PROJECT DESIGN DOCUMENT (PDD) Projects...Gulpur Hydropower Project (“the Project”) is a new scheme of 102 MW run-of-river (“ROR”) hydroelectric power project on Poonch River

CDM-PDD-FORM

Project design document form for CDM project activities

(Version 08.0)

Complete this form in accordance with the Attachment “Instructions for filling out the project design document form for CDM project activities” at the end of this form.

PROJECT DESIGN DOCUMENT (PDD)

Title of the project activity 102 MW Gulpur Hydropower Project

Version number of the PDD 03

Completion date of the PDD 15/08/2016

Project participant(s) Mira Power Limited

Host Party Pakistan

Applied methodology(ies) and, where applicable, applied standardized baseline(s)

ACM0002/Version 17 “Consolidated methodology: Grid-connected electricity generation from renewable resources”

Sectoral scope(s) linked to the applied methodology(ies)

Sectoral Scope: 01, Energy Industries (renewable and non-renewable sources)

Estimated amount of annual average GHG emission reductions 257,022 tCO2/yr

Version 08.0 Page 1 of 76

CDM-PDD-FORM

SECTION A. Description of project activity

A.1. Purpose and general description of project activity Gulpur Hydropower Project (“the Project”) is a new scheme of 102 MW run-of-river (“ROR”) hydroelectric power project on Poonch River which will generate mean annual energy of 474.996 GWh and will connect to government owned national grid of Pakistan (“National Grid”) through a 30 years long term Power Purchase Agreement with Central Power Purchasing Agency (Guarantee) Limited on Build-Own-Operate-Transfer (“BOOT”) basis, where the ownership of the Project will has to be transferred to Azad State of Jammu and Kashmir (“AJ&K”) free of charge. The Project will generate clean, renewable, reliable and sustainable energy to offset power shortages in the country and will replace electricity otherwise supplied by dominant existing or future planned thermal power sources to the extent of its generation. The Project shall contribute to GHG emission reduction by displacing oil and coal fired thermal power plants. The implementation of this hydropower plant will result in the reduction of 228,783 tonnes CO2e per annum. The Project is being implemented by Mira Power Limited, a special purpose vehicle formed for implementation of the Project owned by a Korean consortium lead by Korea South East Power Co. Ltd. The Project has been conceived for harnessing the power potential of Poonch River and relates to installation of a new dam, intake structure and a powerhouse with two Kaplan turbine units of 51 MW each utilizing head of 57.8 meter and a design discharge of 201 m3/s. Energy will be evacuated via an existing transmission line that runs approximately 200 meter from the powerhouse. The reservoir area created would be 2,257,000 m2 and the power density is 45.19 W/m2. The Project is expected to be commissioned on October 2019. As determined in Section B.4, the baseline scenario relates to the electricity for the National Grid by the operation of grid connected power plants and by the addition of new generation sources. The baseline scenario is the same as the scenario existing prior to the start of the implementation of the project activity. As established in Section B.3, the project boundary includes the CO2 emissions from electricity generation in the fossil fuel fired power plants that are displaced due to the project activity. Sustainable Development The project is consistent with the national laws and sustainable development policies, strategies, plans and addresses the national sustainable development. The Project is also in compliance with International Finance Corporation (IFC)’s Performance Standards and Asian Development Bank Safeguard Policy Statements and beneficial in following manner: (a) Environmental Development:

(i) The Project is located in the Poonch River Mahaseer National Park notified in 2010 and aims to achieve net gain for biodiversity consistent with Safeguards Requirement (SR) 1 of ADB’s SPS1 and IFC’s Performance Standards2 and will therefore achieve betterment of the national park through implementation of a Biodiversity Action Plan which will benefit the environment in the Poonch River.

1 Asian Development Bank, 2009 Safeguard Policy Statement (SPS) – Safeguards Requirement (SR) 1 on Environment

2 Policy on Social and Environmental Sustainability, January 2012. Performance Standard 6: Biodiversity Conservation and Sustainable Management of Living Natural Resources, International Finance Corporation. The World Bank Group.


CDM-PDD-FORM (ii) Significant reduction in the emissions of Green House Gases (GHGs) to combat

global climate change. (iii) Reducing air pollution by replacing fossil-fired power plants with clean, renewable

power; (b) Socioeconomic Development:

The potential socioeconomic developments due to the Project can be categorized into the following three groups:

(i) Macroeconomic: o The gap between supply and demand has crossed 5,000 MW. The proposed Project

will supply the much needed power to reduce the current gap. o The Project will invest in equipment, construction materials, infrastructure and human

resources. This investment and the return generated from the Project will be circulated within the AJK economy.

o Reducing the dependence on exhaustible fossil fuels for power generation and good for energy security;

o Government revenues collected during the operational phase of the project in the form of taxes and royalties will benefit the national economy

o Alleviation of poverty by creating regular employment opportunities to the local community in the economically depressed region having very scarce industry and higher rate of unemployment.

(ii) Local Livelihoods and Wellbeing: o Direct, indirect and induced employment at the domestic and local levels, resulting in

increased prosperity and wellbeing due to higher and stable incomes of people o Increase in the stock of skilled human capital due to transfer of knowledge and skill

under the Project resulting in enhanced productivity o Increase in local incomes and wellbeing due to increase in catch of fish following

protection and creation of favorable habitats for the fish in the Poonch River (iii) Socio-cultural: o Development of sustainable mining plan for the entire stretch of river for a commercial

and legal sand/gravel mining and fishing activities for locals. o Improving the skill set for local inhabitants through training and capacity building for

employment in the project, hence contributing to growing technical advancement. o Increase in opportunities for recreational fishing due to increase in population of fish. o In-migration of job seekers leading to cultural and ethnic diversity, promoting tolerance

and awareness in the Project area. This project conforms with, and fits in the policy and objectives of the Government of Pakistan (GoP), where its objectives are to reduce the dependence on exhaustible fossil fuels for power generation, make the energy sector in general and the power sector in particular more sustainable. It is also confirmed that the proposed CDM project activity is not a CPA that has been excluded from a registered CDM PoA as a result of erroneous inclusion of CPAs.


CDM-PDD-FORM

A.2. Location of project activity

A.2.1. Host Party Pakistan

A.2.2. Region/State/Province etc. Azad State of Jammu & Kashmir (AJK) Pakistan

A.2.3. City/Town/Community etc. District Kotli/Barali Village/Rehmani Muhalla

A.2.4. Physical/Geographical location The Project site is located on the Poonch River in Kotli District of Azad State of Jammu and Kashmir at latitude 33°27’ and longitude 73°51’, about 9 km South of Kotli Town. The site is located about 167 km from Islamabad and 285 km from Lahore, it is directly approachable from Islamabad and Lahore by a two-lane, all-weather paved mountainous road.


CDM-PDD-FORM

A.3. Technologies and/or measures >> The Project is a new facility and major components include dam, intake structure and power house. All the project structures will be located near Barali village on the Poonch River about 11 km downstream of Kotli Town and about 6 km downstream of the confluence of Bann Nullah with the river. The intake structure and intake portal of the power tunnel will be located on west bank of the Poonch River, 150 meter upstream of weir structure on the eastern face of a ridge. The power house and outlet will be located on right bank Poonch River about 700 m downstream of the dam structure. The dam will be a concrete gravity dam (CGD) with a height of 66m, length of 205 m, and a spillway having 6 gates (11.5m x 6) with overall width of 86.5m. Technical Features of Project are as follows: Normal Operating Level EL. 532.0 m Weir Concrete Gravity Dam, H 66.0 m, L 205.0 m River diversion Coffer dams & Diversion tunnels Spillway gate H24.0 m X W11.5m X 6Nos. Intake Horizontal Bell-mouth type, Gate Size : W 10.0 m X H 8.0 m X 3 Nos. Waterway Tunnel D 5.0 m, L 154.51 m, 144.88 m, 135.25 m Powerhouse Surface type, L 33.05m × W 80.0m× H 60.75m Plant Discharge 201.0 ㎥/sec Gross Head 57.45 m (Rated Head 55.95 m)


CDM-PDD-FORM

Power would be generated with the help of two Kaplan turbines (51 MW each), each with flow of 102 m3/s at full capacity and a minimum rated flow of 20 m3/s. Using Kaplan is a change compared to Feasibility Stage design where Francis type turbine with a minimum rated flow of 33 m3/s were planned while the minimum rated flow of turbines in this option would be lower. This would result in an improvement in power generation from the Project as the turbines will not have to shut when the flow is in the range of 20-33 m3/s under this option.


CDM-PDD-FORM The technology of Kaplan Turbine is evolution of Francis Turbine and more efficient and applicable for head of 10m to 70m and implied in many projects worldwide. The technology was developed since 1913 and operates at an efficiency of over 90%. The Kaplan Turbine was switched from Francis Turbine as Kaplan offers more advantages over the Francis Setup that includes better operational flexibility, easy O&M and coating, more energy generation, good in environmental point of view and longer in operational life. The technology for manufacturing hydro-turbines and generators is not available in Pakistan. Therefore, it has been proposed that the turbines, generators, automation and control systems shall be procured from European suppliers. The Project implementation shall be covered by robust set of contractual obligations of the Company and its contractor (s) through legally enforceable documents that includes; (i) Power Purchase Agreement (PPA) finalized by Private Power Infrastructure Board (PPIB), Government of Pakistan, Central Power Purchasing Agency (Guarantee) Limited (CPPAG) and other stakeholders. (ii) Engineering, Procurement and Construction (EPC) Contract executed with Joint Venture of M/s Daelim Industrial and M/s Lottee and Operation and Maintenance (O&M) Agreement with lead sponsor (Korea South East Power Co. Ltd.) are based on the international best practices, obligations provided in PPA and on the terms and conditions agreed by Company, the GoP, the lenders and equity partner of the Company, has been finalized and awarded through competitive bidding process. As per the Power Policy 2002, CPPAG will purchase power generated by an IPP from its door-step (bus-bar) and does not bound the sponsors to build or construct any transmission line and likewise sponsors have not claimed any additional tariff for construction of transmission lines. For the purpose to meet requirements of the Project, a single circuit 132 kV Dhudial-Kotli transmission line passing over the site and National Transmission and Despatch Company has approved its Interconnection Study. The Project is located in an environmentally sensitive area and notified as national park by the government of AJ&K in 2010 due to presence of Mahaseer Tor putitora which is listed as Endangered in the IUCN Red List 20133 and therefore, Poonch River was classified as a Critical Habitat as defined by the IFC’s PS6 and ADB SPS, requiring the Project to achieve ‘net gain’ in biodiversity. The location, design and layout of the Project was, therefore, optimized compared with design of Feasibility Report whereby the Dam was located just downstream of confluence of Bann Nullah and Poonch River and a 3.1 KM tunnel located 1 KM upstream in Bann Nullah from its confluence with Poonch River. The Normal Operating Level (NOL) of the project was changed to be at an elevation of 532 meters from the sea level which was modified from 540 meters in the original plan to reduce environmental and social impacts. The scheme was changed in order to get following environmental and social benefits:

(a) Under Feasibility Design, approximately 6.1 km of the River would have experienced the low flows due to operation of the Project while in the revised design only 0.7 km of the River will be affected by these low flows. From an ecological standpoint, the negative impact on the ecological resources of the Poonch River will be much less for the changed design compared with feasibility design.

(b) During the breeding season, Mahaseer Tor putitora migrates into the tributaries (nullahs) of the Poonch River for spawning including the Bann Nullah and Rangar Nullah (Figure 1-2). The construction of a dam, as envisaged in Feasibility Study, at

3 IUCN 2013. IUCN Red List of Threatened Species. Version 2013.1. <www.iucnredlist.org>. Downloaded on 26 October 2013.


http://www.iucnredlist.org/

CDM-PDD-FORM the confluence of Poonch River and the Ban Nullah would disrupt this breeding migration and negatively impact the population of the Mahaseer Tor putitora. Under the new design, the Project facilities will be located about 6 km downstream of Feasibility Study location. The breeding grounds of Mahaseer Tor putitora particularly in the Ban Nullah will not be directly affected by Project operations under new scheme.

Figure 1-2

(c) The total submerged area (including the present river) will be approximately 320

hectares for design envisaged in Feasibility Report while 292 hectares for the optimized design, therefore, comparatively less terrestrial habitat will be submerged and consequently there will be a lower negative impact on the terrestrial ecology.

(d) The Resettlement under optimized design is minor in comparison to that for Feasibility Report design.

(e) For Feasibility Stage design, a new road approximately 1.5 km long was planned to

be built from the existing blacktop road to the inlet of the power tunnel in relatively undisturbed pine and scrub forest. For this, vegetation would have to be cleared, and trees cut. For optimized design, a shorter road of 650m length is required.

(f) The option for peaking mode operations as envisaged in Feasibility Report was

discarded to avoid stress on the river ecology downstream of the power house and, therefore, a non-peaking operation of the powerhouse was therefore adopted for the Project in the new design.

