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National Power System 

Expansion Plan

2011 - 2030

Final Report

Main Report

504760-01-MR

2011

This document contains the expression of the professional opinion of SNC-Lavalin Inc. (“SLI”) as to the matters set out herein, using its professional judgment and reasonable care.  It is to be read in the context of the agreement dated October 4, 2010 (the “Agreement”) between SLI and National Thermal Despatch Company (the “Client”), and the methodology, procedures and techniques used, SLI’s assumptions, and the circumstances and constraints under which its mandate was performed.  This document is written solely for the purpose stated in the Agreement, and for the sole and exclusive benefit of the Client, whose remedies are limited to those set out in the Agreement. This document is meant to be read as a whole, and sections or parts thereof should thus not be read or relied upon out of context. 

Unless expressly stated otherwise, assumptions, data and information supplied by, or gathered from other sources (including the Client, other consultants, testing laboratories and equipment suppliers, etc.) upon which SLI’s opinion as set out herein is based has not been verified by SLI; SLI makes no representation as to its accuracy and disclaims all liability with respect thereto.  

504760                                                        © 2011 SNC-Lavalin Inc.All rights reserved                                             T&D Division 

                                                                                                  Confidential

LIST OF ABBREVIATIONS AND DEFINITIONS Abbreviations: 

      ADB              Asian Development Bank  

AEDB        Alternative Energy Development Board  cct-km        Circuit-kilometre  

Consultant SNC-Lavalin, Transmission and Distribution Group 

                                                                                 i                                                                             

                                                                                ii                                                                             

TABLE OF CONTENTS 

1INTRODUCTION ...................................................................................................1-1

1.1 Objective of the National Power Systems Expansion Plan .................................1-1

    1.2      Scope of Work ............................................................................................................1-2

    1.3       Structure of the report ................................................................................................1-2

2 POWER SECTOR ENVIRONMENT IN PAKISTAN .....................................................2-1

    2.1      Economy and the Energy Sector ................................................................................2-1

    2.2      Characteristics of the Energy Sector in Pakistan ........................................................2-1

    2.3       The Current Power System ........................................................................................2-2

3 SYSTEM PLANNING CRITERIA ..............................................................................3-1

    3.1       Introduction ................................................................................................................3-1

    3.2      Economic and Financial Parameters ..........................................................................3-1

    3.3       Generation Planning Criteria ......................................................................................3-2

    3.4      Environmental Criteria ................................................................................................3-3

3.4.1Thermal Generation Projects ...................................................................................3-3

3.4.2Hydroelectric  Generation Projects ...........................................................................3-4

3.4.3Transmission Projects ..............................................................................................3-5

    3.5      Transmission Planning Criteria ...................................................................................3-6

3.5.1Contingency Conditions ...........................................................................................3-6

3.5.2Component Loading .................................................................................................3-6

3.5.3Voltage .....................................................................................................................3-7

    3.6      Distribution Planning Criteria ......................................................................................3-7

3.6.1System Voltage Criteria ...........................................................................................3-7

3.6.2Equipment Thermal Loading Criteria ........................................................................3-8

    3.7      Financial Planning Criteria ..........................................................................................3-8

4 POWER DEMAND..................................................................................................4-1

    4.1       Introduction ................................................................................................................4-1

    4.2      Issues related to the load forecast ..............................................................................4-1

4.2.1Load Shedding .........................................................................................................4-1

4.2.2Transmission and Distribution Losses ......................................................................4-2

4.2.3System Load Factor .................................................................................................4-4

4.2.4Load Characteristics ................................................................................................4-6

4.2.5Demand Side Management ......................................................................................4-7

    4.3      Approach and Methodology ........................................................................................4-7

4.3.1General ....................................................................................................................4-7

4.3.2Medium-Term Forecast ............................................................................................4-8

4.3.3Long Term Forecast .................................................................................................4-9

    4.4      Key Independent Variables ......................................................................................4 -10

4.4.1Projections of Independent Variables .....................................................................4 -11

    4.5      Load Forecasts ........................................................................................................ 4-13

4.5.1Sales Forecasts .................................................................................................... 4-13

4.5.2Generation Forecast .............................................................................................. 4-15

4.5.3Forecast with DSM ................................................................................................. 4-16

4.5.4Summary of Forecasts ...........................................................................................4 -19

5 FUEL SUPPLY, PORT HANDLING AND FUEL PRICING ............................................5-1

    5.1       Introduction ................................................................................................................5-1

    5.2       Fuel Supply ................................................................................................................5-1

5.2.1Natural Gas ..............................................................................................................5-1

5.2.2Fuel Oil ....................................................................................................................5-5

5.2.3Coal .........................................................................................................................5-6

    5.3      Capacity of Ports and Fuel Logistics ...........................................................................5-7

    5.4       Pricing of Fuels ..........................................................................................................5-9

6 GENERATION PLANNING .......................................................................................6-1

    6.1       Introduction ................................................................................................................6-1

    6.2       Strategic Considerations ............................................................................................6-1

    6.3      Approach and Methodology ........................................................................................6-3

    6.4       Planning Basis ...........................................................................................................6-3

    6.5       Existing and Committed Units.....................................................................................6-7

6.5.1Existing Hydro Plants ...............................................................................................6-8

    6.6      Existing Thermal Plants ..............................................................................................6-8

    6.7      New Generation Options .......................................................................................... 6-15

6.7.1Hydro Projects and Screening ................................................................................6 -15

6.7.2New Thermal Options ............................................................................................ 6-32

6.7.3Other Generation Options ...................................................................................... 6-40

    6.8     Generation Expansion Plans .................................................................................... 6-43

6.8.1Short-Term Plans ................................................................................................... 6-43

6.8.2Development of the Base Case ..............................................................................6 -44

6.8.3Alternative Development Scenarios ....................................................................... 6-54

    6.9     Summary of Reliability Levels and System Expansion Costs....................................6 -57

6.10Sensitivity Tests ....................................................................................................... 6-60

6.11Summary, Conclusions and Recommendations .......................................................6 -63

7 TRANSMISSION PLANNING ....................................................................................7-1

    7.1       Introduction ................................................................................................................7-1

7.2Planning and Performance Criteria .............................................................................7-1

7.3Typical Characteristics of NTDC Longitudinal Network ...............................................7-2

    7.4      Approach and Methodology ........................................................................................7-4

7.4.1Inputs .......................................................................................................................7-4

7.4.2Development of Study Cases ...................................................................................7-5

    7.5      Transmission Expansion upto 2016-17 .......................................................................7-7

    7.6      Transmission Expansion from 2017-2020 ..................................................................7-9

    7.7     Transmission Expansion from 2021-2030 ................................................................7 -12

    7.8      Short Circuit Analysis ...............................................................................................7 -17

7.9Stability Studies ........................................................................................................7 -17

7.10Recommendations .................................................................................................. 7-18

7.11Cost Estimate of Transmission Expansion................................................................ 7-20

7.11.1Total requirement (BOQs) between 2017 and 2030 ...............................................7 -20

7.11.2Total Cost .............................................................................................................. 7-21

7.12Transmission Network in 2030 .................................................................................7 -21

8 EXPANSION PLAN FOR DISCO TRANSMISSION .....................................................8-1

    8.1       Objectives ..................................................................................................................8-1

8.2Study Cases ...............................................................................................................8-2

8.3Input Data...................................................................................................................8-2

8.4Load Forecast ............................................................................................................8-2

8.5Secondary Transmission Planning Criteria .................................................................8-4

    8.6      Methodology ...............................................................................................................8-5

    8.7       Study Results .............................................................................................................8-6

8.7.1Load Flow Study Results..........................................................................................8-6

8.7.2Short Circuit Study for Year-2020 Base Case ..........................................................8-7

    8.8       Cost Estimate .............................................................................................................8-7

8.8.1Unit Cost ..................................................................................................................8-7

8.8.2Cost of Reinforcements ............................................................................................8-8

    8.9      Recommendations ................................................................................................... 8-10

9   FINANCIAL PLAN .................................................................................................9-1

9.1Introduction ................................................................................................................9-1

    9.2     Overview of the Financial Performance of the Pakistan Power Sector in 2010 ...........9-1

9.5.1    Cost of Generation ...................................................................................................9-2

9.2.2Cost of Transmission ...............................................................................................9-2

9.2.3    Cost of DISCOs .......................................................................................................9-2

9.2.4    Summary of PEPCO Costs ......................................................................................9-3

9.2.5    Financial Performance of KESC ...............................................................................9-3

9.3Methodology for Developing Financial Plan ................................................................9-4

9.4Data Input  and Assumptions for Developing Financial Plan .......................................9-6

9.6       Cost Estimates for the Generation, Transmission and Distribution Plans ...................9-8

9.6.1    Investment and Operational Cost Estimates for the Generation Plan .......................9-8

9.6.2    Cost Estimates of the Transmission Plan .................................................................9-8

9.6.3    Cost Estimates for the Distribution System ..............................................................9-9

9.7       Financial Projections and Results ...............................................................................9-9

9.7.1    Investments and Operating Costs of the Generation and Transmission Plans ....... 9-10

9.6.2Annual Investment for Generation and Transmission Plans ................................... 9-11

9.6.3Estimation of Unit Generation Cost from Hydro and Thermal Generation. .............. 9-14

9.6.4Estimation of Unit Transmission Cost .................................................................... 9-16

9.6.5Unit Cost of Power  to the DISCOs and to KESC ...................................................9 -16