In the absence of the project activity the power in the grid would have been supplied by other grid connected power plants and addition of new power plants. The baseline scenario is a continuation of the current practice, thus identical to the scenario existing prior to the implementation of the project activity and identified in Section B.4 corresponds to this situation. The obligations regarding training, personnel and maintenance efforts are covered through above referred project documents and comprise a robust set of contractual obligations of the Company and/or its Contractors. A comprehensive and detailed O&M Contract has been executed which adequately covers manpower requirements, their training, health and safety during normal as well as emergency situations, during construction and operation phases. It may be noted that a significant local resource of trained manpower is available in Pakistan due to existing and operable public sector hydropower projects. Moreover, the EPC Contract will also contain provisions regarding training for operations and maintenance, where the EPC Contractor will also be made


CDM-PDD-FORM responsible for creating an interface between the equipment supplier, O&M Operators and related training activities. The standard Power Purchase Agreement includes obligation of the Company to employ qualified personnel and to comply with prudent utility practices. The preferential obligation to employ staff and labour who are residents of the Project area or its immediate vicinity is provided in EPC Contract for EPC Contractor and its Sub-Contractor. The EPC Contractor is involving local Sub-Contractor for construction of the Project which enhances their capacity, capability and know-how is being transferred to the host Party. The Project involves top-notch Owner’s Engineer (Montgomery Watson Harza, USA) joining hand with local consultant (NESPAK) which will transfer the know-how to the local consultant.

A.4. Parties and project participants

Party involved (host) indicates host Party

Private and/or public entity(ies) project

participants (as applicable)

Indicate if the Party involved wishes to be considered as project participant (Yes/No)

Islamic Republic of Pakistan (host)

Mira Power Limited No

A.5. Public funding of project activity There is no Annex-I countries’ public funding or Official Development Assistance (ODA) involved in this Project activity.

SECTION B. Application of selected approved baseline and monitoring methodology and standardized baseline

B.1. Reference of methodology and standardized baseline The Project applied approved baseline and monitoring methodology ACM0002 i.e. “Grid-connected electricity generation from renewable resources” (ACM0002/Version 17, Sectoral Scope: 01, EB 89) as referred in UNFCCC web-site as follows:

https://cdm.unfccc.int/methodologies/DB/8W400U6E7LFHHYH2C4JR1RJWWO4PVN This methodology refers to latest approved versions of following tools:

• Tool01: Tool for the demonstration and assessment of additionality (Version 7.0); • Tool02: Combined tool to identify the baseline scenario and demonstrate additionality

(Version 6.0); • Tool03: Tool to calculate project or leakage CO2 emissions from fossil fuel combustion

(Version 2); • Tool05: Baseline, project and/or leakage emissions from electricity consumption and

monitoring of electricity generation (Version 02.0); • Tool07: Tool to calculate emission factor for an electricity system (Version 05.0); • Tool10: Tool to determine the remaining lifetime of equipment (Version 1.0); and • Tool11: Assessment of the validity of the original/current baseline and update of the

baseline at the renewal of the crediting period (Version 3.0.1)


https://cdm.unfccc.int/methodologies/DB/8W400U6E7LFHHYH2C4JR1RJWWO4PVN

CDM-PDD-FORM

B.2. Applicability of methodology and standardized baseline The approved methodology ACM0002 is applicable to the Project as it fulfils following conditions as prescribed in the methodology:

(i) The Project involves the construction and operations of a Greenfield power plant (Section 2);

(ii) The Project is grid-connected renewable energy power generation activity that installs a Greenfield power plant (Section 3);

(iii) The Project is a new hydropower plant with a reservoir (Section 4); (iv) The Project will result in a reservoir and power density using equation (7), is greater

than 4 W/m2 (Section 5); (v) The Project is not an integrated hydropower project activity (Section 6); and (vi) The Project activity does not involve switching from fossil fuels to renewable energy

at site of Project activity and is not a biomass fired power plants/units (Section 9). The Power Density of the project activity (PD) is calculated as follows:

𝑷𝑷𝑷𝑷 =𝑪𝑪𝑎𝑎𝑎𝑎PJ – 𝑪𝑪𝑎𝑎𝑎𝑎BL

𝐀𝐀PJ − 𝐀𝐀BL

Where: 𝑷𝑷𝑷𝑷 = Power density of the project activity (W/m²) 𝑪𝑪𝑎𝑎𝑎𝑎PJ = Installed Capacity of the hydropower plant after implementation of the

project activity (W). This is to be newly established project with total installed capacity of 102,000,000 W

𝑪𝑪𝑎𝑎𝑎𝑎BL = Installed Capacity of the hydropower plant before implementation of the

project activity (W) i.e. 0 W 𝐀𝐀PJ = Area of the reservoir measured in the surface of the water, after

implementation of the project activity, when reservoir is full (m²). A new reservoir will be built and surface of water is 2,257,000 m²

𝐀𝐀BL = Area of the reservoir measured in the surface of the water, before

implementation of the project activity, when reservoir is full (m²). As a conservative approach, the value is taken as zero

Therefore: 𝑷𝑷𝑷𝑷 = (102,000,000 – 0) / (2,257,000 – 0) = 45.19 W/m²


CDM-PDD-FORM

B.3. Project boundary

The applied methodology ACM0002 provides that the spatial extent of project boundary includes the project power plant/unit connected physically to the electricity system (National Grid as defined in “Tool to calculate emission factor for an electricity system” (Version 5.0) that the CDM project power plant will be connected to. The baseline emissions include only CO2 emissions from electricity generation in fossil fuel fired power that will be displaced due to project activity. The methodology assumes that all project electricity generation above baseline levels would have been generated by existing grid-connected power plants and the addition of new grid connected power plants.

The greenhouse gases and emission sources included in or excluded from the project boundary are shown in Table below.

Source Gas Included Justification/explanation

Bas

elin

e

CO2 emissions from electricity generation in fossil fuel fired power plants that are displaced due to the project activity

CO2 Yes This gas is included in the project boundary as this was produced in the baseline by the operation of fossil fuel fired power plants connected to the grid.

CH4 No Minor emission source hence has been excluded for simplification

N2O No Minor emission source hence has been excluded for simplification

Proj

ect a

ctiv

ity

For hydro power plants, emissions of CH4 from the reservoir

CO2 No Minor emission source excluded as per ACM0002

CH4 No The project activity results in new reservoir but since the power density is greater than 10W/m2 these emissions are not considered significant in line with the methodology.

N2O No Minor emission source excluded as per ACM0002

The spatial extent of the project boundary includes the project site and all power plants connected physically to the electricity system that the Project is connected to i.e. national grid.

There are two distinct power grids in Pakistan i.e. KESC grid (Karachi Electric Supply Corporation) supplying the electricity to city of Karachi and national grid (National Grid owned by NTDC) covering the remaining part of the country. The project activity will generate cost effective power supply to National Grid avoiding the dispatch of an equal amount of energy produced by fossil fueled thermal plants to that grid. The emission factor has been conservatively calculated by only taking into account the National Grid generation which includes both thermal and hydro generation and excluded KESC generation based entirely on thermal.


CDM-PDD-FORM

B.4. Establishment and description of baseline scenario As the Project activity is the installation of a new grid-connected Greenfield power plant and is not a modification or retrofit of an existing unit, therefore, the baseline scenario as prescribed in the approved consolidated baseline methodology ACM0002 is as follows:

“If the project activity is the installation of a Greenfield power plant, the baseline scenario is electricity delivered to the grid by the project activity would have otherwise been generated by the operation of grid-connected power plants and by the addition of new generation sources, as reflected in the combined margin (CM) calculations described in the “Tool to calculate the emission factor for an electricity system”. (Section 24)

The baseline scenario of the Project is the continued operation of the existing power plants in the National Grid and addition of new generation sources. As the project activity is generation of electricity from renewable energy sources and the electricity generated from the run-of-the river hydropower plant with zero emissions, there is no material leakage and the Project generation will be fed into the fossil intensive National Grid, therefore, the emission reduction would be the equal to baseline emissions. The power system in Pakistan is predominantly thermal and the share of installed generation capacity of thermal power plants using oil, natural gas and coal to the total installed generation capacity in the country, during 2014-15, was about 67.74%, the nuclear contributes 3.17% while hydel and wind generation only contributes 28.67% and 0.43% respectively to the system.

Poonch River

Power

Tunnels

Power House (Turbines,

Generators)

Main Transformer

National Grid

(NTDC)

GHG Emission in Project activity = 0

GHG Emission (main emission: CO2) produced by fossil fired plants in NTDC

CDM monitoring point to measure the electricity supplied to grid as detailed in B.7.2

NTDC

Figure B.1 – Project Boundary

Project Site


CDM-PDD-FORM Keeping in view the above scenario, it can safely be concluded that the Project activity would directly replace oil based thermal generation based on furnace oil and would save emissions by them, calculated on the basis of “Tools to calculate the emission factor for an electricity system”, and emission factors figures are provided in Section B.6.1 of this Project Design Document.

B.5. Demonstration of additionality The table below is only applicable if the proposed project activity is a type of project activity which is deemed automatically additional, as defined by the applied approved methodology or standardized baseline. Specify the methodology or standardized baseline that establish automatic additionality for the proposed project activity (including the version number and the specific paragraph, if applicable).

Not applicable

Describe how the proposed project activity meets the criteria for automatic additionality in the relevant methodology or standardized baselines.

Not applicable

As per approved methodology ACM0002, the Project does not qualify in positive list for which the simplified procedure to demonstrate additionality is given, therefore, the additionality of the project activity has to be demonstrated and assessed using latest version of the “Tool for the demonstration and assessment of additionality” Version 7.0 as referred in approved methodology. Since the start date of the project activity is before the date of validation, the updated “Tool for the demonstration and assessment of additionality”, Chapter B of “Specific guidelines for completing the Project Design Document (CDM-PDD)” section B, sub-section B-5 and the requirements of paragraph 13 of Decision 17/CP.7 requires evidence that incentives from CDM were seriously considered in the decision to proceed with the project activity. The Project proponents, before the demonstration and assessment of additionality, demonstrate evidence as follows: Prior Consideration of CDM: The Project Start date is August 7, 2015 when the Construction Contract was executed for the construction of the Project and the project proponents have reiterated to notify the Designated National Authority (DNA) of Pakistan and the UNFCCC within 6 months of the start date i.e. January 14, 2016 about its intention to seek CDM status as per ‘guidelines on the demonstration and assessment of prior consideration of the CDM, Annex 13, EB 62’. The Project proponent earlier submitted its intention to seek CDM status as per ‘guidelines on the demonstration and assessment of prior consideration of the CDM’ on April 8, 2009. The UFCCC Secretariat posted the Project activity on UNFCCC website with following link: https://cdm.unfccc.int/Projects/PriorCDM/notifications/index_html The Private Power Infrastructure Board (PPIB) GOP provided Letter of Intent for development of the Project on March 12, 2005 and a Letter of Support on April 27, 2010 to the local sponsors after the completion of feasibility study and approval of first stage feasibility stage tariff from regulator. A Korean consortium led by Korea South East Power Co. Ltd. (KOSEP) acquired this virtually dormant project on December 19, 2012 in order to expeditiously develop the project. The Korean management reiterates its intention to develop the Project as CDM activity in the first Board meeting of Mira Power Limited with new Korean management.


https://cdm.unfccc.int/Projects/PriorCDM/notifications/index_html

CDM-PDD-FORM S/No. Key Milestones Dates

A. LOI Stage (Feasibility) 1. Letter of Intent 12-Mar-2005 2. Feasibility Approval by GOP 27-Apr-2006 3. Feasibility Stage Tariff (approval by NEPRA) 10-Feb-2009 4. Prior Consideration from UNFCCC 8-Apr-2009

B. LOS Stage (Development) 5. Letter of Support (1st Letter) 27-Apr-2010 6. Completion of Project Acquisition 19-Dec-2012 7. Completion of Revised Basic Design with new design 30-Apr-2014 8. NOC from AJK Wildlife & Fisheries 21-May-2014 9. Approval of Revised Design by POE PPIB 05-Jun-2014 10. Environmental NOC by AJK – EPA 18-Jun-2014 11. Approval of EPC Stage Tariff by NEPRA 03-Aug-2015 12. Execution of EPC Contract 07-Aug-2015 13. Execution of Power Purchase Agreement 3-Sep-2015 14. Approval of Power Purchase Agreement by NEPRA 28-Oct-2015 15. Financial Closing 30-Oct-2015 C. Construction Stage 16. Construction Start 01-Nov-2015

D. Operation Stage 17. Commercial Operations 30-Oct-2019

It is, therefore, concluded that CDM has been seriously being considered as an important factor, which had played a key role for the project owners to decide and proceed for the project investment. Additionality: The following section will demonstrate the additionality of the project activity which is not part of baseline scenario using the “Tool for the Demonstration and Assessment of Additionality” (version 7.0.0) by applying step wise approach as prescribed therein. The steps are:

• Step 0: Demonstration whether the project activity is the first-of-its-kind;

• Step 1: Identification of alternatives to the project activity consistent with mandatory laws and regulations; 1(a) define alternative to the project activity 1(b) consistency with mandatory laws and regulations

• Step 2: Investment analysis to determine that the proposed project activity is either: 1) not the most economically or financially attractive, or 2) not economically or financially feasible; 2(a) determine appropriate analysis method 2(b) Apply Benchmark Analysis (Option III)

• Step 3: Barriers analysis; and


CDM-PDD-FORM • Step 4: Common practice analysis.