9.8       Supply Cost of Power and Impact on the Customer Tariffs ....................................... 9-17

9.9       Analyses of Results and Concluding Remarks .........................................................9 -19

LIST OF TABLES 

Table 4-8Projected Real GDP Growth Rates – Normal Case ....................................... 4-12

Table 4-9Category-wise Sales (GWh) Forecast ............................................................ 4-14

Table 4-10Consumption Patterns ................................................................................. 4-15

Table 4-11Load Forecast – Normal .............................................................................. 4-17

Table 4-12Load Forecast with Demand Side Management .......................................... 4-18

Table 4-13Summary of Forecasts for Selected Years for Country ................................ 4-19

Table 4-14Summary of Forecasts ................................................................................. 4-20

Table 6-6Existing Generation Capacity of PEPCO System ............................................. 6-9T

able 6-7Existing Units – KESC System ...................................................................... 6-11

Table 6-8Retirement Schedule of Existing Plants ......................................................... 6-12

Table 6-9Lead Time of Future Hydro Projects by Category .......................................... 6-18

Table 6-10Identified Future Hydro Projects .................................................................. 6-18

Costs 2011-2030) ................................................................................................... 9-11

Table 9-6Annual Capital Investments and Financing Requirements (million USD) ....... 9-12

Table 9-7Total Debt and Equity Financing for Different Periods (billion USD) ............... 9-14

Table 9-8Cost of Power from Hydro Plants for Selected Years ..................................... 9-15

Table 9-9Cost of Power from Thermal Plants for Selected Years ................................. 9-15

Table 9-10Unit Supply Cost for Selling to Discos and KESC (¢/kWh) ........................... 9-17

Table 9-11Total Cost of Supply from the DISCOs and Comparison to the Existing Tariffs 

Escalated at 2 % (¢/kWh) ........................................................................................ 9-18

Table 9-12Comparison of Unit Cost of Supply and End Tariffs ..................................... 9-18

1     INTRODUCTION 

1.1    Objective of the National Power Systems Expansion Plan 

As at 31 December 2010 the total installed capacity of Pakistan was around 21,420 MW. However rapid load growth and inadequate generation addition to the power pool created a gap between supply and demand resulting in significant load shedding. 

Table 1-1 below shows the level of load shedding in recent years from no load-shedding in 1993 to almost 23% in 2010. 

                                            Table 1-1        Load Shedding Levels 

In order to address this gap the National Transmission and Despatch Company (NTDC) of Pakistan identified the need to develop a National Power System Expansion Plan (NPSEP). The objective is to provide a plan for the development of hydroelectric, thermal, thermal nuclear and renewable energy resources to meet the expected load up to the year 2030. Given the chronic and ever increasing power shortage, the need for an expansion plan was urgent and thus only six months were allotted to prepare this revised plan.  This plan was prepared during the period from December 1, 2010 through May 31, 2011.  

504760-01-MR                                                  1-1                                                    Main Report 

1.2     Scope of Work 

The scope of the NPSEP was to determine new generation facilities and transmission reinforcements required to meet future load growth using the latest available data. Based on a review of the load forecast (prepared by NTDC and reviewed by SNC-Lavalin), a least cost generation expansion plan was prepared taking into consideration government policies, environmental considerations and fuel constraints. An indicative transmission plan to evacuate power was developed using the generation expansion plan to 2030 and the network reinforcement requirements for the DISCOs in 2020. These generation and transmission plans were the key inputs in developing the financial plan and the annual revenue requirements to build and operate the system. The investments required by each DISCO to effectively reduce losses and optimize their systems were also calculated but they do not form a part of the overall investment requirements appearing in the NPSEP. They are provided as information to the DISCOs for their respective tariff preparation. 

1.3     Structure of the report 

The sections of the NPSEP report are as follows: 

• Executive Summary 
• Main Report (This Volume) 
• Annexure 1: Fuel Supply, Port Handling and Fuel Pricing 
• Annexure 2: Generation Plan 
• Annexure 3: Transmission Plan 
• Annexure 4: Distribution Plan 
• Annexure 5: Financial Plan 

504760-01-MR                                                  1-2                                                    Main Report 

2     POWER SECTOR ENVIRONMENT IN PAKISTAN 

2.1    Economy and the Energy Sector 

Pakistan’s economy grew by 4.1% on an inflation adjusted basis in 2009-10 after a growth of 1.2% in 2008-09.  On a per section basis the industrial output grew by 4.9%, the Services sector grew by 4.4% while the Agriculture sector grew by 2%. Foreign Direct Investment (FDI) declined by 0.6% after a 5.5% increase in 2008-09. With large part of the decline in FDI was attributed to the Energy Sector and to Large Scale Manufacturing.  FDI accounts for about 20% of gross fixed investment in the country. 

Electricity and Gas Distribution was 3.9% of GDP in 1999-2000, which declined to 2% in 2009-10. Over the last six years, the GDP has varied from a high of 9% in 2004-05 to a low of 1.2% in 2008-09. For the same period, growth in the Electricity and Gas Distribution component of GDP has varied from a low of 26.6% in 2005-06 to a high of 30.8 in 2008-09 to. According to the Economic Survey 2010, the energy crisis is estimated to have reduced the overall GDP growth by about 2 % in 2009-10. 

The total energy consumption declined by 5.2% in 2009 with electricity consumption in the industrial sector falling by 6.5% in 2009, and that of natural gas in the industrial sector falling by 2.6%. 

2.2    Characteristics of the Energy Sector in Pakistan 

Pakistan’s energy supply includes natural gas, oil, coal and electriicy. The primary energy supplies by source in 2008-09 were: 

                                                    Source:Energy Yearbook 2009

The final energy consumption by source in 2008-09 was: 

                                                    Source:Energy Yearbook 2009 

Pakistan has a good indigenous resource base of natural gas (28.3 TCF as of January 2010), hydroelectric potential and the huge reserves of coal at Tharparkar. Due to a variety of reasons, there has been a lack of progress in development of all these resources with a consequent increase in the use of imported oil at a huge import cost.   

2.3     The Current Power System 

Since independence, Pakistan’s power sector consisted of two vertically integrated utilities – WAPDA and Karachi Electricity Supply Company (KESC). The power sector has been restructured starting with the creation of Pakistan Electric Power Company (PEPCO) in 1998. Water and Power Development Authority (WAPDA) retained ownership of 14 hydro plants while WAPDA’s thermal plants have been distributed to three Generation Companies (GENCOs). National Transmiission and Despatch Company (NTDC) acts as the bulk supplier of electricity and is responsible for the entire transmission network. The electricity is transmitted to ten Distribution Companies (DISCOs) for onward distribution to end consumers. The existing arrangment is shown below: 

Kotri Thermal Power Station

GENCO-II:  Guddu Thermal Power Station

Quetta Thermal Power Station

GENCO-III: Muzaffargarh Power Station Faisalabad Thermal Power Station

Multan Thermal Power Station

Shahdara Power Plant

GENCO-IV: Lakhra Coal Power Plant 

LESCO: Lahore Electric Supply Company

GEPCO:  Gujranwala Electric Power Company

FESCO:   Faisalabad Electric SupplyCompany IESCO:    Islamabad Electric Supply Company

MEPCO: Multan Electric Power Company

PESCO:   Peshawar Electric Supply Company 

HESCO:  Hyderabad Electric Supply Company

QESCO:  Quetta Electric Supply Company

TESCO:   Tribal Electric Supply Company

SEPCO:   Sukkur Electric Power Company

    Note: KESC is an integrated utility with generation, transmission and distribution. It purchases power from both NTDC and IPPs.       

Pakistan’s power system is severely strained with widespread and unannounced loadshedding. In recent years, the lower availability of hydro resources and of gas for power has resulted in the increased use of imported and expensive oil, which has added to the financial strain of the sector. The gap between the cost of producing power and revenue derived from its sale has also widened. From 2003 to 2007, despite rising fuel costs GoP chose not to increase consumer tariffs. Compounding the problem is the cumulative effect of the inter – corporate circular debt in the energy supply chain. 

In the late 1980s and early 1990s, Pakistan’s total installed capacity remained at about 9,400 MW. The installed capacity of the country in 2010 was 18,892 MW  of which 30% was hydro. The total electricity generation in 2010 was 10,544 GWh, the breakdown by source was: 

                                                 Source: Power System Statistics 2010 35^thedition 

The power sector is a major consumer of petroleum products and natural gas. Of the total petroleum products consumed in Pakistan in 2008-09 of 17.9 million tonnes, 42.3% was consumed by the power sector. The corresponding percentage in 2003-04 was 20.4%, demonstrating the drastic increase in the use of petroleum products for power generation. The percentage share of total natural gas consumption for power generation was 44.7% in 2003-04 but this has declined to 31.8% in 2008-09, reflecting the Government of Pakistan’s (GoP) policy of restricted allocation of gas for power generation.   

The length of transmission lines in the country as of June 2009 was 5,078 ckM of 500-kV and 7,325 of 220-kV lines. Improvement of the transmission system to ensure system integrity and smooth supply to the consumers, is an ongoing process. Village electrification is an important part of Pakistan’s power policy. In 2008-2009 9,868 villages were electrified.  

The GoP through the Alternative Energy Development Board (AEDB) is encouraging the development of alternative and renewable energy projects. Several Letters of Intent have been signed for wind power projects, and active efforts are being made to encourage biodiesel, biomass, waste-to-energy, mini hydro and solar technologies.  

GoP policy is to reduce dependence on imported oil and the development of indigenous resources. This can only be achieved by development of economic hydro resources, drilling for more gas and by following a determined approach to exploit the huge coal reserves at Tharparkar. 