Step 0: Demonstration whether the project activity is the first-of-its-kind; The Project is not first-of-its-kind in the applicable geographical area as there are already two hydro-based technology projects, registered with UNFCCC as CDM activity and one is in its commercial operations. STEP 1: IDENTIFICATION OF ALTERNATIVES TO THE PROJECT ACTIVITY CONSISTENT WITH MANDATORY LAWS AND REGULATIONS; Sub-Step 1(a) define alternative to the project activity: The realistic and credible alternative(s) available to the project participants that provide outputs or services comparable with the proposed CDM project activity include: Alternative (a): The Project activity undertaken without being registered as CDM project activity; Alternative (b): The Project activity is not undertaken and other alternatives are considered; and Alternative (c): The continuation of current situation (no project activity or alternative are undertaken).

Alternative (a): Without revenue from the CDM, the Project activity is in compliance with applicable legal and regulatory requirements, however, this will not be viable as elaborated in Step 2 (Investment Analysis) below. Moreover, the two projects of similar size in Pakistan could only be advanced for the development following their registration as CDM project activity. These include 84MW New Bong Escape Hydropower Project (in operation) and 150MW Patrind Hydropower Project (under construction) while other planned pipelined projects are also considering them as CDM project activities. Further, the investment to such projects are not mandatory, the investor may opt for options for thermal projects with lower project risks and short construction period like coal. Alternative (b): If the project activity is not implemented and other alternatives are considered. As the hydropower project is “site specific” and the project has been optimized based on hydrology, geology and ground condition, therefore, no other alternatives at project site for following reasons: (i) The remote location of the site in the mountains is not suited to conventional power

plants due to constraint of transportation of fossil fuel (oil, coal & gas) to such remote area and lack of availability of flat space & land in such area. Such conventional power plants are placed near the load centre, plain and easily accessible areas with lesser transportation cost.

(ii) The project site is not suited for other renewable energy projects like wind, solar or geothermal. The small renewable hydro plants do not provide comparable quantity of energy.

For years, the matter of balancing Pakistan’s supply against the demand of electricity has remained a largely unresolved matter. Pakistan needs around 15,000 to 20,000 MW electricity per day, however, currently it is able to produce only 11,500 MW per day, hence there is a shortfall of 4,000 to 9,000 MW per day. For a reliable system, around 2500 to 3000 MW generation capacity over and above already planned is needed every year keeping in view the growth rate of 7-8% in power demand. The project activity is “grid connected”, there may be alternative at other locations which can feed the same grid and substitute the generation from proposed project activity. The Project has been selected against the alternatives described below:


CDM-PDD-FORM (i) Steam Thermal Plant on Imported Coal:

The exploding oil prices affected the whole world and being unprepared Pakistan particularly got trapped as most of the steam thermal plants in Pakistan were based on imported furnace oil. In the current scenario of power shortages, the government has serious consideration and encouraging investors for new steam thermal plants on imported coal as well as retrofit of existing oil-based plant to be converted to coal. Several such projects are under consideration which includes; (a) 1320 MW Imported coal based Power Project at Qadarabad Dist Sahiwal (b) 1320 MW Imported coal based Power Project at Port Qasim, Karachi (c) 163MW imported coal based Power Project at Arifwala Punjab (d) 1320 MW Imported coal based Power Project at HUB Balochistan (e) 660 MW Imported coal based PowerProject near Port Qasim (f) 350 MW Imported coal based Power Project at Port Qasim Karachi

(ii) Steam Thermal Plant on Local Coal:

Pakistan has big coal reserves of 175 billion lignite coal 50 Billion TOE and want to tap this opportunity to resolve its power shortages. Several such projects are under consideration which includes: (a) 2 x 330 MW Thar Coal based Power Project by Engro Powergen Thar Limited

(Block-II) (b) 1320 MW Thar Coal based Power Project by Shangai Electric (Block-I) (c) 1320 MW Thar Coal based Power Project by Oracle Coal Field PLC England

(Block-VI) (d) 300 MW Local Coal based Power Project Punjab

(iii) Reciprocating Engines Operating on Furnace Oil Five thermal projects with a total capacity of 1,304 MW have been set up in private sector as IPP and Rental Power Plants. The Projects started generation after June 30, 2010. These includes Hubco Narowal (220 MW), Nishat Chunian (200 MW), Nishat Power (200 MW), Halmore Power (200 MW) and Attock Gen (165 MW) as thermal IPP. These RFO plants run using standardize reciprocating engine technology are smaller in size, cheaper to finance and construct and shortest gestation period providing strong investor interest despite high cost of fuel, expensive electricity and government discouragement. These projects were initiated as government was left with no choice to mitigate power shortages and blackouts.

(iv) Combine Cycle on Natural Gas/Diesel After June 30, 2010, six new power plants started generation which includes Saif Power Sahiwal (229 MW), Orient Power (229 MW), Saphire Power (225 MW), Halmore Power (225 MW) and Foundation Power (185) as thermal IPP. Due to shortage of gas, these projects are forced to operate on diesel in winter while operate on gas in summer if gas is available and come out to be very expensive.

(v) Implementation of Equivalent Capacity Renewable Power Plants (Wind) The Government of Pakistan through Alternate Energy Development Board (AEDB) is promoting the development of small renewable energy projects in Pakistan which includes wind power. Following commercial operations of six projects of approximately 50 MW each and ten other projects in construction phase, the pace has become slow due to different constraints/barriers faced by investors that includes acquisition of land and lack of capacity for interconnection with national grid. Projects are facing it difficult to opt for upfront tariff announced by NEPRA. These wind power projects under development also suffer due to location in south of the country which is far from load centre, lack of transmission infrastructure and intermittent nature of supply. Due to above and moreover due to low capacity of such project, a number of projects will not be able to come on the grid.


CDM-PDD-FORM (vi) Hydropower

The Government of Pakistan has announced several projects under Policy for Development of Hydropower 1995 and Power Policy 2002, however, only one project namely 84 MW New Bong Escape Hydropower Project could enter into operation phase after lapse of more than twenty years. Currently, there are 4,995 of hydropower projects which are at various stages of project development and only one Project of 84 MW New Bong Escape Hydropower Project after lapse of 17 years could achieve financial close and achieve Commercial Operations in 2013. The remaining projects are either struggling for financial close or issuance of LOS from Government of Pakistan. These includes Patrind Hydropower Project (150 MW), Kotli (100 MW), Sehra (130 MW), Rajdhani (132 MW), Karot (720 MW), Azad Pattan (640 MW), Kohala (1100 MW), Chakothi Hattian (500 MW), Asrat Kadam (215 MW), Madian (157 MW), Suki Kinari (840 MW) and Kaigha (548 MW). With pressing electricity demand, this is highly unsatisfactory state of affairs but is mainly caused by the high upfront capital cost compared with thermal projects, difficulty of achieving financial close, institutional neglect and dysfunctional policy which has plagued the private hydropower sector.

Alternative (c): The continuation of current situation (no project activity or alternative are undertaken). The country is facing huge power shortages starting from 1,000 MW in 2006 and its persistence till now increased to 5,000 MW and economy is adversely impacted by power, gas woes due to persistent power and gas outage. In Punjab only, over 200,000 families directly or indirectly negatively affected and 40% of Pakistan textile industry have been shifted to Bangladesh in last five years. It is safely deduced that the continuation of current situation is impossible and government will have to exercise all options to add capacity to its grid in order to fulfill the energy requirements. Non-implementation of the Projects will make it imperative for the Government to plan and implement an alternative fossil fuel intensive thermal project (which is the baseline scenario). In this situation the national grid will be deprived of ecologically friendly and non-polluting hydropower.

Outcome of Step 1a: Realistic and credible alternative scenario identified above is the Alternative b(iii), b(iv), b(v) and b(vi) (thermal based) and implementation of equivalent capacity fossil fueled Thermal Plants which is baseline scenario for the purposes of calculation of emission reduction. Sub-Step 1b: Consistency with mandatory laws and regulations: All the above referred alternatives are in accordance with mandatory applicable legal and regulatory requirements that include Power Policy 2002 prevailing in the country, NEPRA Act 1997, Rules, Regulations and government announcements. Outcome of Step 1b: The alternatives referred above are in accordance with laws and regulations, therefore, the proposed project activity is in competition with alternatives narrated above for electricity generation through fossil fuelled fired thermal plants and project emits zero GHG emissions at highest capital cost of generation compared with thermal plants. The applied tool i.e. “Tool for the Demonstration and Assessment of Additionality” (version 7.0) provides that the Project participants can use either Investment Analysis or Barrier Analysis step OR they may, if they so wish, use both Investment and Barrier Analysis steps. To demonstrate and assess the additionality for proposed project activity, the project participants have decided to use both Investment and Barrier Analysis. Therefore, we will proceed to Step 2 (Investment Analysis) and subsequently to Step 3 (Barrier Analysis) in following portion of the document.


CDM-PDD-FORM STEP 2: INVESTMENT ANALYSIS;

Sub-step 2a: Determine appropriate analysis method

The additionality tool provides following three investment analysis options: (a) Option I: Simple Cost analysis (b) Option II: Investment comparison analysis (c) Option III: Benchmark analysis All the above options were considered to prove additionality. The Option I is not applicable as the Project activity will be developed as an Independent Power Producer (IPP) to generate revenues from sale of electricity to National Grid. With regard to choosing of option from II & III, the Benchmark analysis has been preferred due to the factor that the project participants while evaluating the project apply Benchmark analysis to evaluate the project with or without benefit of CDM revenue. Sub-step 2b: Option III – Apply Benchmark Analysis The financial/economic indicator Internal Rate of Return (IRR) of equity is the most suitable for the project type and decision context. The same indicator is also used for equity partners for evaluation of their investment. The additionality tool also prescribed that the Project IRR is used to analyse the financial situation of the Project. Benchmarks (a) The investment analysis has been undertaken in compliance with Methodological Tool

EB85 Annex 12 - “Investment Analysis, Version 6.0”. In order to determine the most suitable benchmark in real terms that is comparable to the project’s IRR, the default value defined in Appendix A – Methodological Tool: Investment analysis (version 06) and the default value for the expected return on equity for Pakistan has been set to 19.05% for Group 1 (Energy Industries).

(b) The benchmark can also be derived from paragraph 38(d) of the Tool for the

demonstration and assessment of additionality –

“(6) Discount rates and benchmarks shall be derived from:

(d) Government/official approved benchmark where such benchmarks are used for investment decisions.”

(i) Alternative b(viii): The hydropower projects developed as an IPP similar to

Project activity are given 17% IRR only one project namely 84 MW New Bong Escape Hydropower Project could enter into operation phase after lapse of more than twenty years despite availability of several hydropower options in the market. Even above referred project could achieve better IRR by registering it as CDM activity.

(ii) Alternative b(iv): The competing technology option available as an IPP planned by government is thermal projects based on indigenous coal are provided IRR of above 20%.

(iii) Alternative b(iii): The thermal projects based on imported coal option available

as an IPP planned by government is provided IRR of above 17% despite the projects are low risks, less capital intensive and shorter construction period compared with hydropower projects.


CDM-PDD-FORM (iv) Alternative b(v) & b(vi): The options for thermal projects based on furnace oil

and gas, despite benchmark of 15%, are no more available to investors due to government’s bad experience of fluctuating the oil prices and non-availability/shortage of gas in the country.

(v) Alternative b(vii): The options for renewable technologies like based on wind

provided benchmark of 17%, however, the options are no more available for investors due to non-availability of land and lack of transmission infrastructure and intermittent nature of supply.

(vi) Alternative b(v) & b(vi): The options for thermal projects based on furnace oil

and gas, despite benchmark of 15%, are no more available to investors due to government’s bad experience of fluctuating the oil prices and non-availability/shortage of gas in the country.

The practical benchmark can safely be considered through alternative b(iv) through indigenous resources (coal) which are largely available in Pakistan i.e. the reserves of 175 billion lignite coal available in Thar Pakistan for which 20% of IRR is provided by government whereas hydropower which is equally “indigenous” is only allowed 17%.

Conservatively, we have selected default value for the expected return on equity for Pakistan has been set to 19.05% for Group 1 (Energy Industries) as benchmark.