Sources: 

• Economic Survey of Pakistan 2009-10 
• Pakistan Energy Yearbook 2009 
• Electricity Marketing Data, 35^thIssue, Planning Dept, NTDC

3     SYSTEM PLANNING CRITERIA 

3.1     Introduction

The key assumptions as well as the technical and economic criteria used in the development and analysis of the National Power System Expansion (NPSEP) are presented in this section. 

3.2     Economic and Financial Parameters 

The following economic and financial parameters were considered in the development of the plan: 

Study Period and Reference Year for Discounting

The study horizon period for development of the NPSEP is 2011-12 to 2029-30, inclusive, a 19-year period. The reference year used for present worth costing was 2011-12. The costs including capital costs, operating costs and fuel prices have been estimated at 2010 price levels. 

Discount rate

The discount rate was used to bring all the future costs to one reference time point using the time value of money concept. The basic real discount rate considered in the study is 10%. Additional discount rates of 8% and 12% were also considered for the sensitivity analysis. 

Exchange Rate

The exchange rate used in this study is Rs. 80/US$, which was the average exchange rate for 2010. 

Cost of un-served energy

Un-served energy represents the failure to meet the energy demand of existing and new customers. It takes the form of either planned or unplanned supply curtailments. The cost of un-served energy varies on a sector-by-sector basis. In this study, the target levels of system reliability have been established so that the levels of un-served energy for the different scenarios analyzed would be similar. The cost of un-served energy has been approximated as the cost of generation from the most expensive unit in the system. This approach most likely understates the cost of un-served energy. However, since the primary purpose of the analysis was the comparison of alternative expansion scenarios which by definition would have similar levels of un-served energy, this approximation was deemed appropriate. 

Fuel Pricing

Given the shortage of supply of indigenous fuels, it is likely that petroleum products and gas would need to be imported for future power plants. Therefore the pricing for petroleum products and gas have been based on their imported equivalents. 

Although Thar coal would be produced domestically, currently there is insufficient information to base firm mining costs on. Therefore Thar coal has been priced such that the cost of power generated at Thar using Thar coal would be equivalent to the cost of power from a coastal plant using imported coal.  

3.3    Generation Planning Criteria 

Reliability Criteria and Reserve

Reliability criterion to decide the capacity addition requirement for every year over the planning horizon is the basis for developing the generation plan. The reliability criterion determines the timing of new capacity additions required in the future. Currently the reliability of the system is not the primary concern for Pakistan as the country is experiencing huge shortages of power. NTDC is therefore planning to add capacity to meet demand requirements at a lower but acceptable reliability level. There are two reliability indices which are commonly used for the development of generation expansion plans.  These indices are as follows: 

• Loss of Load Probability (LOLP):  LOLP is the risk associated with having insufficient generation to meet the forecasted load demand.  It is generally expressed in hours/year; 
• Expected Un-served Energy (EUE):  EUE is the measure of energy that is not supplied in expected terms over the year. It is generally expressed in GWh per year. 

Since the country is experiencing huge shortages of power and most of the new capacity will be available only after 2014-15 taking into account the lead time of at least three years for development of new power plants, it is not realistic to expect that the country could meet the pre-determined reliability target of 1% of LOLP (equivalent to a loss of load expectation of 87.6 hours/year) in a short time period. A further constraint for Pakistan to meet its reliability target is the limited funding available for power system expansion. A significant amount of investment is required for both generation and transmission systems expansion as well as for the strengthening and expansion of the distribution networks. 

The primary index used for reliability criterion in this study is Loss of Load Probability (LOLP). The reliability criterion for this study was applied in a staged manner, as follows: 

• Up to 2018-19: LOLP < 10% (equivalent to a loss of load expectation of 876 hours/year); 
• 2019-20: LOLP < 5% (equivalent to a loss of load expectation of 438 hours/year); 
• 2020-21 onwards: LOLP < 1% (87.6 hours/year). 

Load Profile  

Analysing annual hourly load profiles is an important aspect of generation planning to capture the hourly and seasonal variations in the load. The hourly load data is used to construct monthly load duration curves which are key inputs to generation planning for planning the future years. The normal assumption is that the future monthly/seasonal load variations would be similar to the past ones. However, the historical load duration curves for the recent years could not be directly used for the future years since these curves were based on supply availability. Therefore it was necessary to have information on unrestricted monthly load patterns and hourly load profiles to represent the future years. After reviewing historical data and previous studies, 2003-04 was selected as it had no planned load shedding and very little adjustment was required for unexpected load shedding. 

3.4     Environmental Criteria 

The development of the NPSEP has been based on the environmental criteria and standards as currently exist in Pakistan.  

3.4.1      Thermal Generation Projects 

The emission requirements for thermal power plants have been based on the National Environmental Quality Standards (NEQS) that include the following specific standards: 

• National Environmental Quality Standards for Municipal and Liquid Industrial Effluents; 
• National Environmental Quality Standards for Industrial Gaseous Emissions;  
• National Environmental Quality Standards for Sulphur Dioxide and Nitrogen Oxide Ambient Air Requirements. 

The emission requirements pertain to particulates, Nitrogen Oxides, Sulphur Dioxide, Liquid Effluents and Solid Wastes. 

The NPSEP has included in its cost estimates water treatment equipment for all plants, FGD equipment for coal fired plants and has used Low Sulphur Fuel Oil for oil fired plants. 

3.4.2      Hydroelectric  Generation Projects 

The range of adverse environmental and related social impacts that can result from hydroelectric dams is remarkably diverse. While some impacts occur only during construction, the most important impacts usually are due to the long-term existence and operation of the dam and reservoir. Other significant impacts can result from complementary civil works such as access roads, power transmission lines, and quarries and borrow pits. Adverse environmental and social impacts associated with dams and reservoirs include flooding of natural habitats, loss of terrestrial wildlife, involuntary displacement and deterioration of water quality. Twenty seven hydroelectric projects have been considered in the NPSEP.  Of these, eighteen projects have undergone thorough feasibility studies. Eleven of the eighteen projects have feasibility studies which are more than three years old and need updating. Nine projects are at initial stages and their feasibility studies have not yet started.  

For those projects that have been studied to feasibility level and for which environmental cost estimates were available, these cost estimates were escalated to 2010 price levels. For those projects which have not been studied to feasibility level and for which environmental cost estimates were not available, an approximation was made. The approximation was based on information for those projects for which the required information was available. The environmental cost as a percentage of total project cost averaged over all those projects for which information was available, was applied to those projects for which the total project cost was available but the environment cost was not. 

3.4.3      Transmission Projects 

Environmental criteria at the planning level are applied at the transmission line route selection. 

In Pakistan, there is an identification of protected areas designated for the protection of endangered species, habitats, ecosystems, archaeological sites, monuments, buildings, and other cultural heritage sites. These areas can be broadly categorized into two groups as follows: 

• Ecosystems;
• Archaeological and Cultural sites.  

The following environmental criterion has been adopted to avoid environmentally sensitive areas and major resettlement issues for the proposed transmission line routes. These are mainly based on physical, ecological and socio-economic features: 

• Avoidance of heavily populated areas/towns; 
• Avoidance of indigenous or tribal settlements; 
• Avoidance of cultural, religious and historical buildings; 
• Minimum disturbance to the natural habitats of flora and fauna; 
• Avoidance of major birds migratory routes; 
• Avoidance of wildlife sanctuaries, National Parks, and Game Reserves;  
• Avoidance of potentially security vulnerable areas; 
• Appropriate distance from the sensitive receptors (for instance, minimum 500m); 
• Avoidance of large water bodies like lakes, rivers or streams; and, 
• Avoidance of airports, railway tracks and other similar structures and facilities. 

3.5    Transmission Planning Criteria 

The planning criteria used in the transmission planning studies were taken from the Planning Code section of the NTDC Grid Code (June, 2005). 

3.5.1      Contingency Conditions 

Planning for steady-state, were based on (N-0) and (N-1) contingency conditions.  There were two base-case scenarios for each year; Summer-peak (High Water) and Winter-offpeak (Low Water). 

Single contingency cases (N-1) were studied for each base case scenario. For the  planning studies, an outage was defined as any one of the following: 

• Outage of a 500/220/132 kV transmission circuit;
• Outage of a generator step-up transformer; 
• Outage of a grid station transformer; 
• Outage of a substation 500 kV or 220 kV bus section; 
• Outage of a 500 kV shunt reactor. 

Planning for dynamic performance (transient stability) was  based on the occurrence of each of the following contingencies: 

• Permanent three-phase fault on any 500/220 kV line and subsequent outage of the associated transmission line; 
• Failure of a circuit breaker to clear a fault (“stuck breaker” condition) in 5 cycles, with back-up clearing in 9 cycles after fault initiation. 

3.5.2      Component Loading 

Under normal operating conditions (N-0), all transmission lines and transformers were loaded below their Normal Continuous Maximum ratings.  Under contingency conditions (N-1), all transmission lines and transformers were loaded below their Emergency ratings. 

3.5.3      Voltage 

For steady-state conditions, all bus voltages shall be within the following ranges: 

• Under normal operating conditions (N-0) ± 5% of nominal system voltage 
• Under contingency conditions (N-1)± 10% of nominal system voltage 

3.6    Distribution Planning Criteria 

The planning of the secondary transmission system considered the operation of a power system under two possible situations as listed below: 

• Normal operating conditions (N-0):the secondary transmission system (66-132 kV) infrastructure was entirely available (no equipment has been forced out of service); 
• Contingency operating conditions (N-1):one of the secondary transmission system equipment (line or transformer) was out of service. In this study, only the outage of transmission lines rated at 132 kV (or 66 kV) within each DISCO was considered. 