Sub-step 2c: Calculation and comparison of financial indicators

Scenario IRR Gulpur Hydropower Project (NEPRA approved without CDM) 16.27% NEPRA’s Benchmark 17% Benchmark 19.05%

The tariff for power projects in Pakistan is determined by the regulatory (NEPRA) based on cost plus scenario measured against certain benchmarks and comparable projects. Following completion of competitive bidding process for selection of EPC Contractor and arrangements of financing from multilateral financial institutions, the Project Sponsors applied for approval of EPC Stage tariff from NEPRA who determine tariff on the basis of 17% return on equity against the demand of 20% IRR from Sponsors. However, NEPRA has approved the tariff which yields 16.27% return on equity as it has not approved return on equity during development period (30 months) while the same was approved to the only project which is in operation (New Bong Escape Hydropower Project). Based on the approved tariff, the Company signed a long term Power Purchase Agreement for 30 years term following which the Project will be transferred to Government without any cost being a BOOT project. The approved tariff details and financials are as follows:

Items Details Financial Details

Project Capital Cost US $ 317.627 Millions Project Installed Capacity 102.0 MW Project Term 30 years from Commercial Operation

date Auxiliary Consumption 1% Project Net Capacity 100.98 MW Net Saleable Energy 474.996 GWh Funding Plan Debt 75% : Equity 25% Equity US$ 79.407 millions


CDM-PDD-FORM Long Term Debt US$ 238.220 millions Construction Period 48 months Interest Rate (LIBOR + spread of 500 bps)

0. 35+5.0 = 5.35 (Bi-annual)

Debt Repayment Period 12 years after COD NPV Discount Rate 10% Lenders A syndicate of international

development financial institutions which includes IFC, ADB, K-EXIM and CDC UK

Financial Results

Actual Hurdle Rate IRR – without CDM revenue 16.27% 19.05% IRR – with CDM revenue 17.15% 19.05%

The details of NEPRA’s approved Capital Cost & Operational Costs are as follows:

CAPITAL COST

Item Amount (USD million)

Civil works cost 150.202 Electrical & Mechanical works 84.214 Architectural works 1.484 Reference EPC Cost 235.90 Custom Duty 3.6 Insurance During Construction 4.718 Feasibility & Technical Studies 2.000 Project Advisors & Agents 4.727 Administration 7.240 Owners Engineer 9.000 Engineering & Design Cost 9.100 Management Supervision 3.000 Re-opener Verifier /Independent Engineer 0.360 O&M mobilization cost 2.240 Lenders' Financing Fees & Charges 6.468 Environmental Costs 1.610 Resettlement & Rehabilitation Costs 3.960 Interest During Construction 23.704 Total Project Cost (the “Capital Cost”) 317.627

OPERATIONAL COSTS

Item Amount (USD million/Annum)

Variable O&M 0.200 Water Use Charge 0.705 Fixed O&M – Local 1.800 Fixed O&M – Foreign 2.200 Insurance during Operations 1.533


CDM-PDD-FORM Based on above referred NEPRA’s approved costs, the Project Company is allowed to charge following Levelized tariff for delivery of electricity to the Power Purchaser:

Tariff Component Levelized Tariff US ¢ /KWh

Variable Charges (Energy Purchase Price)

Water Use Charges 0.1431 Variable O&M 0.0421 Sub Total 0.1852 Fixed Charges (Capacity Purchase Price) Fixed O&M 0.8421 Insurance 0.3228 ROE 2.8916 ROEDC 0.6500 Debt Service Component 4.1324 Sub Total 8.8389 Levelized Tariff 9.0241

As the Financial Benchmark revealed that the project activity has a less favourable indicator i.e. lower IRR than the benchmark, then the CDM project activity cannot be considered as financially attractive. Sub-step 2d: Sensitivity Analysis A sensitivity analysis was conducted by altering the following parameters in order to show that the conclusion of the benchmark analysis is robust to reasonable variations in the critical assumptions:

• Electricity generation; • O&M costs (total); • Price for Available Power and Power Generation of PPA • Investment;

These parameters were selected as they are the most likely to fluctuate over time and can significantly affect the financial attractiveness of the Project. The sensitivity analysis was performed by altering these parameters enough to reach the benchmark. Then the output value of the alteration for each parameter was compared with the most maximum variation value which is supported by official contracts, articles or technical data. If the maximum variation value for any parameter is higher than the alteration necessary to make the project feasible, there is a possible scenario that makes the Project feasible. The table below presents the results of the sensitivity analysis.

Parameter IRR with

minimum variation (-10%)

No Variation

(0%)

IRR with maximum

variation (+10%)

Benchmark

Electricity Generation 16.20% 16.27% 16.30% 19.05% O&M Cost (Total) 15.95% 16.27% 16.58% 19.05% Price for Available Power and Power Generation of PPA

- 16.27% - 19.05%

Investment 12.24% 16.27% - 19.05%

The seriatim analysis of above variation is as follows:


CDM-PDD-FORM (i) Electricity Generation: The variation in generation has minimal impact on IRR as

Power Purchase Agreement executed by Company has assured minimum monthly amount every month. The Power Purchaser has absorbed the hydrological risk as only smaller portion of tariff fluctuates with generation i.e. Variable O&M and Water Use Payment, therefore, any decrease in generation due to hydrology and excessive generation above the Average Energy will be at account of Power Purchaser and Project IRR would hardly have any impact. It is also highlighted that the Average Energy is based on hydrology (flow data) for the period of 50 years. Therefore, a significant change in average annual power generation of the project during the operating period is not likely to occur.

(ii) O&M Cost: The hydropower project entails lower operational costs and does only have marginal impact on IRR with regard to an increase or decrease of 10% of O&M costs. Moreover, the O&M Contract for hydropower are usually based on a fixed fee, therefore, it is unlikely and difficult to adjust the O&M Cost to raise the Project IRR.

(iii) Investment The NEPRA approved tariff (EPC Stage) is subject to adjustment at Commercial Operations Date and provided in the executed Power Purchase Agreement through NEPRA’s approved mechanism for Determination of Tariff for Hydropower Projects (the “Mechanism”). The approved tariff includes provision for cost variation through change in tariff for hydropower projects that includes coverage for currency fluctuation, and escalations and variations for geology, civil work, hydraulic steel structure and resettlement cost on the terms provided in the mechanism. The project construction arrangements are also based on tightly structured Construction contract executed with Joint Venture of Daelim-Lottee, where the price of the Project is determined and Company must pay at least the price stipulated in the Construction contract. The only way that the investment amount denominated USD suffers a reduction is through devaluation of the Pakistan Currency or through decrease of material prices. The Construction Contract recognizes price adjustment (i.e. inflation and currency fluctuation) of major materials during the construction cycle and similar arrangements.

(iv) Price for Available Power and Power Generation of PPA: The Project will

receives through the PPA the incomes: (i) Fixed income for Available Power; (ii) Fixed income for O&M Costs, (iii) Fixed Income from generation for Administration, (iv) Variable Income from generation for Operation. These incomes are fixed for a period of 30 years (PPA duration). The Company is allowed certain outages that include scheduled outages and forced outages and guarantee payment for not generating due to non-availability of power. Under the scenario of +10% for Available Power or Power Generation, there is no impact on IRR as Company is only compensated in terms of variable O&M and Water Use Charges which will be passed on to O&M Operator and government respectively. In case of non-availability of plant and power generation for the reasons other than non-availability of power, the Company will be obligated to pay liquidated damages equal to 110% of capacity payment which will hit IRR of the Sponsors.

For each parameter, the IRR remains below the benchmark when the maximum variation is applied.

Outcome of Step 2: It can, therefore, safely be concluded that the Project is not commercially viable without CDM revenue and returns and financial indicators will render the Project un-fundable and it would be close to impossible to attract equity investment into an enterprise with high country and project risk


CDM-PDD-FORM while returns are low; implementation is thus dependent on CDM registration. Thus, project activity indicates that the proposed project activity is additional. Notwithstanding the foregoing, the project participant would also like to perform Barrier Analysis faced by the project activity in following section. STEP 3: BARRIER ANALYSIS; The latest version of the “Tool for the demonstration and assessment of additionality” states that project participants may choose to apply Step 2 (Investment Analysis), OR Step 3 (Barrier Analysis) to demonstrate Project additionality. The objective of the barrier analysis is to determine whether the proposed project activity faces barriers that: (a) Prevent the implementation of this type of proposed project activity; and (b) Do not prevent the implementation of at least one of the alternatives. It may please be appreciated that the Investment Analysis was sufficient to demonstrate additionality, but the barriers faced also provide cogent grounds for demonstration of additionality as they prevent potential project proponents from carrying out the proposed project activity from occurring without being registered as a CDM project activity. For the purpose, the latest approved version of “Guidelines for objective demonstration and assessment of barriers” Version 1, available on UNFCCC website, is taken in account when applying the following sub-steps:

Sub-step 3a: Identify barriers that would prevent the implementation of the proposed CDM project activity:

There are realistic and credible barriers that would prevent the implementation of proposed project activity from being carried out if the project activity is not registered as a CDM activity. Such realistic and credible barriers include, amongst others discussed in Step 2 above, and are elaborated in following paragraphs. The dilemma of Pakistan Power Sector has been that it not only failed to make additions in the generation capacity despite of having identified potential of around 40,000 MW hydropower, whereas the installed hydel power capacity of Pakistan at the end of fiscal year 2015 was 7,116 MW. The share of existing hydel power installed capacity to the total installed generation capacity of the country is only 28.67% while this share in year 1985 was around 67%. Most of the installed hydel power capacity of the country (19 hydropower plants) despatching electricity to national grid are owned by public sector (WAPDA) and only there exist a single private sector power plant (84 MW New Bong Escape) which is in operation phase and started due to its registration as CDM Project activity. The above referred trend of more participation by private sector in thermal based power generation compared with hydro generation is due to the barriers faced by them which mainly result from specific financing constraints and from a higher risk profile. These, inter-alia, includes investment barriers for non-recourse and long tenure financing to mitigate impact on tariff, high upfront capital cost, completion risk, country risk, geological risk, civil work risk, scheduling risk etc. These are explained hereunder:

i. High front-end Costs (Capital Cost) The construction cost of a hydropower plant is typically 100 to 200% more than a thermal power station on a $/kW basis. The gap is magnified by the so called “soft-costs” for project preparation, which are greater for hydro as they also include costs for Environmental Impact Assessment. In addition, local costs for civil works have high portion (around 40-50%) that is not eligible for export credits. These high costs of capital lead to scarcity of financial resources for the hydro power project development,


CDM-PDD-FORM originated by the perception of Pakistan as a risky country by foreign investors. These are elaborated in following paras: (i) Country risk

The country risks generally constitute the creditworthiness of a country. They result from uncertainty about the economic, political and socio-cultural situation of a country and are not influenced by private investors. This may be measured by sovereign ratings of International Credit Rating Agencies. The ratings by “the Political Risk Survey (PRS) Group” show the data for relative risk of country with respect to other Asian countries. The countries within range of 51-100 are declared as less risk and from 0-49 as high risk countries by PRS. The data is reproduced below:

CURRENT RISK RATINGS AND COMPOSITE RISK FORECASTS

CURRENT RATINGS COMPOSITE

RATINGS

Political Financial Economic Year

Risk Risk Risk Ago Current COUNTRY 01/15 01/15 01/15 02/14 01/15 China, Peoples' Rep. 56.5 47.5 40.0 73.3 72.0 India 61.0 43.0 33.5 65.8 68.8 Indonesia 57.5 41.0 35.5 65.5 67.0 Iran 53.5 35.5 33.5 63.0 61.3 Japan 82.5 40.5 36.0 81.5 79.5 Korea, Republic 77.0 42.5 43.5 82.0 81.5 Malaysia 74.0 42.5 40.5 77.5 78.5 Pakistan 48.5 37.5 30.5 61.3 58.3 Philippines 60.5 45.0 39.0 71.8 72.3 Saudi Arabia 64.5 48.0 45.0 80.8 78.8 Singapore 82.0 45.0 46.5 87.3 86.8 Sri Lanka 57.0 36.0 34.0 62.5 63.5 Taiwan 76.5 45.5 44.0 82.8 83.0 Thailand 54.5 42.5 37.0 67.5 67.0 Source: http://epub.prsgroup.com/icrg-tables

(ii) Foreign Direct Investment

Government of Pakistan always seek foreign investment and investment liberalization initiatives begin in 1992 and progressively opened Pakistan to foreign investment, offering broad arrays of incentives to attract new capital inflows.

Notwithstanding this pro-investment stance, foreign direct investment activity remains relatively modest due to significant security threats for foreign interests in Pakistan, concerns about political instability, inadequate infrastructure, delays in privatization of state-owned enterprises, past protracted disputes between foreign investors and government, piracy of intellectual property, arbitrary and non-transparent application of government regulations and resistance to the adoption of new policies by some elements of federal and provincial bureaucracies who have not yet fully adjusted to the new, more open economic environment.

The situation has deteriorated more during past five years due to intensified terror attacks, global economic crisis and energy crisis in Pakistan has led to


http://epub.prsgroup.com/icrg-tables

CDM-PDD-FORM flight of capital and scared away the investors. The FDI shrink and dropped to the level of US$ 1 billion in 2011-14 against above US$ 3 billion for the corresponding period of last five year. All these factors created perceptions of Pakistan as a high risk country, resulting in low levels of foreign investment, particularly in the capital intensive electric, gas and water projects and same can be viewed in the Tables below:

FOREIGN DIRECT INVESTMENT MAJOR COUNTRIES OF ASIA

(US $ Billions) Country 2011 2012 2013 2014

China

280.07

241.21

290.23

289.10

India

36.50

23.99

28.15

33.87 Indonesia 20.56 21.20 23.28 26.35

Iran, Islamic Rep. of

4.28

4.66

3.05 2.10

Japan

-0.850

0.55

7.41

9.07

Korea, Rep. of

9.77 9.50

12.77

9.90

Malaysia

15.12

8.90

11.30

10.61

Pakistan

1.33

0.86

1.33 1.78

Philippines 2.01

3.22

3.74 6.20

Singapore

48.00

56.66

64.79

67.52

Sri Lanka

0.96

0.94 0.93 0.94

Thailand

2.47

12.89

15.82 3.72 Source: http://data.worldbank.org/indicator/BX.KLT.DINV.CD.WD/countries

ii. Construction Risk The principal construction risk in hydro projects arises from geological conditions, scheduling/project completion risk, civil works risk and non-recourse risk. This encompasses a wide range of issues (such as slope stability, ground treatment, depth of excavation, rock support), any of which can have a major influence on both the schedule and final costs. Although geological risks have been mitigated by careful selection of the site and project layout, and by adequate advanced site investigation and shall be covered in a tight turn-key EPC contract, it is inevitably a factor in the construction of the project activity. The capital-intensive nature of hydro means that the potential losses of developers through construction delays can be very large, to the point where it becomes difficult to cover them by contractual penalties or insurance. For example, a 300 MW project operating at a 65 percent capacity factor will be generating about 140 gig watt-hours (GWh) per month, worth perhaps $10 million a month in revenue. A six-month delay on completion, resulting from a 15 percent overrun on schedule, would represent a loss of $50 million, which would be nearing the acceptable limit of liquidated damages for most contractors on a project of this size.


http://data.worldbank.org/indicator/BX.KLT.DINV.CD.WD/countries

CDM-PDD-FORM

iii. Environmental Risk Lenders and guarantors are highly sensitized on environmental issues, and they invariably require that a project meets not only local environmental permitting requirements but also acceptable international norms as defined by organizations such as the World Bank, Asian Development Bank and other donor agencies.

In the case of hydro schemes the environmental issues can be complex, and they will vary substantially between projects. Storage schemes, in particular, tend to be sensitive if they involve resettlement or the loss of rare habitat. In the past, promoters have generally been left to obtain their own environmental clearances. This can be a time-consuming and expensive business, and it represents another area of unwelcome risk and delay as far as the private developer is concerned. The cost of environmental mitigation is invariably borne by the project.

iv. Financing Constraints – Non recourse Risk Hydropower projects are usually high capital-intensive, and in consequence a very large portion of very large proportion of the tariff during the debt-servicing period is attributable to capital charges. This is a marked contrast to thermal IPP plants where fuel, operation and maintenance costs constitute perhaps half the tariff. In making a comparison between the two this creates a number of adverse impacts on hydro, in particular: • The capital sums that have to be raised for hydro are proportionately much larger • The increased cost of capital that comes from private financing is magnified to a

greater extent with hydro because the costs are dominated by capital charges; and • Cost-based tariff profiles result in high up front prices with minimal escalation, which

appears unfavorable in comparison with thermal where there is a lower base cost but a much greater escalating element in the tariff reflecting fuel and O&M.

In developing countries, it is common for project lenders to establish a security interest in the Project’s assets. Typically the security interest gives the lenders the ability to foreclose on the security and remove project assets in the event of a default on the project loan. This is a viable option for lenders in situations where capacity increments are satisfied by thermal generation units – combustion turbines or reciprocating engines are relatively easy to relocate. In the case of the Project, this obviously was not an option - the Project assets are specifically made for the Project and are immovable, therefore the assets have very little salvage value. In the event of a default, lender recourse is limited to either operate or not operate the Project, or sell it as a distressed asset.

v. Regulatory Issues / Institutional Barriers Private hydropower in Pakistan has had a very mixed past. Hydropower development has been the sole prerogative of the public sector that has focused more on mega dam/storage projects and in its time Pakistan has constructed some of the largest dams in the world e.g. Mangla, Tarbela and Warsak which total approx 4,700 MW represented over 70% of the total developed hydropower capacity in Pakistan. Private power developers were invited to participate in power project development under the 1994 Power Policy; however, the policy attracted interest only from thermal power developers. Fourteen projects totalling over 3,000 MW came on ground but not a single application was received for hydropower. In 1995 in an attempt to attract interest from hydropower developers the Government brought out the “Policy Framework and Package of Incentives for Private Sector Hydel Power Generation Projects in Pakistan”; dated May 1995.


CDM-PDD-FORM Letters of support were issued for some 29 hydropower projects totalling 1,684 MW allowing sponsors to complete feasibility studies, design, finance and construct the projects; however, in the past 20 years not a single hydropower project could come on stream except to one hydropower project i.e. 84 MW New Bong Escape which is due to its registration as CDM activity. The major reason for this failure was the refusal of the power purchaser to offer a commercially reasonable tariff and the barriers enumerated above. Private hydropower projects pose a number of specific regulatory issues that arise from the fact that hydro entails the exploitation of unique natural resources which would generally be regarded as the property of the state and it often needs significant public sector involvement to ensure that projects are commercially viable and consistent with wider development objectives. Unlike thermal power projects, which can be built and operated essentially in isolation, an individual hydro scheme has to be seen in the broader context of the river basin where there may be multiple water uses and other hydropower projects to be considered. The Suki Kinari hydropower project in Pakistan faced similar barrier where Govt. of Khyber Pakhtoon Khawa claimed to develop the project as multi-purpose dam project for irrigation and power. The matter becomes sub-judice before court of law for at least four years.

vi. Transmission Constraints: Unlike a run-of-river hydro project, thermal power plants enjoy considerable flexibility for choosing an optimal project site. One of the primary criteria used in site selection is access to suitable transmission, with good routing alternatives. Constraints have been reported in the Extra High Voltage (EHV) transmission and transformation system which have resulted in partial outages as well as blackouts of the power supply on a number of occasions to large part of the country. It has been noted that EHV transmission line tripping due to forced outages increased from 29 in 2006-07 to 80 in 2009-10, point to a deteriorating reliability in the system. It is also noted that a number of new IPPs could not undergo commissioning tests as the interconnection transmission networks were either not available or had inadequate capacity. Such constraints have added to the shortages in power supply position.

vii. Technological Barriers Skilled and/or properly trained labour to operate and maintain the technology is not easily available. Though Pakistan has significant public sector hydropower projects there is a large local resource of trained manpower, however, it is very difficult to relocate experienced people from Government jobs.

viii. Barriers due to prevailing practice It is to be noted that the practice prevailing in the country is installation of fossil fueled fired thermal and coal power plants. The Project activity is one from the private sector activity and all running project activities relating to hydro are in currently owned by Public Sector and investors/lenders prefer to invest in thermal power generation projects. Both of these activities have different project profiles and risk perception.

Outcome of Step 3a: The above referred barriers would prevent implementation of the proposed CDM project activity. The Barriers including country risk, lack of FDI, lack of capital for private investment, transmission risk, environmental constraint, and technological barriers may prevent some of the alternatives to the project activity but they prevent less strongly to alternatives than the subject project activity.


CDM-PDD-FORM Sub-step 3 b: Show that the identified barriers would not prevent the implementation of at least one of the alternatives (except the proposed project activity): In this section we will demonstrate that while some of same barriers generally exist for alternative projects, however, their influence on those projects is greatly reduced and in most cases non-existent.

a) High Cost of Capital While it is acknowledged that all infrastructure projects in Pakistan are affected by the country risk, scarce foreign direct investment and local savings, the degree of risk varies from project to project. Projects that are less capital intensive and have shorter development and construction period are less prone to effects of such risks. Alternative projects in Pakistan are less capital intensive on per kilowatt basis (thermal projects can be set up at half or one-third of the cost), and can be put into operation much more quickly than run-of-river hydropower project, thereby, lowering their exposure to country risk.

b) Financing Barriers Hydropower projects are also characterized by a relative high risk profile, which exacerbates the financial constraint. Due to the nature of the works delays and significant cost increases can occur in the construction phase. Prominent importance is attached to potential delays, heavy costs and even cancellations arising from environmental and resettlement issues. Adopting governmental recommendations on an appropriate environmental and social framework for the construction of such projects can mitigate these risks but will also likely add to the high up-front costs. The high risk exposure implies high interest rates and/or short pay-back periods and finally unacceptably high tariffs, so that the competitiveness of hydropower plants is affected. It has to be highlighted that the competition is distorted by the fact that hydro is required to internalize all its environmental mitigation and similar costs (resettlement etc.) whereas there is usually no carbon tax or similar charges levied for the environmental impact of fossil fuel generation.

c) Institutional Barriers Unlike hydropower for which tariff was non-existent/suspend for a decade, alternative thermal projects in Pakistan had a well-established tariff framework during this period. From 1994 to 2002, tariff under Power Policy 1994 was available to such thermal projects and some 15 IPPs were commissioned in Pakistan during this period. From 2002 onward the Power Policy 2002 provided tariff guidelines and the regulator, NEPRA announced upfront as well as cost-plus tariffs of around 11 alternative thermal projects during this period. Two of these thermal projects based on combined cycle gas technology have already achieved financial close, with others are expected shortly.

d) Geological/Civil Risk Hydropower projects by their nature subject the Owner and Constructor of the works to considerable risk during development. The uncertainty of operating in a geotechnical environment, underground structures with attendant uncertainties, construction floods, the complex construction logistics and methods involved, and the large and expensive machinery engaged, all contribute to a high risk environment. Delays and cost overruns occur at an unfortunately regular frequency, particularly in tunnelling and dam foundations. The Gulpur Hydropower Project also faced broad range of risks for Owner and Constructor during construction and implementation phase. These risks include environmental issues as the Project is located in National Park and requires establishment of Net Gain in biodiversity of the river and endangered species.


CDM-PDD-FORM Underground flood controls, diversion of existing river, de-watering, tunnelling and dam foundation are major risks. On the other hand, thermal projects are not exposed to any civil/geological risks and have a relatively low content of civil works. Such projects not only enjoy easy site access but typically present few challenges with regard to site topography and conformation. Civil works are largely a matter of clearing and grading.

e) Scheduling/Project Completion Risk The time period to develop and construct an alternative thermal project is significantly less than that required to develop and construct a hydropower project. A typical simple cycle thermal project can be developed in 3 years including construction, whereas a hydropower project could take 8-10 years. Consequently risk associated with time is significantly reduced. Similarly hydropower projects under public sector are not under obligation to complete the project in given timeframe as required for this project.

f) Non-Recourse risk

Alternative thermal projects, especially the simple cycle projects provide lenders with tangible assets that can be pledged as security and seized and relocated in the event of default. The combustion turbine/power island represents the majority of project assets. The class of turbines typically used to provide incremental capacity in Pakistan is relatively easy to relocate. This provides lenders with a recourse option unavailable to those who fund a hydro project, and lowers the overall project risk profile accordingly.

g) Transmission

Unlike a run-of-river hydro project, thermal power plants enjoy considerable flexibility for choosing an optimal project site. For thermal projects, one of the primary criteria used in site selection is access to suitable transmission, with good routing alternatives. It would be rare and generally unnecessary for any of the alternative project to face a radial line outage risk of the type dictated by the location of the Gulpur Hydropower project.

As the risk analysis amply demonstrates, the various risk-related barriers identified for hydropower projects including Gulpur Hydropower Project have much less impact on the alternative thermal plants in every case. To our knowledge, no alternative project in Pakistan has been or should be prevented from implementation due to barriers identified in this review. On the other hand, all the identified risks not only have the potential to significantly impact hydropower development but might actually and practically impact the development of Gulpur Hydropower Project.

Outcome of Step 3: The analysis conducted above concluded that the risks identified above have imposed barriers on viability of the project and Gulpur Hydropower Project is subject to barriers that have had a material influence in the financing and overall development, construction and operation of the Project. At the same time, alternative power generation projects in Pakistan, namely thermal (oil and natural gas fired projects) do not face the same degree of exposure or have the same level of impact causing inability for them to be implemented. As both sub-step 3a & 3b are satisfied, we will now proceed to Step 4 (Common Practice Analysis). STEP 4: COMMON PRACTICE ANALYSIS; The Section 4.5 of latest version of the “Tool for demonstration and assessment of additionality” Version 7 states that this additionality test is a “Credibility Check” to complement the Investment Analysis or Barrier Analysis performed above. Moreover, the latest version of the Methodological


CDM-PDD-FORM tool: Tool24 - Common practice Version 3.1 available on the UNFCCC website shall be applied for Step 4a (below) as required in the additionality tool. According to the additionality tool, the following steps are needed to be taken for common practice analysis: Sub-step 4a: The proposed CDM project activity(ies) applies measure(s) that are listed in the definitions section above According to common practice tool, the following step-wise approach for common practice shall apply:

Step 1: Calculate applicable capacity or output range as +/-50% of the total design capacity or output of the proposed project activity. The applicable range would be 51 MW – 153 MW. Step 2: identify similar projects (both CDM and non-CDM) which fulfil all of the following conditions:

(a) The projects are located in the applicable geographical area; (b) The projects apply the same measure as the proposed project activity; (c) The projects use the same energy source/fuel and feedstock as the

proposed project activity, if a technology switch measure is implemented by the proposed project activity;

(d) The plants in which the projects are implemented produce goods or services with comparable quality, properties and applications areas (e.g. clinker) as the proposed project plant;

(e) The capacity or output of the projects is within the applicable capacity or output range calculated in Step 1;

(f) The projects started commercial operation before the project design document (CDM-PDD) is published for global stakeholder consultation or before the start date of proposed project activity, whichever is earlier for the proposed project activity.