For each of these operating conditions, the following criteria were applied to the analyses. 

3.6.1      System Voltage Criteria 

The acceptable voltage range for operating the system based on factors such as equipment limitations and motor operation under normal and contingency conditions were as follows: 

It is important to note that from an operational standpoint, healthy systems usually target a voltage close to 1.0 pu at 132 kV (or 66 kV) voltage levels. 

3.6.2      Equipment Thermal Loading Criteria 

The secondary transmission system was planned to allow all transmission lines and equipment to operate within the following limits for the following defined conditions: 

In line with NTDC requirements the line loading under contingency conditions (N-1 analysis) were based on the normal rating (Rating A). 

3.7     Financial Planning Criteria 

The overall objective for the financial plan was to determine the financial implications for the power sector over the course of the 20 year period (2010-11 to 2029-30) and to determine the level of impact on the average tariff.  

The sales and load forecast and the system expansion plan comprising the generation and transmission expansion plans were the key inputs to the financial plan. The system expansion plan was the least cost economic plan to serve Pakistan’s load growth and current load over the period 2010-11 to 2029-30.  

The costs underlying the generation expansion plan were economic costs and were in real terms (i.e. constant price levels excluding financing costs, taxes). For the financial plan, it was necessary to turn these economic costs of the generation and transmission into financial costs, taking into account taxes, depreciation, financing charges and profits. This involved determining the financing associated with the capital expenditures and then calculating the financial costs associated with the assets by including interest costs, depreciation, operation costs including fuel and maintenance costs, taxes, and appropriate returns to the investors. Since the financial plan was carried out in nominal terms, an inflationary component was also be added to the capital, and operating costs.  

The financial plan indicates the overall investment and financing required for the generation and transmission expansion and the overall impact on the cost of power to the DISCOs and to KESC. 

The analysis determined the tariff at the generation and transmission level required to recover the financial costs of the investments in the power sector in generation and transmission. 

The key criteria used in the financial analysis are summarized in Table 3-1 below. Table 3-1      Key Financial Criteria 

4     POWER DEMAND 

4.1     Introduction 

Load forecasting entails the prediction of the future level of demand, and provides the basis for future supply side and demand side planning. Generation planning requires a load forecast for the country as a whole, while transmission and distribution planning requires more load–level and geographic detail to determine the location, timing and loading of individual lines, substations and transformation facilities. Geographic load detail is also a factor in the determination of the location of generation plants since it is generally desirable to locate generation sources close to the load centres. 

This analysis was based on a complete review of historical data which included electricity consumption, electricity tariffs, Gross Domestic Product (GDP), population etc., covering the period 1970 to 2010.The forecast horizon is up to the year 2035.   

Four forecast scenarios have been developed: the Base or Normal Case, the Low Case, the High Case and the Base Case with Demand Side Management.  The forecast was prepared by NTDC and is summarized in the following sections. 

4.2    Issues related to the load forecast 

4.2.1     Load Shedding 

There has been planned load shedding in the country since 2004 due to shortages of generation and reliability of the transmission and distribution systems. Statistics available on load shedding since 2004 are shown in Table 4-1. 

                                 Table 4-1        History of Planned Load Shedding 

Source: Power System Statistics 35^thedition and National Power Control Centre 

The national demand combines sales by the PEPCO system and the sales by KESC. 

Load shedding as a percentage of national demand reached an alarming 22.9% by 2010. In the derivation of the load forecast, the historical data was adjusted to take into account the load shedding.  The forecast used the estimate of unconstrained demand as its starting point and therefore reflects the true energy and demand requirements of the customers.  

4.2.2     Transmission and Distribution Losses 

During the 1980’s WAPDA introduced programs to reduce power and energy losses throughout its system, the implementation of which proved to be quite fruitful. After a few years of declining losses, system losses particularly distribution losses have risen again, thereby suggesting the need for remedial loss reduction efforts. Table 4-2 shows a summary of energy generation, sale, and auxiliary, transmission and distribution losses since 2000 for PEPCO. 

              Table 4-2        Historical Energy Generation, Sale and Losses – PEPCO 

Source:Electricity Demand Forecast Period 2011-2035 by Planning Power NTDC.

Note:  Gross Generation of PEPCO includes Export to KESC but auxiliary consumption of IPPs is not included

The figures indicate that PEPCO distribution losses dropped from 17.4% to 14.8% of gross generation over the period 2000 to 2006. However, these increased to 17.3% in one year i.e. in 2007, and remained around that level from 2007 to 2010. 

A summary of energy generation, sale, and losses since 2000 for the Karachi Electric Supply Company (KESC) is shown in Table 4-3. 

                Table 4-3        Historical Energy Generation, Sale and Losses - KESC 

Source:Electricity Demand Forecast Period 2011-2035 by Planning Power NTDC and information from KESC. 

KESC distribution losses were significantly high and range from 27.1 to 37.6% (almost double the PEPCO system losses) during the past 10 years.  

4.2.3     System Load Factor 

The annual load factor gives the average value of the load to supply ratios as it changes over the year. The load depends mainly upon the electricity demand changes with time of day use, temperature, and season. It also depends on the composition of customer categories.  

The load factors for the PEPCO system for the period 2005-2010 are given in Table 4-4. 

                                    Table 4-4        PEPCO Load Factor (Historical) 

Source:Electricity Demand Forecast Period 2011-2035 by Planning Power NTDC.Note:   IPPs auxiliary consumptions are not included. 

These figures have been calculated on the basis of computed energy generation and computed peak demand for the two systems i.e. taking into account load management and excluding import/export of electricity between PEPCO and KESC. The load factors for the KESC System for the period 2005-2010 are shown in Table 4-5. 

                                     Table 4-5        KESC Load Factor (Historical) 

Source:Electricity Demand Forecast Period 2011-2035 by Planning Power NTDC & KESC letters 

The load factors for both PEPCO and KESC systems have been increasing in recent years, with the KESC system load factor significantly higher than that of PEPCO. 

4.2.4     Load Characteristics 

The electricity consumption pattern by sector over the last four decades is shown in Table 4-6. 

                                   Table 4-6        Electricity Consumption Pattern 

Source:Electricity Demand Forecast Period 2011-2035 by Planning Power NTDC  

The domestic share of total electricity consumption is increasing over time, while that of the industrial sector is declining. As incomes are rising, the domestic sector consumption is increasing. However, the trend of decreasing industrial consumption is likely to have a negative impact on economic growth and therefore needs to be arrested. 

Tariffs

The real price of electricity is, conceptually, very important in deriving an econometric forecast of electricity sales.  Economic theory suggests that for any increase in the real price of a commodity there will be a corresponding decrease in its consumption.  The link between the two is price elasticity.  In Pakistan, as in many other jurisdictions, the derivation of the price elasticity of sales of energy is difficult for two reasons: 

• The real price increases tend to be small and widely dispersed in time; 
• From a pragmatic point of view, electricity is an inelastic product: once a consumer has electric power service, he or she is reluctant to go to alternative energy sources (from electric light to candles or kerosene lamps, electric motors to gas-powered motors or domestic beasts of burden, etc.). 

The power sector has been chronically short of funds and will rely to a certain extent on tariffs to fund future expansion plans. Modest real increases in price have been used in the regression analysis based on the growth in real prices over the past years.   

Electrification

Pakistan has been following a rural electrification program to enable the rural population to share the benefits of development. In 1980 30% of households were electrified which increased to 70% in 1998 as reported in the respective census reports.  

4.2.5     Demand Side Management 

Little formal work has been done on Demand Side Management (DSM) since the 1998 load forecast update study.  As the benefits identified in this and other studies are assumed to have been implemented by 2010, the current long-term forecast assumes that while there may be no energy benefit in terms of either sales or generation, there could be a reduction in peak demand.  

It is recognized that in a country with a scarcity of power, DSM is a crucial element in planning to meet the load.  Such programs should be fostered and their results taken into account as programs are implemented.   

4.3    Approach and Methodology 

4.3.1      General 

Two forecasts were prepared by the NTDC team a medium-term forecast up to the year 2020 for the PEPCO system and a long-term forecast up to 2035 for both the PEPCO system and the KESC system.  The KESC system accounts for approximately 10% of the country’s load. 

The medium term forecast covers PEPCO service areas by category: domestic, commercial, industrial, agricultural, traction, street lighting and bulk sales.  This includes all the DISCOs except KESC. 

The long-term forecast was carried out on a country-wide basis; this was then separated into the PEPCO system and the KESC system. The medium term forecast contains a breakdown by grid-station but the long-term forecast does not. 

For purposes of the National Power System Expansion Plan (NPSEP), it was appropriate to consider the energy and capacity requirements of the country as a whole. The point of the forecast was to estimate the amount of power required by the current and prospective customers. The forecast therefore presented the unconstrained needs of the country. 

The load forecast was used for two activities in the development of the NPSEP.  The generation plan had to determine the least cost expansion plan that would meet the load forecast with an appropriate degree of reliability. The transmission plan was required to provide the least cost transmission plan that would transmit the power from the generation sources to the load centers. The forecast was therefore segregated by major load centre, defined as each DISCO and, within the DISCO, by each 132/11 kV grid station. 