According to the above referred conditions; following six projects, with applicable range/capacity and similar energy source, have started commercial operations before the start date of proposed project activity:

S/No. Name MW Type of Plant

Location Development Mode

1. Khan Khwar 72 Reservoir Shangla, KPK Public Sector

2. Allai Khwar 121 Reservoir Battagram, KPK Public Sector

3. Jinnah 96 Run-of-River Mianwali, Punjab Public Sector

4. Duber Khwar 130 Reservoir Kohistan, KPK Public Sector

5. Malakand-III 81 Run-of-River Malakand, KPK Public Sector

6. Laraib Energy 84 Run-of-River AJ&K Private Sector

Step 3: within the projects identified in Step 2, identify those that are neither registered CDM project activities, project activities submitted for registration, nor project activities undergoing validation. Note their number Nall. Five of above referred projects are neither registered as CDM project activity nor in process of validation or registration as CDM activity. Therefore, Nall = 5.


CDM-PDD-FORM Step 4: within similar projects identified in Step 3, identify those that apply technologies that are different to the technology applied in the proposed project activity. Note their number Ndiff. There is essential distinction between the proposed Project and the hydroelectric power plants mentioned in Step 3. As per Additionality Tool, “essential distinctions may include a serious change in circumstances under which the proposed CDM project activity will be implemented when compared to circumstances under which similar projects were carried out”. These projects were constructed under a completely different investment environment, regulatory framework and access to financing; compared to the proposed project activity which is being developed under private sector. In these public sector projects, the State made it possible to finance hydro projects through the investment of funds from the National Treasury, and in other cases, through the aid of international funding organizations. While the proposed Project is being developed as an Independent Power Producer (IPP) in private sector under the Government Policy for Power Generation Projects, 2002. The policy for private sector in Pakistan has been in placed from last 20 years starting from 1995 Hydel Policy and only one project (84 MW New Bong Escape Hydropower Project) could achieve commercial operations out of some 5,000 MW LOIs/LOS issued by Government of Pakistan and that is only due to its registration as CDM activity. Therefore, Ndiff = 5. Step 5: calculate factor F=1-Ndiff/Nall representing the share of similar projects (penetration rate of the measure/technology) using a measure/technology similar to the measure/technology used in the proposed project activity that deliver the same output or capacity as the proposed project activity. Calculation of the factor F = 1 - Ndiff/Nall = 1- 5/5 = 0

The proposed project cannot be considered common practice and should be deemed additional according to the “Tool for the demonstration and assessment of additionality” (version 07.0), because both conditions are fulfilled: the factor F is smaller than 0.2 (F = 0) and Ndiff-Nall is smaller than 3 (Ndiff-Nall = 5 – 5 = 0).

B.6. Emission reductions

B.6.1. Explanation of methodological choices >> As the Project activity is the installation of a new grid-connected Greenfield power plant and is not a modification or retrofit of an existing unit, therefore, the baseline scenario as prescribed in the approved consolidated baseline methodology ACM0002 is as follows:

“If the project activity is the installation of a Greenfield power plant, the baseline scenario is electricity delivered to the grid by the project activity would have otherwise been generated by the operation of grid-connected power plants and by the addition of new generation sources, as reflected in the combined margin (CM) calculations described in the “Tool to calculate the emission factor for an electricity system”. (Section 24)

In accordance with ACM0002, project emissions need not be accounted as the methodology provides that if the power density of project activity is greater than 10 W/ m², the Project Emission is Zero. As the project activity is the installation of a new hydropower plant that results in a reservoir with power density of 45.19 W/m2, therefore, the project emission is zero.


CDM-PDD-FORM Baseline Emissions As per ACM0002, the baseline scenario is the continuing operation of the existing thermal intensive grid and future expansion mainly through increase in capacity of the system by the addition of new fossil fuel based generation sources. Baseline emissions include only CO2 emissions from electricity generation in fossil fuel fired power plants within National Grid that are displaced due to the Project activity, calculated as follows:

𝐁𝐁𝐁𝐁y = 𝐁𝐁𝐄𝐄PJ,y ∙ 𝐁𝐁𝐄𝐄grid,CM,y Where: 𝐁𝐁𝐁𝐁y = Baseline emissions in year y (t CO2/yr) 𝐁𝐁𝐄𝐄PJ,y = Quantity of net electricity generation that is produced and fed into the grid as

a result of the implementation of the CDM project activity in year y (MWh/yr) 𝐁𝐁𝐄𝐄grid,CM,y = Combined margin CO2 emission factor for grid connected power generation

in year y calculated using the latest version of the “Tool to calculate the emission factor for an electricity system” (CO2/MWh)

and 𝐁𝐁𝐄𝐄PJ,y = 𝐁𝐁𝐄𝐄facility,y Quantity of net electricity generation supplied by the Project

Plant to the grid in the year y (MWh/yr) as project is Greenfield renewable new energy power plant

Following the “Tool to calculate the emission factor for an electricity system Version 5.0”, the baseline emission factor is calculated as a combined margin (CM), consisting of the simple average of the operating margin emission factor (OM) and build margin emission factor (BM) by utilizing an ex-ante 3 years data period.

𝐁𝐁𝐄𝐄grid,CM,y = 𝐖𝐖OM × 𝐁𝐁𝐄𝐄grid,OM,y + 𝐖𝐖BM × 𝐁𝐁𝐄𝐄grid,BM,y Parameter SI Unit Description 𝐁𝐁𝐄𝐄𝐠𝐠𝐠𝐠𝐠𝐠𝐠𝐠,𝐂𝐂𝐂𝐂,𝐲𝐲 t CO2/MWh Combined margin CO2 emission factor for the project

electricity system in year y 𝐁𝐁𝐄𝐄𝐠𝐠𝐠𝐠𝐠𝐠𝐠𝐠,𝐎𝐎𝐂𝐂,𝐲𝐲 t CO2/MWh Build margin CO2 emission factor for the project electricity

system in year y 𝐁𝐁𝐄𝐄𝐠𝐠𝐠𝐠𝐠𝐠𝐠𝐠,𝐁𝐁𝐂𝐂,𝐲𝐲 t CO2/MWh Operating margin CO2 emission factor for the project electricity

system in year y 𝐖𝐖𝐎𝐎𝐂𝐂 NIL Default weight is 50%

𝐖𝐖𝐁𝐁𝐂𝐂 NIL Default weight is 50%

The Combined margin CO2 emission factor (𝐁𝐁𝐄𝐄grid,CM,y) is calculated by applying the following six steps in accordance with the “Tool to calculate the emission factor for an electricity system” Version 5.0. STEP 1: Identify the relevant electricity system

There are two power grids in Pakistan i.e. KESC grid (Karachi Electric Supply Corporation) supplying the electricity to city of Karachi and WAPDA grid or National Grid (NTDC) covering most part of the country except Karachi. National Grid is selected to calculate the combined margin for emission factor as the Project will supply energy to National Grid. By separating KESC generation (100% thermal) the emission factors for the national grid (thermal + hydro) are broadly reduced,


CDM-PDD-FORM providing a correct and conservative estimate of the impact of the new plant on emissions. Each grid is having its own independent dispatch centre, generation and distribution system. There are no material inter-dependencies between the two grids except for occasional supply from National Grid to KESC grid which ranges from 400-600 MW. There is an element of electricity import into the National Grid but being non-material less than one percent i.e. 0.40%, therefore it has been ignored. Moreover, the imported electricity is also thermal.

STEP 2: Choose whether to include off-grid power plants in the project electricity system (optional)

The Option-I is selected applying conservative approach thus using only grid connected power plants in the calculations.

STEP 3: Select a method to determine the operating margin (OM)

There are four options for calculating OM as follows: (a) Simple OM; or (b) Simple adjusted OM; or (c) Dispatch data analysis OM; or (d) Average OM.

For the Project activity, Option (a) Simple OM is the only reasonable and feasible option as prescribed and allowed in methodological tool due to following reasons: (a) The detailed daily/hourly despatch data of National Grid is not available in

the public domain.

(b) Low cost must run resources constitute less than 50% of total grid generation in average of the five most recent years. The low cost must run power generation in National Grid constitutes 41.17%, 38.75%, 39.23%, 39.12% & 40.23% of total power generation during 2011-2015.

This PDD chooses ex-ante method to calculate the OM emission factor of WAPDA Grid by using the latest available three years data vintage.

STEP 4: Calculate the operating margin emission factor according to the selected method

The simple OM emission factor (EFgrid,OMSimple,y) is calculated as the generation-weighted average CO2 emissions per unit net electricity generation (tCO2/MWh) of all generating power plants serving the system excluding low-cost/must-run power plants/units. The simple OM may be calculated:

Option A: Based on the net electricity generation and a CO2 emission factor of

each power unit; or Option B: Based on the total net electricity generation of all power plants

serving the system and the fuel types and total fuel consumption of the project electricity system.

Option B is only feasible and selected to calculate OM emission factor of WAPDA grid due to the following reasons: (a) The necessary data for Option A was not available; and


CDM-PDD-FORM (b) Only nuclear and renewable power generation are considered as low-

cost/must-run power sources and the quantity of electricity supplied to the grid by these sources is known; and

(c) Off-grid power plants are not included in the calculation (i.e., if Option I has been chosen in Step 2).

According to option B, the simple OM emission factor is calculated on the basis of net electricity supplied to National Grid by all power plants serving the National Grid, not including low-cost/must-run power plants/units, and based on the fuel type(s) and total fuel consumption of National Grid as follows:

EFgrid,OMsimple,y =∑ (FCi,yi × NCVi,y × EFCO2,i,y)

EGy

Where: EFgrid,OMsimple,y = Simple operating margin CO2 emission factor in year y

(tCO2/MWh)

FCi,y = Amount of fossil fuel type i consumed in the project electricity system in year y (mass or volume unit)

NCVi,y = Net calorific value (energy content) of fossil fuel type i in year y (GJ/mass or volume unit)

EFCO2,i,y = CO2 emission factor of fossil fuel type i in year y (tCO2/GJ)

EGy = Net electricity generated and delivered to the grid by all power sources serving the system, not including low-cost/must-run power plants/units, in year y (MWh)

I = All fossil fuel types combusted in power sources in the project electricity system in year y

Y = The relevant year as per the data vintage chosen in Step 3

The consolidated grid system generation and energy statistics (Pakistan Energy Yearbook) have been available in Pakistan for several years and such reliable official data is available to compute the required factors. This PDD calculates the Operating Margin (OM) emission factors of National Grid in 2013, 2014 and 2015, respectively by using information from Pakistan Energy Year Books. Then, the OM emission factor of National Grid is calculated as the weighted average of the three years.

The generating plants for each grid i.e. KESC grid & National Grid are clearly identifiable and data for each grid is available. By separating KESC generation the emission factors for the national grid are broadly reduced, providing a correct and conservative estimate of the impact of the new plant on emissions. The information has been utilized as follows: (a) Grid system statistics have been analyzed for five years to provide evidence

for under 50% of the system being must run-least cost generation and justify use of the Simple OM method;

(b) Grid system statistics have been analyzed for the most recent three years to compute the following:


CDM-PDD-FORM (i) Total generation and analysis by type by fuel used; (ii) Calorific values of the fuel based on official data; (iii) Total heat value of fuel; (iv) Emissions factors and computation of CEF.

Based on these the analysis and official information available for the Pakistan Power System for 2013, 2014 and 2015, the value for the Operating Margin Emissions Factor (OM) is as follows:

OPERATING MARGIN (2013-2015) - Summary

Year tCO2 Power Generation

GWh CEF

2013 35,370,146 52,000 0.68020

2014 38,591,169 56,595 0.68189

2015 39,168,170 57,030 0.68680

Grand Total 113,129,485 165,625 0.68305

STEP 5: Calculate the Build Margin (BM) Emission Factor

In terms of vintage data, the project participants have option to choose between one of the following two options: Option 1: For the first crediting period, calculate the build margin emission factor ex ante based on the most recent information available on units already built for sample group m at the time of CDM-PDD submission to the DOE for validation. For the second crediting period, the build margin emission factor should be updated based on the most recent information available on units already built at the time of submission of the request for renewal of the crediting period to the DOE. For the third crediting period, the build margin emission factor calculated for the second crediting period should be used. This option does not require monitoring the emission factor during the crediting period. Option 2: For the first crediting period, the build margin emission factor shall be updated annually, ex post, including those units built up to the year of registration of the project activity or, if information up to the year of registration is not yet available, including those units built up to the latest year for which information is available. For the second crediting period, the build margin emissions factor shall be calculated ex ante, as described in Option 1 above. For the third crediting period, the build margin emission factor calculated for the second crediting period should be used. The project participants have selected Option 1 ex ante and will apply as follows: The sample group of power units m used to calculate the build margin has been determined in accordance with following procedure/chart, consistent with data vintage selected above:


CDM-PDD-FORM

To determine sample group m the five most recent additions to the system were compared with the additions to the electricity system that comprise 20% of the system generation and that have been built most recently. It was found that the power plant capacity additions in the electricity system that comprise 20% of the system generation and that have been built most recently provided the larger annual generation and were therefore selected as in the Methodology. Moreover, none of power plants, registered as CDM activity, is providing electricity to the system. The methodology results are as follows: (a) The five power plants that have been built most recently contribute 3,498.16

MWh to the grid;

(b) The most recent published total electricity generation in 2015 was 96,149,200 MWh and 20% of system generation comes to 19,230,840 MWh.