4.3.2      Medium-Term Forecast 

The medium-term forecast followed a bottom-up approach. It started with the data of units billed by each category for each feeder within each DISCO, adjusted for load shedding.  The medium-term forecast gave the peak demand for each grid station at the 132/11 kV level. This forecast gave the estimated consumption for each DISCO but did not include KESC. 

This forecast estimated the value of energy and demand for the PEPCO system (KESC did not provide the required information for the development of this forecast for its system). Load factors were estimated for each category for each DISCO.  The categories included were Domestic (42% of total sales in 2010), Industrial (35%), Agriculture (12%), Commercial (7%) and others (traction, street lighting and bulk - 4%). 

The forecast was based on a survey of the DISCOs who provided their forecast by customer category and by area or sub-area. The NTDC Planning Department adjusted the forecast for load shedding and for demand-side management. Load shedding has been a factor in the power sector since the 1980’s but had been virtually eliminated in the early 2000’s.  It has become significant again in 2005 and even more so in 2009. The last DSM study done was about 10 years ago and the current forecast was adjusted to take into account the results of that study. 

The DISCOs provided feeder wise data for units billed for the base year, and data for expected spot loads (e.g. any new industry, housing scheme, commercial plazas and any new village etc.) for the future years.  NTDC provided estimates of future growth from the units billed in the base year. 

4.3.3      Long Term Forecast 

The long-term forecast was done at a national level and included KESC as an integral part of the forecast.  The following were some of the more relevant observations: 

• It was based on historic data 1970 to 2010 and the forecast covered 2011 to 2035; 
• In carrying out multiple regressions, care was taken to ensure that any econometric relationships selected were logical and had a strong statistical correlation; 
• The software E-views was used to assist with the derivation of econometric relationships;
• The methodology used was first presented in the National Power Plan Pakistan in 

1994. This approach has, in general terms, been retained;  

• The relationships that were examined are in the following formula: 

Ln(S) = K + C₁* Ln(V₁) + C₂* Ln(V₂) + C₃* Ln(V₃) + etc. 

                    Where:     Ln  = the natural logarithm 

                                    S  = sales in a specific category 

K  = a constant 

V1, V2, V3,etc. are independent variables 

 C1, C2, C3,etc. are coefficients derived from the least squares regression analysis 

• This analysis was applied to the Domestic, Commercial, Industrial and Agricultural categories; 
• The Domestic category included a grouping of the direct sales to PEPCO customers, the direct sales to KESC customers, an estimate of the bulk load that serviced residential households (i.e. as part of housing colonies) as well as an estimate of the unserved domestic load (i.e. a load shedding allowance); 
• The Commercial category included all the same elements; 
• The Industrial load (which included all the captive generation as contained in the records available) was based on the assumption that captive generation was used primarily by industries in the production of their goods and services; 
• Street lighting was taken as a percentage of the sales by domestic and commercial customers; 
• The remainder of the bulk sales was taken as a percentage of the industrial and commercial load; 
• The traction load was extremely small and an allowance for such sales was made by the judgment of the analyst; 
• The regression coefficients derived from the historical analysis of the four “category groups” as mentioned above were applied to projections of the independent variables for each year of the forecast period in order to obtain the forecast for the category for that year; 
• The projections of the independent variables were usually obtained from authoritative sources external to the NTDC; 
• Each of the four categories of country level sales, forecasted above, was then bifurcated into PEPCO and KESC. This was done according to the historical share of each category. 

4.4     Key Independent Variables 

The potential independent variables (demographic and economic) for regression analysis included: 

• Total GDP; 
• GDP by major sector (agriculture, manufacturing, trade, services, etc.); 
• Electricity revenue per kWh sold by customer class (real price); •  Number of customers by consumption category; and 
• Population. 

These regressions were analyzed by province and power system (PEPCO and KESC), and was based on sales by customer category. The best-fit regressions were found to be based on a logarithmic relationship between the variables. 

The relationships selected for the forecasts were: 

• Domestic sales are related to Total GDP, Real Electricity Price and Domestic Sales Lagged (-1) and a dummy variable; 
• Commercial sales are related to Commercial GDP, Real Electricity Price Lagged (-2) and Commercial Sales Lagged (-3);  
• Industrial sales are related to Total GDP, Real Electricity Price Lagged (-1), and Industrial Sales Lagged (-1) and a dummy variable; and 
• Agricultural sales are related to Agriculture GDP, Real Electricity Price, Agricultural Sales Lagged (-1) and a dummy variable. 

4.4.1     Projections of Independent Variables 

GDP Growth

A review of historical total real GDP growth rates from 1970 to 2010 was carried out in order to assess the reasonableness of the future projections, and to propose the values to extrapolate these projections up to the year 2035. This analysis suggested that the longest continuous period where the growth rate approximated 6.5% was for ten years, and the longterm average for the entire period was 5% per year. These boundaries were used to establish the Low and High Cases for future projections of GDP. For the Base Case GDP growth projections, official projections developed by the GoP Planning Commission were directly adopted.   

These projections are shown in Table 4-7 for the Low, Normal and High scenarios.  

                                                 Table 4-7        GDP Projections 

The detailed GDP forecast by sector for the Normal case is shown in Table 4.8. 

                    Table 4-8        Projected Real GDP Growth Rates – Normal Case 

Source:Electricity Demand Forecast – 2011-2035, NTDC Planning 

Number of Customers

The number of domestic customers was estimated by first projecting the population growth of Pakistan using the most recent historic growth rates. This was converted to the number of households using the size of households based on census data – 6.8 people per household.  This household size was kept constant over the forecast period. This provides an estimate of the future number of domestic customers. 

Electricity Prices

There is a direct relationship between the price of electricity and its consumption. There is also a relationship between the price of electricity and distribution losses. Real changes in future electricity prices will be determined by the capital investment program.  

The power sector has been chronically short of funds and will rely to a certain extent on tariffs to fund future expansion plans. Modest real increases in price have been used in the regression analysis based on the growth in real prices over the past three years.  The rates used were 2.2%, 2.2%, 0.6%, and 3.1% for domestic, commercial, industrial and agriculture sectors respectively for the first 10 years of the forecast. The increases were tapered down to 1.1%, 1.1%, 0.3% and 2.5% for the next 10 years of the forecast. And finally, no real increase has been assumed for the next five years for all sectors.  Higher tariff increases were assured in earlier years as capital investments are expected to be higher in those years. 

4.5    Load Forecasts 

4.5.1      Sales Forecasts 

The NPSEP sales forecasts for PEPCO and KESC by tariff category are shown in Table 4-9. These forecasts are based on the observed 2010 consumption levels and the annual growth rates determined from the growth in the independent variables and the coefficients established in the regression analysis. The average annual growth rate of electricity consumption over the 2010 to 2035 period is 8.05%. Table 4-9 shows that the category of largest growth is the Domestic sector, followed by the Industrial category and then by the Agricultural and Commercial sectors. 

The sectoral consumption pattern in 2010 and in 2035 is shown in Table 4-10. Table 4-10           Consumption Patterns 

Source:Electricity Demand Forecast – 2011-2035, NTDC Planning

The sectoral consumption pattern shows little change over time. The domestic sector will represent close to half of the total electricity consumption in 2035. 

Pakistan’s per capita consumption of electricity was 125 kWh in 1980, this improved to 640 kWh by 2010. It is projected that Pakistan’s per capita consumption of electricity will rise to 2,538 kWh by 2035. This is still very low by international standards.  4.5.2 Generation Forecast 

The NPSEP generation forecast is listed in Table 4-11. 

The generation forecast was derived based on the sales forecast and the estimated power system losses, i.e. distribution losses and transmission losses, and the auxiliary consumption as well as the load factor for PEPCO and KESC system. These are discussed as follows: 

Transmission and Distribution Losses and Auxiliary consumption

      -     PEPCO System 

The present level of PEPCO transmission losses is 5.6% which consists of 3.0% at the 500 and 220 kV level (NTDC losses) and 2.6% at the 132kV level. DISCO”s losses have been gradually reduced from 2.6% in 2010 to 2.5% by the year 2015. NTDC transmission losses have also been gradually reduced from 3.0% in the year 2010 to 2.4% in the year 2015. These have been kept constant for the rest of the forecast period.  

504760-01-MR                                                 4-15                                                   Main Report 

The present level of distribution losses is 14.6%. These losses have been reduced gradually to reach 8% by the year 2019, and have been kept constant up to the year 2035. Auxiliary consumption in the PEPCO system at present is 3.3% and this is kept constant throughout the forecast period.  

      -     KESC System 

The present level of KESC transmission losses (2.5%) is maintained throughout the forecast period. The distribution losses have been reduced gradually from the present 31.1% to reach 23.6% by the year 2015 and are kept constant for the rest of the forecast period. Auxiliary consumption in the KESC system is kept at 3.7% throughout the forecast period.  

Load Factor

The present load factor is 69.3% for the PEPCO system and 85.4% for the KESC system. The average load factor for the PEPCO system for the period 2006 to 2010 is approximately 70%. The average load factor for the last six years for the KESC system is 78%. The computed load factor for both systems combined was gradually reduced to reach a target level of 67% by the year 2035, representing a system that would be free of supply constraints. 

The NPSEP generation forecast is listed in Table 4-11. The results show that the average annual growth rate of electricity generation and peak demand of the country over the 2010 to 2035 period is 7.68% and 7.92%, respectively. The total generation and peak demand are expected to reach 889,583 GWh and 149,665 MW by the end of the period.   