Identify the 5 most recent power units, excluding

CDM

Identify the units that comprise at least 20% of the system generation excluding CDM

Select the set of power units that comprises the larger

annual generation

Is there at least one power unit older than 10

years in the set?

Use the resulting set to calculate the build margin

Y

Exclude power units older than 10 years and

include power units registered in the CDM

Does the set comprise at least

20% of generation?

Use the resulting set to calculate the build margin Y

N

Include power units older than 10 years

until the set comprises 20% of generation

Use the resulting set to calculate the build margin


CDM-PDD-FORM Thus (b) above would be selected and the Build Margin emission factor would be computed based on the sample of the power plants capacity additions in the electricity system that comprises 20% of the system generation (in MWh) and that have been built most recently. In terms of vintage of data, ex-ante method is employed in this PDD to calculate the BM emission factor for the first crediting period based on the most recent available data from 2009 to 2015 published through Pakistan Energy Yearbooks published by Government of Pakistan.

The build margin emissions factor is the generation-weighted average emission factor (tCO2/MWh) of all power units m during the most recent year y for which power generation data is available, calculated as follows:

EFgrid,BM,y =∑ (EGm,ym × EFEL,m,y)

∑ EGm,ym

Where: EFgrid,BM,y = Build margin CO2 emission factor in year y (tCO2/MWh)

EGm,y = Net quantity of electricity generated and delivered to the grid by power unit m in year y (MWh)

EFEL,m,y = CO2 emission factor of power unit m in year y (tCO2/MWh)

M = Power units included in the build margin

Y = Most recent historical year for which power generation data is available

EFEL,m,y =EGCO2,m,i,y × 3.6

ηm,y

EFEL,m,y = CO2 emission factor of power unit m in year y (tCO2/MWh)

EGCO2,m,i,y = Average CO2 emission factor of fuel type i used in

power unit m in year y (tCO2/GJ)

ηm,y = Average net energy conversion efficiency of power unit

m in year y (ratio)

M = All power units serving the National Grid in year y

except low-cost/must-run power units

Y = The relevant year as per data vintage chosen


CDM-PDD-FORM As per the step 4(a) above, for the IPPs, emissions were calculated based on their efficiencies (taken from the Tool Annex-1, as no public data was available, and result is more conservative). For thermal plants, the data was taken from Pakistan Energy Yearbook 2015.

Based on the calculations, the BM is 0.3992 (A detailed calculation is presented in Annex 3 and in the supporting excel file).

STEP 6: Calculate the combined margin emissions factor

The calculation of combined margin emission factor 𝑬𝑬𝑬𝑬𝑔𝑔𝑔𝑔𝑔𝑔𝑔𝑔,𝐶𝐶𝐶𝐶,𝑦𝑦 is to be based on one of the following method: (a) Weighted Averages CM; or (b) Simplified CM.

The Weighted Average CM should be used as the preferred option. The Baseline Emission Factor is the weighted average of the OM emission factor 𝐁𝐁𝐄𝐄grid,OM,y and the BM Emission Factor 𝐁𝐁𝐄𝐄grid,BM,y. 𝐁𝐁𝐄𝐄grid,CM,y = 𝐖𝐖OM × 𝐁𝐁𝐄𝐄grid,OM,y + 𝐖𝐖BM × 𝐁𝐁𝐄𝐄grid,BM,y

The default weight of the 𝐖𝐖OM and 𝐖𝐖BM are 50% (i.e. 𝐖𝐖OM = 𝐖𝐖BM = 50% and 𝐁𝐁𝐄𝐄grid,OM,y and 𝐁𝐁𝐄𝐄grid,BM,y has been calculated in Steps 4 and 5 above and are expressed in tCO2/MWh. Please note that default values for all the projects other than wind and solar generation projects would be 𝐖𝐖OM = 𝐖𝐖BM = 50% for the first crediting period and 𝐖𝐖OM = 𝟐𝟐𝟐𝟐% 𝐚𝐚𝐚𝐚𝐠𝐠 𝐖𝐖BM = 75% for the second and third crediting period.

\ It is proposed to use the default weights as there appears little justification to use alternative weights after a study of the (i) timing of project output; (b) predictability of project output; or (c) suppressed demand.

Thus the default weights will be used will be 0.5 for both OM & BM and baseline emissions factor 𝐁𝐁𝐄𝐄grid,CM,y is determined as follows:

𝐁𝐁𝐄𝐄grid,CM,y = (0.5 × 0.68305) + (0.5 × 0.283) = 0.54110 tCO2/ MWh.

B.6.2. Data and parameters fixed ex ante (Copy this table for each piece of data and parameter.) Data / Parameter FCi,y Unit Metric tonnes for oil; mmcft for gas, Metric tonnes for diesel Description Amount of fossil fuel type consumed in the project electricity system in

year y Source of data Pakistan Energy Yearbook, Ministry of Minerals & Natural Resources,

Government of Pakistan Value(s) applied Series of data is used from Pakistan Energy Yearbook 2013, 2014 &

2015, therefore, the detailed information is provided in Annex-3


CDM-PDD-FORM Choice of data or Measurement methods and procedures

The Methodology requires use of published/official data, therefore, the required data has been extracted and collected from such official sources.

Purpose of data Calculation of baseline emissions Additional comment

Data / Parameter NCVi,y Unit GJ Description Net calorific value (energy content) of fossil fuel per mass or volume

unit of fuel i in year y (tonn/per mmcft) Source of data Revised 2006 IPCC Guidelines for National Greenhouse Gas

Inventories, Chapter I Value(s) applied 41.4 GJ/tonne for diesel

39.8 GJ/tonne for oil 0.89 TJ/MMCFT for gas 21.6 GJ/tonne for coal Note that the density of diesel is taken as 0.89 kg/litre as per the IPCC Guidelines. Also note that the density of natural gas is taken as 0.6728 kg/m3 as per API, 2009.

Choice of data or Measurement methods and procedures

Data is not available from local resource and IPCC figures are more appropriate

Purpose of data Calculation of baseline emission Additional comment

Data / Parameter EFCO2,i,y Unit tCO2 /TJ Description CO2 emission factor of each fossil fuel type Source of data Revised 2006 IPCC Guidelines for National Greenhouse Gas

Inventories Value(s) applied Natural gas: 54.3 tCO2/TJ

Fuel oil: 75.5 tCO2/TJ Diesel oil: 72.6 tCO2/TJ Coal: 94.6 tCO2/TJ

Choice of data or Measurement methods and procedures

IPCC default values have been used as no reliable national values are available

Purpose of data Calculation of baseline emission Additional comment

Data / Parameter EGm,y Unit MWh


CDM-PDD-FORM Description Electricity generated and delivered to the grid by all power sources

serving the system, not including low-cost/must-run power plants/units Source of data Pakistan Energy Yearbook, Ministry of Minerals & Natural Resources,

Government of Pakistan Value(s) applied As series of data is used from Pakistan Energy Yearbook 2013, 2014 &

2015, therefore, the detailed information is provided in Annex-3 Choice of data or Measurement methods and procedures

The Methodology requires use of published/official data, therefore, the required data has been extracted and collected from such official sources.


Data / Parameter ηm,y

Unit % Description Average net energy conversion efficiency of power unit m in year y Source of data The default values provided in the Tool to Calculate the Emission

Factor of an Electricity System (Annex 1) were used in the absence of publically available data

Value(s) applied Refer to Annex-3 Choice of data or Measurement methods and procedures

This data from the Tool was used for the IPPs only in the WAPDA grid, as details on their fuel consumption are not available. The average efficiency data was used to calculate their fuel consumption based on known energy generation and year of commissioning.


B.6.3. Ex ante calculation of emission reductions >> Baseline Emissions Baseline emissions, as per ACM0002, include only CO2 emissions from electricity generation in fossil fuel fired power plants within National Grid that are displaced due to the Project activity, calculated as follows:

𝐁𝐁𝐁𝐁y = 𝐁𝐁𝐄𝐄PJ,y ∙ 𝐁𝐁𝐄𝐄grid,CM,y Where: 𝐁𝐁𝐁𝐁y = Baseline emissions in year y (t CO2/yr) 𝐁𝐁𝐄𝐄PJ,y = Quantity of net electricity generation that is produced and fed into the grid as

a result of the implementation of the CDM project activity in year y (MWh/yr) 𝐁𝐁𝐄𝐄grid,CM,y = Combined margin CO2 emission factor for grid connected power generation

in year y calculated using the latest version of the “Tool to calculate the emission factor for an electricity system” (CO2/MWh)

The baseline emission factor is calculated as presented in section B.6.2. The factor is: 𝐁𝐁𝐁𝐁y = 0.54110


CDM-PDD-FORM The estimated quantity of net electricity generation that is produced and fed into the grid as a result of the implementation of the CDM project activity is: 𝐁𝐁𝐄𝐄PJ,y = 𝐁𝐁𝐄𝐄facility,y= 𝟒𝟒𝟒𝟒𝟒𝟒,𝟗𝟗𝟗𝟗𝟗𝟗 𝐂𝐂𝐖𝐖𝐌𝐌/𝐘𝐘𝐠𝐠 This Value is calculated using average hydrology data for the river over past 60 years, a plant utilization factor, a loss factor and known plant capacity of 102 MW. Therefore, baseline emission factor of the Project are: 𝐁𝐁𝐁𝐁y = 𝐁𝐁𝐄𝐄PJ,y ∙ 𝐁𝐁𝐄𝐄grid,CM,y= 474,996 × 0.54110 = 257,022 (tCO2/yr) Project Emissions The Project emissions from water reservoir are calculated based on Power Density as follows: The Power Density of the project activity (PD) is calculated as follows:

𝑷𝑷𝑷𝑷 =𝑪𝑪𝑎𝑎𝑎𝑎PJ – 𝑪𝑪𝑎𝑎𝑎𝑎BL

𝐀𝐀PJ − 𝐀𝐀BL

Where: 𝑷𝑷𝑷𝑷 = Power density of the project activity (W/m²) 𝑪𝑪𝑎𝑎𝑎𝑎PJ = Installed Capacity of the hydropower plant after implementation of the

project activity (W). This is to be newly established project with total installed capacity of 102,000,000 W

𝑪𝑪𝑎𝑎𝑎𝑎BL = Installed Capacity of the hydropower plant before implementation of the

project activity (W) i.e. 0 W 𝐀𝐀PJ = Area of the reservoir measured in the surface of the water, after

implementation of the project activity, when reservoir is full (m²). A new reservoir will be built and surface of water is 2,257,000 m²

𝐀𝐀BL = Area of the reservoir measured in the surface of the water, before

implementation of the project activity, when reservoir is full (m²). As a conservative approach, the value is taken as zero

Therefore: 𝑷𝑷𝑷𝑷 = (102,000,000 – 0) / (2,257,000 – 0) = 45.19 W/m² The power density of the project activity (PD) is greater than 10 W/m2, therefore, according to ACM0002, the Project Emissions are as follows: 𝐏𝐏𝐁𝐁y = 0 Leakage According to ACM0002, no leakage emissions are considered since the main emissions potentially giving rise to leakage in the context of the electric sector projects are emissions arising from


CDM-PDD-FORM activities such as power plant construction and upstream emissions from fossil fuel use (e.g. extraction, processing and transport). These emissions sources are thus neglected. 𝐋𝐋y = 0 Emission Reduction The project activity reduces the emissions through substitution of electricity in the grid by renewable energy which is based on fossil fuelled power plant. The net emission reduction of project 𝐁𝐁𝐄𝐄y in a year y is calculated by subtracting project emissions 𝐏𝐏𝐁𝐁y and emissions due to leakage 𝐋𝐋y from baseline emissions 𝐁𝐁𝐁𝐁y as follows:

𝐁𝐁𝐄𝐄y = 𝐁𝐁𝐁𝐁y − 𝐏𝐏𝐁𝐁y − 𝐋𝐋y For the project activity the value of 𝐏𝐏𝐁𝐁y & 𝐋𝐋y is equal to Zero, therefore, 𝐁𝐁𝐄𝐄y = 𝐁𝐁𝐁𝐁y. Thus 𝐁𝐁𝐄𝐄y = 257,022 tCO2

B.6.4. Summary of ex ante estimates of emission reductions

Year Baseline

emissions (t CO2e)

Project emissions

(t CO2e)

Leakage (t CO2e)

Emission reductions

(t CO2e)

1 Nov 2019 – 31 Oct 2020 257,022 0 0 257,022 1 Nov 2020 – 31 Oct 2021 257,022 0 0 257,022 1 Nov 2021 – 31 Oct 2022 257,022 0 0 257,022 1 Nov 2022 – 31 Oct 2023 257,022 0 0 257,022 1 Nov 2023 – 31 Oct 2024 257,022 0 0 257,022 1 Nov 2024 – 31 Oct 2025 257,022 0 0 257,022 1 Nov 2025 – 31 Oct 2026 257,022 0 0 257,022 Total (tonnes of CO2 e)

1,799,151 0 0 1,799,151

Total number of crediting years

7 years

Annual average over the crediting period

257,022 0 0 257,022

B.7. Monitoring plan

The monitoring methodology described in the ACM0002 version 17 is to be used. All data collected as part of monitoring should be archived electronically and be kept at least for 2 years after the end of the last crediting period. 100% of the data should be monitored if not indicated otherwise in the tables below. All measurements should be conducted with calibrated measurement equipment according to relevant industry standards. Section B.7.1 outlines the data and parameters that will be monitored, and section B.7.2 contains a detailed monitoring plan which describes how the monitoring of the project activity will be performed.