4.5.3     Forecast with DSM 

It was not possible to explicitly include DSM initiatives in the medium term PMS model, or in the regression forecast. The impact of DSM on the forecast has been approximated by an improvement of the load factor to 70%, up from the 67% assumed in the Base Case. The NPSEP forecast with DSM is shown in Table 4-12. 

504760-01-MR                                                 4-16                                                   Main Report 

                                                                               Table 4-11      Load Forecast – Normal 

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4.5.4      Summary of Forecasts 

A summary comparison of the four forecasts developed for the selected years is presented in Table 4-13 below.   

                Table 4-13      Summary of Forecasts for Selected Years for Country 

The detailed summary comparison is shown in Table 4-14. 

                                           Table 4-14      Summary of Forecasts 

The peak demand forecasts for the combined PEPCO and KESC systems for the different scenarios considered is shown in Figure 4-1 below: 

               Figure 4-1       Summary of Forecast Results (MW) – PEPCO and KESC 

5     FUEL SUPPLY, PORT HANDLING AND FUEL PRICING 

5.1     Introduction 

The key objective of this section is to provide an assessment of the fuel supply and demand situation and the fuel supply infrastructure in Pakistan. This assessment is based on the information gathered during visits to the gas companies and ports, as well as information obtained from secondary sources, such as available reports and websites.  The current situation with respect to all the major fuels, namely natural gas, oil and coal along with the plans to enhance the supply of various fuels and the steps being taken to implement these plans are also presented. 

As the capacity of ports to handle the fuel supply is an important factor for the assessment of the fuel supply infrastructure, this section also provides information on the current capacity of various ports to handle the fuel and the plans to enhance this capacity.  The scope of this work is restricted to the review of the fuel supply infrastructure/port handling facilities and specific recommendations for the development of fuel supply infrastructure and port handling facilities as it is outside the scope of the mandate. 

Considering that the analysis of prices of various fuels is an important subject with regard to the development of the power sector and this analysis of the current pricing of various fuels and fuel price projections is also included in this section.  

A detailed analysis on the supply of fuel, its infrastructure and pricing is provided in Annexure 1 along with a list of sources consulted. 

5.2     Fuel Supply 

5.2.1     Natural Gas 

Domestic Gas Production

Presently there are 14 gas production companies operating in Pakistan producing a total of a little over 4,000 MMcfd^[1](million cu-ft per day). There are 10 major gas production fields and several smaller ones. Unless there are new discoveries, domestic supply of gas is expected to decline while the demand for gas by all sectors is increasing. There are already load management measures currently in effect.   

A number of options are being considered to enhance the supply of gas. These include: 

• Enhancing the domestic production; 
• Import of gas from Iran; 
• Import of gas from Turkmenistan; 
• Import of gas from Qatar; and 
• LNG Imports. 

Options for the import of gas are described in the following section.  

SNGPL has declared that some gas reserves have been discovered in the Khyber PakhtunKhawa (KPK) province with a current potential estimated to be 350 MMcfd. Efforts need to be made to obtain a more accurate estimate of the gas reserves and to tap this source for enhancing the domestic supply of gas. In addition, infill drilling technology can be used on the existing gas fields in order to recover more gas from existing gas reservoirs for an estimated 500 MMcfd of gas using this method.  

Concerted and well-planned efforts need to be made to review the different options of gas supply and decisions for the implementation of these options should made quickly so that the situation of gas supply in the country can be improved. 

The current policy of the prioritization of gas supply to different sectors also needs to be reviewed. Currently, the policy allows gas allocation according to the following priority: 

• Domestic and commercial sectors; 
• Fertilizer industry; 
• Power generation having FSAs (Fuel Supply Agreement); 
• Industry and CNG; 
• Other power plants; and 
• Cement industry 

The above policy shows that gas allocation for the power sector has a relatively low priority. This policy needs a review considering the added value of gas for its utilization in different sectors.  

Options for Import of Gas

Considering that the indigenous sources for the supply of natural gas would not be sufficient to meet the growing requirements of natural gas, a number of options for the import of gas are being studied / implemented.  For the time being, these include: 

• Import of gas from Iran; 
• Import of gas from Turkmenistan; and 
• Import of gas from Qatar. 

Import of gas from Iran to the tune of 750 MMcfd is the option which is at a relatively advanced stage and if implemented will circumvent the shortage of the gas supply to a certain extent.  The work on the Iran-Pakistan line is underway and the project is expected to be completed by 2015.  The gas pipe line would enter Pakistan from Gwader area and would terminate at Nawabshah. According to the plans, the imported gas from Iran will mainly be used for power generation and initial estimates suggest that it could be used to generate about 5,000 MW generation capacity.   

The import of gas from Turkmenistan via Afghanistan is the other import route that is being considered.  In this regard recent contacts between the governments of the participating countries were made and the necessary agreements have been signed. The participating countries include Turkmenistan, Afghanistan, Pakistan and India.  The project is known as TAPI project and its estimated cost is US $ 7.6 billion.  The gas pipe line is envisaged to provide 38 million cu-m per day to Pakistan and India. This is equivalent to 1,342 MMcfd. According to the agreements signed recently, its completion is expected in 2014. However, the geo-political risks regarding the implementation of the project should not be ignored, which might hinder or delay the planned implementation of the project.  

A submarine pipeline from Qatar is the other option that was under consideration for the import of gas in the 1990s.  According to the plans, Pakistan was supposed to import 2,400 MMcfd from Qatar through a pipeline link of about 1,700 km. Most of the proposed link was offshore. However, this plan never materialized and for the time being is not being actively considered.  According to the reports, Qatar has also expressed its inability to provide such a large quantum of gas.  An alternative option that has been considered in the recent past is the import of LNG from Qatar.   According to the information available, import of 1.5 million tonnes of LNG is under consideration, which is equivalent to 200 MMcfd.  This gas is proposed for use by the power sector. 

Gas Transportation and Distribution

Currently there are two gas transportation and distribution companies, namely Sui Southern Gas Company limited (SSGCL) and Sui Northern Gas Pipelines Limited (SNGPL).  These companies are also involved in the marketing of gas.   

SSGCL has the responsibility for the southern part of the country including Sind and Baluchistan provinces.  The total transmission capacity of the SSGCL network is 1,643 MMcfd.   Its distribution system is quite extensive and covers over 4,200 km. Its design capacity is 2,442 MMcfd (SSGC website).   

SSGCL accounts for about 30% of the total gas supply in the country. According to the Pakistan Oil Report by OCAC the gas supplied by SSGCL during the year 2009-10 was 1,065 MMcfd. Of the 1,065 MMcfd of total gas supply, the share of the supply to the power sector was about 30%.  

SNGPL transmission system extends from Sui in Baluchistan to Peshawar in KhyberPakhtunkhwa and passes though Punjab.  It accounts for about 48% of the gas supply.  In year 2009-10, SNGPL gas supplies were 1812 MMcfd as reported in the Pakistan Oil Report by OCAC.    

Both SSGCL and SNGPL currently supply a combined volume of 2,945 MMcfd, which is equivalent to 78% of the total gas supply.   The remaining 22% of the gas supply is transported by various independent systems.  The total gas transportation infrastructure consists of about 11,000 km of transmission line and approximately 102,000 km of gas distribution lines.  The appropriate compression system is in place to facilitate the transportation of gas over long distances.  

5.2.2     Fuel Oil 

Fuel Oil Production and Imports  

The oil reserves in the country that are recoverable are 314 million barrels, which is equivalent to 42 MTOE (million tons of oil equivalent).  The current production in the country is about 66,000 bbl/day^[2].   

The domestic oil production in the country is not sufficient to meet the growing requirements for fuel in the country. Therefore, the country is dependent on the import of fuel to meet the demand of fuel and to bridge the gap between the demand and supply.   About 84% of the total oil requirements are imported.  

The total crude oil production in the country in the year 2008-09 was 3.2 MTOE while the imports in the country were 18.4 MTOE, out of which 8.3 MTOE were crude oil imports and 10.1 MTOE were Product imports^[3].  

OGDCL has the largest production of crude oil in the country followed by BP and PPL.  In the year 2008-09, OGDCL’s crude oil production was 40,485 bbl/day, while the crude oil production by BP and PPL was 9,745 bbl/day and 4,696 bbl/day respectively.   The two main fuels used in the country are high speed diesel (HSD) and fuel oil.  HSD is mainly used in transportation while fuel oil is used for power generation. As domestic production and refining capacity are insufficient to meet the domestic demand, 4.4 million tonnes of HSD and 5.1 million tonnes of fuel oil were imported in the financial year 2008-09^[4].

Petroleum Products Consumption, Refining and Marketing  

The biggest consumption of petroleum products takes place in the transportation sector followed by the power sector.  Fuel oil consumption in the power sector in the years 200607, 2007-08 and 2008-09 was 6.74 million tonnes, 7.08 million tonnes and 7.57 million tonnes respectively.  

There are 7 refineries in the country with a total refining capacity of about 13.887 million tonnes per year as reported in Pakistan Oil Report by OCAC. The refining capacity in the country is able to cater for about half of the total demand, while the remaining demand is met by the oil imports.  

The key marketing company which supplies oil to both the transportation and power sectors is Pakistan State Oil (PSO) which enjoys a market share of 70%.  In addition to PSO, the other marketing companies include Shell, Caltex, Attock Petroleum Limited, BPPL, HASCOL, ASKAR and OOTC Land Total-PARCO. These companies are free to import oil to meet the local demand.  

5.2.3     Coal 

Coal Reserves and Production  

Making use of the available coal resources for power generation and meeting the growing energy needs of the country is one of the cornerstones of the power policy.  The total coal resources of Pakistan are estimated to be 185 billion tonnes^[5].  

The total estimated reserves of Thar coal are 175 billion tones and are spread over a geographically contained area of about 9,000 sq.km. The other major fields in Sindh are Lakhra, Sonda-Jherruck and Indus East.  The coal reserves in these fields are estimated to be 1,328 million tonnes, 5,523 million tonnes, and 1,777 million tonnes respectively.  

Thar coal field has the potential of generating about 100,000 MW based on the assumption of 536 million tonnes of coal production per year.  While the potential of power generation of Lakhra and Sonda fields are 1,000 MW and 500 MW respectively.  These are based on coal consumption of 4.60 million tonnes per year and 2.3 million tonnes per year respectively.  Other coal fields have the potential of generating 25 – 50 MW of power. This fuel source for power generation could contribute hugely to the security and diversity of indigenous fuel supply for power generation^[6].   

According to the Energy Yearbook, the production of coal in 2008-09 was 3.37 million tones (MT) while 4.65 MT was imported. 

Apart from the power sector, the main consumers of coal are the cement industry, steel industry and brick-kiln industry. In the year 2008-09, the power sector consumed only 1.3 % of the total supply of coal^[7].  

5.3    Capacity of Ports and Fuel Logistics   

The major ports in the country include Karachi Port and Port Qasim. These ports located at Karachi serve as the major hub for the import and export of commodities.  Both the ports have the facilities to handle fuel oil as well as coal.   

Karachi Port Trust

KPT is the main port that deals with the imports and exports of liquid bulk cargo and dry bulk cargo. KPT handled imports of bulk liquid cargo of about 9.84 million tonnes in the year 2009-10.  The imports of crude oil, diesel and furnace oil handled by the port in the year 2009-10 were 6.12 million tonnes, 0.6 million tonnes and 1.17 million tonnes respectively.   Currently KPT has the capacity to handle 24 million tonnes of all types of fuels. Currently the capacity of KPT to handle liquid cargo is under-utilized and less than half of the available capacity is being used.  KPT has plans to increase the fuel handling capacity to 28 million tonnes per annum in the future, however considering that its present capacity is underutilized, there are no immediate plans to enhance this capacity. KPT also has the storage capacity of 1 million tonnes of liquid fuel.  There are no plans to increase this storage capacity.^[8]

With regards to the handling of coal, KPT handled the import of 3.65 million tonnes of coal in the year 2009-10.  The available capacity to handle coal is 4 million tonnes per annum. It has no plans to enhance this capacity as the Port Qasim Jetty is planned to be utilized for coal handling. KPT also has the storage facility for 0.7 million tonnes of coal.  

KPT has also signed an MOU with PSO for laying a fuel oil pipeline from Keamari to Korangi^[9].  

Port Qasim Authority  

Port Qasim, the second busiest port in the country handling about 40% of the nation’s cargo (17 million tonnes per year) is located near Karachi at a distance of 35 km from the city centre.  

At Port Qasim, the terminal that deals with the handling of fuel oil is FOTCO (Fauji Oil Terminal and Distribution Company) is capable of handling 9 million tonnes of furnace oil per annum (750,000 tonnes per month) with a growth potential to handle more than 27 million tonnes with three additional berths.  HSD and crude oil are also imported at FOTCO terminal after commissioning of the PAPCO oil pipeline. The facility mainly comprises a jetty capable of handling up to 75000 DWT vessels, product pipelines, loading arms and a 4 km long trestle that connects the jetty with the shore. The terminal has the capability to berth tankers with 63,000 tonnes ship-load.  For liquid fuel storage, 77 acres of land has been earmarked.  

FOTCO has a capacity to handle 15 tankers per month. Infrastructure limitations of FOTCO restrict the large size vessels.  However, due to inadequate port and storage facilities at other terminals belonging to KPT and PQA, it is expected that 20-23 cargoes per month will be handled at FOTCO which will result in congestion at the FOTCO terminal. The terminal is designed to cater for four additional berths and four product pipelines to meet the current and future fuel handling requirements of the country. 

There is a separate Iron Ore and Coal berth that deals with the imports of coal. The design capacity of the berth is 3.36 million tonnes per annum. The berth has a handling capacity of 1400 tonnes per hour. Currently vessels of 55,000 tonnes payload are being handled here.  

PQA has developed plans to increase port parameters to accommodate larger vessels to benefit from economies of scales, and to build additional berths/terminals. Some of the development projects relevant to fuel handling include establishment of an LPG terminal and coal & clinker/cement terminal^[10].  

Fuel Logistics

The transmission and storage network for fuel oil adequately covers most of the major cities as well as remote areas.  A pipeline network of about 2000 km exists for supplying crude oil as well as refined fuel products.  The crude oil pipeline belongs to PARCO, while the pipelines for the refined products are owned by PAPCO, Shell, PSO and other oil companies. 

The rail road capacity to transport oil is presently 1.2 million tonnes/annum.  This is about 4,000 MT/day. As the railroad capacity is not sufficient, a significant quantity of oil is transported up-country through road tankers.  Currently about 4 million tonnes of fuel oil per annum is being transported by road tankers^[11].  

Among the fuel oil suppliers, PSO is the largest supplier of fuel oil to the power generation sector.  It has a relatively large fuel oil logistic capacity.  Its capacity to transport oil by pipelines, road and rail is 5 million tonnes/year, 6.5 million tonnes/year and 1.5 million tonnes/year respectively. 

As regards the future strategy to supplement the existing storage and transportation capacities for fuel oil, a number of measures have been planned. These include: 

• PSO and KPT plan  to connect the Port Qasim with Karachi Port via a 52 km pipe line; 
• Enhancement of port infrastructure to handle increased number of vessels; 
• Agreement between Pakistan Railways and PSO to increase the railroad capacity from 120,000 MT/month to 250,000 MT per month; and 
• Up-gradation of storage and transportation infrastructure. 

5.4     Pricing of Fuels 

The current fuel prices, transportation and handling costs and the projection of future fuel prices are presented in this section.  Full references to data sources, the basis of cost computation and detailed analyses are presented in Annexure 1. 

Current Fuel Pricing   

The current prices of various types of fuel are provided in Table 5-1. The prices presented represent both the domestic and international fuels.   

                                              Table 5-1        Current Fuel Prices 

   Source: Based on data from Energy Information Administration, International Energy Agency, Platts, OGRA, WAPDA and PSO 

Fuel Transportation & Handling Costs

Power sector fuels may be transported by road, rail, or pipeline.  Historically, coal and fuel oil are primarily transported by rail and road, natural gas is transported by pipeline, and diesel is transported by pipeline and road.  Table 5-2 shows the current costs for the various modes of fuel transport.  

                                        Table 5-2        Fuel Transportation Costs 

Source:Based on data from Platts, and OGRA and calculation of SNC-Lavalin Inc.

The port handling costs for crude oil and other liquid petroleum products, LNG and coal are provided in Table 5-3.  These costs are considered to remain fixed in 2010 dollars up to the year 2030.  

                                       Table 5-3        Fuel Handling Costs at Port 

Source:Based on data from NEPRA, EIA and calculation of  SNC-Lavalin Inc.

Future Fuel Price Projections  

Many agencies project future fuel prices – the notable ones are Energy Information Administration (EIA), International Energy Agency (IEA) and Platts. In general, these projections take into account the world economy, supply and demand situation, market volatility and political considerations.  The long-term fuel price forecasts for different fuels in mixed units are provided in Table 5.4.   

         Table 5-4        Long-Term Fuel Price Forecasts to the Year 2030 (Mixed Units) 

Source: Based on data from EIA, Pakistan Energy Yearbook 2009, and ISGS (Inter State Gas Systems), IEA, Notes:  All prices are at 2010 price levels 

The Thar coal costs above have been derived from the Rheinbraun Engineering 2004 feasibility study, escalated to 2010 price levels. For the generation planning analysis, Thar coal has been priced such that the cost of power from a plant using Thar coal would be equivalent to the cost of power from a coastal plant using imported coal. 

The fuel prices in $/MMBtu are provided in Table 5-5. The computational basis of these price forecasts are provided in Annexure 1.  

           Table 5-5        Long-Term Fuel Price Forecasts to the Year 2030 ($/MMBtu) 

Source:Based on data from EIA, Pakistan Energy Yearbook 2009, and ISGS (Inter State Gas Systems)

The data presented in the above table illustrates that the prices of various types of liquid fuels and natural gas are envisaged to increase over the planning period.  The price of imported coal is projected to increase till 2020, and after then it is projected to decline slightly based on the coal price projections by EIAC (Energy Information Administration, USA). 

The current fuel transportation infrastructure needs to be examined in light of the changing requirements of all types of fuel. This has implications on the development of current rail, port and road infrastructure. The generation planning section provides details of the level of each fuel type that will be required for the current plan which serves as a key input to any infrastructure policy and plan that will need to be developed at the national level. In case of fuel availability restrictions and inadequate development of fuel supply infrastructure, revisions would possibly be required in the generation plan. 

6     GENERATION PLANNING 

6.1     Introduction 

The key objective of the generation expansion  planning activity was to develop a long range least-cost generation expansion plan for Pakistan for the period 2011-12 to 2029-30 to meet the maximum load demand and energy consumption whilst taking into account government policies and identified constraints.  

This section describes the key parameters and results of the generation planning study and is structured as follows: 

• Strategic and Policy Considerations; 
• General Approach and Methodology; 
• Planning Basis; 
• Review of the Existing and Committed System; 
• Generation Options Available and Screening; 
• Scenarios Considered for Generation Expansion; 
• Development and Analysis of the Base Case Expansion Plan; 
• Comparison of the Base and Alternative Cases; 
• Sensitivity Analysis for the Base Case; and 
• Conclusions.

6.2     Strategic Considerations 

In order to develop an effective generation plan that will meet the power needs of the country, both the strategic considerations and constraints faced by Pakistan have to be taken into account. In developing the National Power System Expansion Plan (NPSEP) careful consideration has been given to the Government of Pakistan (GoP) policy guidelines as well as  fuel and infrastructure constraints that affect the power sector development. 

As outlined in their document “Policy for Power Generation Projects Year 2002” the GoP Power Policy has three key objectives as listed below: 

• To provide sufficient capacity for power generation at the least cost, and to avoid capacity shortfalls; 
• To encourage and ensure exploitation of indigenous resources, which include renewable energy resources; and 
• To be attuned to safeguarding the environment. 

The GoP has two other policy documents that impact on the development of power system expansion plans. The Natural Gas Allocation and Management Policy 2005 states that, as part of their demand management policy, “Power Plants would get gas supply after meeting the requirements of domestic, commercial, fertilizer and industrial sectors”. The demands of these other sectors are increasing rapidly, thus the availability of domestic gas for future power plants is likely to be limited. The Policy for Development of Renewable Energy (RE) for Power Generation 2006 mentions as a target to “Increase the deployment of renewable energy (defined as wind, solar and small – less than 50 MW – hydro) technologies so that RE provides a minimum of 9,700 MW by 2030”.   

Pakistan faces several constraints as it strives to meet its current and expected power demand. Perhaps the most significant constraint is the scarcity of capital, which has affected not only power sector development but also the development of other infrastructure critical to power sector development. 

In the short term the main focus has been the reduction of load shedding, and this focus has often taken attention away from an optimum long term growth strategy. it is accepted that it will probably take several years for the target reliability level of 1 % Loss of Load Probability to be achieved. The short term focus is on rehabilitation of existing plants, on demand side management, and the implementation of fast track projects to reduce load shedding.  

In the long term, it is assumed that the GoP’s policy will continue to focus on the development of indigenous resources, particularly Tharparkar coal and hydro projects, as well as increasing the use of renewable resources and keeping power tariffs at affordable levels. Also barring major gas discoveries, the GoP policy of allocating gas will remain unchanged and future gas based power generation will be based on imported gas or LNG. 

The development of the Base Case described later in this section has taken the foregoing policy guidelines, and the least cost approach into consideration. Also considered are fuel availability, infrastructure and other constraints. 

6.3    Approach and Methodology 

The development of the least cost generation plan is the process of optimizing the additions of generation supply options in order to determine the optimal development sequence, which would meet the projected demand and would satisfy the specified reliability criteria.    

The first step was to review the existing and committed system, and to review the range of generation addition options available to meet the future demand. The next key step was to determine the economically attractive generation options and generation mix using simplified screening curves. The purpose of the screening curves was to compare the unit cost of different plants at different plant factors. The Base Case and Alternative Cases to be analysed were then defined. The last step was the development of the least cost plan under the Base Case and alternative scenarios using the System Planning and Production Costing Software (SYPCO).  

6.4     Planning Basis 

In order to ensure that all the developed scenarios met uniform requirements in terms of performance and to also enable all the scenarios to be compared on a similar technical basis, specific planning criteria was adopted. These criteria are summarized in Table 6-1 below and are discussed in detail in Annexure 2. 

                                                 Table 6-1        Planning Criteria 

Load Profile and Forecast

Analysing annual hourly load profiles is an important aspect of generation planning to capture the hourly and seasonal variation in the load. The hourly loads are used to construct the monthly load duration curves which are one of the key inputs to generation planning. The historical monthly load duration curves are used for planning the future years. The assumption is that the future monthly/seasonal load variations would be very similar to the past ones. However, the historical load duration curves in the recent years cannot be directly used for future years since these curves are restricted by supply availability. Therefore it is necessary to have information on unrestricted monthly load patterns and hourly load profiles to represent the future years. After reviewing the historical data and previous studies,  

2003-04 was selected as it had no planned load shedding and very little adjustment was required for unexpected load shedding.  

The load forecast developed for the NPSEP forecast is based on multiple regression techniques, and considers three scenarios – low, normal, high and another case where the normal forecast is adjusted for demand side management (DSM) measures. The load forecast is presented in Section 4 of this Report.  

Fuel Pricing

The prices for different fuels is one of the critical inputs for developing the least cost generation plan since the quantum of fuel used and its cost has a significant impact on the economic attractiveness of the thermal candidate units. The fuel price forecast for the study period is summarized in Table 6-2. 

                            Table 6-2        Summary of Fuel Price Forecast to 2030 

Notes:All prices are in 2010 US$ 

These fuel price projections are based on the Annual Energy Outlook (2010) prepared by the Energy Information Administration (EIA) and other sources, and restated in 2010 price levels. Details are given in Section 5 of this Report. In Table 6-2, the handling cost for imported coal and furnace oil (LSFO) were estimated based on the costs used in NPP 1994 (US$ 10/ton for imported coal and US$ 1.5/barrel for oil) escalated by 3% each year considering both the impacts of inflation and the advancement of the technologies. The handling costs were added to the price of imported coal and oil for screening curve analysis and generation production costing. 

Given the shortage of supply of indigenous fuels, it is likely that at the margin petroleum products and gas will need to be imported for future power plants. Thus pricing for petroleum products and gas have been based on their imported equivalents. 

Although Thar coal would be produced domestically, currently there is insufficient information to base firm mining costs on. Thar coal has been priced such that the cost of power generated at Thar using Thar coal would be equivalent to the cost of power from a coastal plant using imported coal. Based on this analysis, Tharparkar coal would need to be priced at or below $ 56 / MT in the first year, or $70 / MT on average over the life of the generating plant. The breakeven analysis is shown in Table 6-3. 

                               Table 6-3        Breakeven Price for Tharparkar Coal 

The premise is that the Tharparkar coal should be priced such that the cost of power from a mine – mouth plant is competitive with the cost of power from a plant located on the coast burning imported coal.  

Environmental Criteria

The environmental criteria for the NPSEP are presented in Section 3 of this Report. 

The emission requirements for power plants have been based on the National Environmental Quality Standards (NEQS) of Pakistan. The emission requirements pertain to Particulates, Nitrogen Oxides, Sulphur Dioxide, Liquid Effluents and Solid Wastes. The NPSEP has included in its cost estimates water treatment equipment for all plants, Flue Gas Desulphurisation equipment for coal fired plants and has used Low Sulphur Fuel Oil for oil fired plants.  

The range of adverse environmental and related social impacts that can result from hydro dams is remarkably diverse. Twenty seven hydroelectric projects have been considered in the NPSEP.  Of these, eighteen projects have undergone thorough feasibility studies. Eleven of the eighteen projects have feasibility studies which are more than three years old and need updating. Nine projects are at initial stages and their feasibility studies have not yet been started. For those projects that have been studied to feasibility level and for which environmental cost estimates are available, these environmental cost estimates have been escalated to 2010 price levels. For those projects which have not been studied to feasibility level and for which environmental cost estimates are not available, an approximation has been made. The approximation is based on information for those projects for which the required information is available. For example, the environmental cost as a percentage of total project cost averaged over all those projects for which information is available is applied to those projects for which the total project cost is available but the environment cost is not. These costs are shown in Table 6-11 of Section 6.7. 

6.5    Existing and Committed Units 

The total installed capacity of existing hydro and thermal generation units for the PEPCO and KESC systems including IPPs is about 21,455 MW as at the end of 2010. However, due to the seasonal variation of water inflows for hydro plants and the capacity de-rating of thermal units, the dependable capacity for the systems are estimated to be 15,254 during winter. The installed capacity of hydro plants accounts for about 31%, thermal capacity for 67%, and nuclear capacity less than 2%. The total installed capacity from IPPs is about 38% of the total installed capacity. This breakdown is shown in Figure 6.1: 

                                         Figure 6-1       Installed Capacity in 2010 

6.5.1      Existing Hydro Plants 

The total existing hydro capacity in the country is 6,555 MW. However, due to the seasonal variation of water inflows, the existing hydrol plants can only provide 2,414 MW dependable capacity during winter.  The summary of existing hydro plants is provided in Table 6-4. Table 6-4 Summary of Existing Hydro Plants 

The detailed information of the existing hydro plants is provided in Annexure 2. 

6.6     Existing Thermal Plants 

The existing thermal plants in the country are owned by PEPCO, KESC and IPPs. Table 6-5 provides a summary of the status of existing thermal plants in the system as at the end of 2010.  

                             Table 6-5        Summary of Existing Thermal Capacity 

*De-rated capacity = Gross dependable capacity 

The detailed information of the existing thermal plants is provided in Annexure 2. 

The plant-wise information of existing thermal units and existing hydro units under public and private sectors for the PEPCO system is presented in Table 6-6. 

                      Table 6-6        Existing Generation Capacity of PEPCO System 

*De-rated capacity (MW) for Thermal Plants

The summary of existing thermal units in the KESC system is presented in Table 6-7 below: 

                                     Table 6-7        Existing Units – KESC System 

Retirement of Existing Plants

There is no retirement plan for the existing units in the PEPCO and KESC systems. For planning purposes, the following retirement schedule in Table 6-8 was used taking into account the current condition of the existing units and the typical service lifetime of unit types.