B.7.1. Data and parameters to be monitored Data / Parameter EGy Unit MWh/year


CDM-PDD-FORM Description Electricity delivered by the project activity to the national grid under the

power purchase agreement (PPA) executed with Central Power Purchase Agency (Guarantee) Limited (“CPPAG or “Power Purchaser”)

Source of data (a) Measured by the metering system in accordance with a transparent and strict procedure as stipulated in PPA; (b) confirmed by officially published generation data provided in the Pakistan Energy Yearbook; and (c) monthly invoicing to the Power Purchaser.

Value(s) applied The annual generation of the hydropower complex of 474,996 MWh is the basis for computation of emissions through application of the Combined Margin. The given generation is based on average historic hydrology; the estimate of hydrology and generation may be subject to year to year variation but is expected to equal the historic average hydrology/ generation over the term.

Measurement methods and procedures

All requirements for metering will be in accordance with the PPA and a summary extracted from the PPA is as follows: 1) There will be installed a metering system and a back-up metering

system; in addition there will be magnetic media and a sequential event recorder;

2) Testing of the metering system will be part of the complex commissioning procedures;

3) Inaccuracy of the metering system to be not greater than 0.2%; 4) Joint sealing of metering system after any inspection/examination; 5) Reading and recording thereof at the beginning of each day; 6) Joint reading with Power Purchaser’s representative on the last

business day of each month. Monitoring frequency Monthly by the Power Purchaser while aggregated annually QA/QC procedures In accordance with QA/QC procedures:

1) The metering system and the back-up metering system will be regulated by Power Purchaser and under continuous surveillance and in the event of greater than specified inaccuracy recalibration is specified;

2) Seals will be checked regularly; and 3) Cross checking between the different metering system.


Data / Parameter APJ Unit m2 Description Area of the reservoir measured in the surface of the water, after the

implementation of the project activity, when the reservoir is full. Source of data Project site Value(s) applied Measurement methods and procedures

Measures from the surveying map, the contour line of the reservoir at full water on the surveying map

Monitoring frequency Once in crediting period QA/QC procedures - Purpose of data For calculation of power density Additional comment


CDM-PDD-FORM B.7.2. Sampling plan No Sampling Plan is required over the monitoring period under ACM0002.

B.7.3. Other elements of monitoring plan The critical areas which are relevant under the approved methodology ACM0002 are to ensure that the estimation of emissions reductions under the methodology is a reasonable estimate of the actual emission reductions during the crediting period. To achieve this objective the measurements of emissions shall be carried out throughout the crediting period through a well-organized and well managed organizational structure and an adequate monitoring plan. The ex-ante estimate of the emissions is derived from BEy = EGy ∙ EFy and the critical functions are (a) the project generation and (b) baseline emission factor established ex ante. The monitoring would focus on these aspects with greatest attention on the project energy generation and any leakages as the other element i.e. baseline is a function of computational work performed on office published data publicly available and given that the methodology once selected and applied cannot be changed. The critical area in the monitoring plan is the independent and reliable verification of project metering and generation. For hydropower projects, constructed as Independent Power Producer having a power purchase agreement, this is relatively simple task because it is already built into the prescribed procedures. The generation, metering and delivery of electricity to the power purchaser under the terms of Power Purchase Agreement is well-structured activity which will form the basis of monitoring the energy generation from the project. Mira Power Limited proposes to appoint a CDM Management Team with the responsibility of managing the collection, recording and storage of the data required to calculate the greenhouse gas emission reductions from the project activity. The data that is required to be monitored is described in detail in Section B.7.1. The team consists of three key positions and will be supervised by the company’s Chief Operating Officer. An outline of responsibilities and roles of these three key positions are described in the table below: Position and Reporting

Job Description

Environment Manager (Reports to the Chief Operating Officer)

• Manages the collection, recording and storage of data; • Reviews the monitoring reports prepared and investigates

any irregularities; • Ensures ongoing compliance with the CDM monitoring plan; • Supervises meter calibration requirements; • Expert in calculations of Emission Reductions;

Chief Operating Officer

Manager (Project Dev.) Manager (Environment)

Site Supervisor


CDM-PDD-FORM • Prepares annual (or biannual) Emission Reduction Report;

and Site supervisor (Reports to the Environment Manager)

• Responsible for the completeness and reliability of the data; • Responsible for carrying out meter calibration; • Responsible to ensure that there is no irregularities in meter

function and data recording in between shifts; and • Responsible for preparation of quarterly metered net

electricity generation data reports. Manager Project Development (Reports to Chief Operating Officer)

• Review and verify the generation data; • Prepares Baseline Emission Factor report at the end of each

crediting period; • Energy and CER Calculations; • Undertakes regular internal audits of the project; and • Ensures compliance with Company Quality Assurance

Procedures. Monitoring Provisions Training All persons that form part of this CDM Project Team will be suitably qualified and trained before the start of the crediting period in order to perform the tasks specified in the table above. A copy of the project monitoring plan will be distributed to all of the CDM Management Team during the training, and additional copies will be readily available at appropriate locations on site. The Chief Operating Officer of the Project will be ultimately responsible to ensure that the required capacity and internal training is made available to assigned staff, to enable them to undertake the tasks allocated for each role. Specific Data Monitoring Procedures Installation of the Meters: The electricity will be monitored through state-of-the-art sealed and tested Meters as it is required under Power Purchase Agreement. The metering system will comprise of two sets of meters. The main meters will record the net electricity exported by the project to the grid and the second set of meters will record the gross electricity generated by the project. Both sets of meters will include a main meter and a back-up meter. Calibration of Meters: The CDM Monitoring Officer will ensure that a manufacturer’s test certificate accompanies with all purchased meters. A report summarising meter calibration requirements will be prepared by the CDM Monitoring Officer on project commissioning, and updated with each recalibration. Surface Area at Full Reservoir Level: The surface area of the reservoir at full volume at project commissioning will be measured from a detailed topographical survey. This data will be used to confirm that the power density of the project is greater than the minimum requirement specified by the ACM0002. Metered Net Electricity Export Data: Metered net electricity export data will be measured continuously. A monthly report of metered net electricity export data will be generated by the Site Supervisor, and saved in electronic and paper form. The monthly report will be generated using a template, approved by the Manager (Environment), to ensure that the data is reported consistently and can be compared to previous months. The Manager (Environment) will review this report on a monthly basis and cross check the data against the invoices for the quantity of electricity exported and sold. Any irregularities will be investigated as described below in “Review of Reports and Treatment of Uncertainty”. The auxiliary loads and losses (gross metered electricity generation minus net generated electricity) will be recorded in the monthly report, to be used in the event of meter failure, as described below in “Emergency Preparedness”.


CDM-PDD-FORM Emission Reductions: Emission reductions will be calculated on a daily basis using the project and baseline emission data. Emission reductions occurring as a result of the project activity will be summarized in a quarterly report that will be prepared by the Site Supervisor. The quarterly report will be generated using a template, approved by the Manager (Environment), to ensure that the data is reported consistently and can be compared to previous quarters. The quarterly report will be reviewed by the Manager (Environment) and submitted to the Chief Operating Officer. Updating the Baseline Emission Factor: If the required data is not available, the baseline emission factor will be calculated in accordance with ACM0002. A report summarizing this information will be prepared at the end of each crediting period by the Manager (Environment). The report will be submitted to the Chief Operating Officer. Emergency Preparedness: The project has the necessary provisions for emergency preparedness to deal with any unforeseen events such as fire or an electrical blackout. These provisions include installed firefighting systems, and standby features for critical items. In the situation where an emergency causes unintended emissions, these emissions will be quantified and recorded on a daily basis by the Site Supervisor and summarized in a discrete section of the Emission Reductions quarterly report. In the event that the main meter, which is used to record the net electricity exported by the project, is found to be faulty it will be repaired or replaced and the data from the backup meter will be used in its place. In the unlikely event that the backup meter fails it will also be repaired or replaced and the net electricity will be obtained from the gross generation data, minus the average the auxiliary loads and losses. The average auxiliary loads and losses will be calculated as the average over the most recent six months, using the values recorded in the Metered Net Electricity Generation monthly reports, described above. In the event of meter failure, the details will be recorded by the Site Supervisor and summarized in a discrete section of the Emission Reductions quarterly report. Reporting A summary of the monitoring reports is contained in below Table. All reports will be reviewed by the CDM Monitoring Officer and then sent to Chief Operating Officer and CEO for review and acceptance.

Reports Responsibility Frequency Surface area at full reservoir level CDM Monitoring

Officer At project commissioning

Meter Calibration report CDM Monitoring Officer

At project commissioning and updated at each recalibration

Metered Net Electricity Generated Data

Site Supervisor Monthly

Emission Reduction Site Supervisor Quarterly Baseline emission factor CDm Monitoring

Officer End of each crediting period

Emergency Report: Unintended emissions

Site Supervisor Daily (as required)

Emergency Report: Meter failure Site Supervisor Daily (as required) Internal Audit Report Manager (Quality

Assurance) Quarterly

Review of Reports and Treatment of Uncertainty When reviewing the Metered Net Electricity Export Data and Emission Reductions report the CDM Monitoring Officer will examine the report for data anomalies and compare the report with previous months for consistency.


CDM-PDD-FORM If any discrepancies are found they will be investigated and corrected. The discrepancies and corrective actions will be recorded in an appendix to the relevant report. If the corrective actions result in any adjustments to monitor the data, the relevant report will be revised, after necessary adjustments. The Quality Assurance Officer will undertake an internal audit of the project regularly after every three months to ensure the operational and maintenance regimes of the project and data collection and recording practices are compliant with the content of this Project Design Document. The results of the audit will be summarized in a report, which will be sent to the Chief Operating Officer for review. The report will also list any corrective actions required to ensure project compliance. Record Storage A paper copy of all documentation will be stored in a secure area within the site head office. All reports will be signed and date stamped after review by the CDM Monitoring Officer, prior to being filed in storage. All electronic reports will be backed-up on a monthly basis and sent to MPL’s Head Office. All archived data will be kept until two years after the last issuance of CERs for this project. The documents that will be stored include: • Surface area of reservoir at full volume • Manufacturer’s test certificate accompanies and meter calibration reports • Monthly report of metered net electricity export data • Quarterly report of emission reductions • Internal audit reports • Baseline emission factor

B.8. Date of completion of application of methodology and standardized baseline and contact information of responsible persons/ entities

Date of completion of application of methodology and standardized baseline: 15/08/2014

Contact information of responsible persons/entities: Contact Person Mr. Shahid Javed Company Name Mira Power Limited Mobile # +923335102709 E-mail address [email protected] Contact Address 1st Floor, Square 11 Plaza, Street # 1,

MPCHS, E-11/1, Islamabad Telephone # +92512100985 Fax # +92512114359

SECTION C. Duration and crediting period

C.1. Duration of project activity

C.1.1. Start date of project activity The start date of the project activity is 07/08/2015 (Signing of EPC contract), as it is the earliest date on which the implementation of the project activity has begun.

C.1.2. Expected operational lifetime of project activity 30 Years, 0 Months


mailto:[email protected]

CDM-PDD-FORM C.2. Crediting period of project activity

C.2.1. Type of crediting period 7 Years, 0 Months Renewable

C.2.2. Start date of crediting period 30/10/2019

C.2.3. Length of crediting period 7 Years SECTION D. Environmental impacts

D.1. Analysis of environmental impacts Gulpur’s potential direct impacts include: (a) conversion of aquatic and riparian habitat as a result of the modification of the hydrological regime of the Poonch river, both upstream from the dam before its confluence with the Ban Nullah tributary by creating a reservoir, and in the 700-m long dewatered segment from the dam to the power house where the natural flow regime will be significantly lowered; downstream from the tailrace the flow will be restored to its natural regime; (b) barrier effect to fish and invertebrates caused by the dam; (c) limited impacts on forest and vegetation cover; (d) permanent acquisition of 93.18 Acres (37.7 ha) of private land resulting in the physical displacement of 4 households (26 people), and the economic displacement of a total of 76 households; (e) potential safety risks to affected communities; and (f) a number of short-term disturbances typical of any new construction and civil works (e.g. air and noise emissions, wastewater, solid and hazardous waste generation and disposal, workers’ occupational health and safety risks, among others). Cumulative Impacts: The Project is the first of a series of proposed hydropower project in the Poonch river. Once it is successful implemented, it is likely to send a positive signal to the other hydropower developers, which could potentially lead to cumulative impacts that if realized would completely convert the Poonch river. A Strategic Environmental Assessment (SEA) prepared by the IUCN in 2014, states that the potential for hydropower development on the Jhelum and Neelum rivers is substantial, but recommended caution while developing hydropower in Poonch river due to its high environmental value and the relatively small contribution of hydropower development in the Poonch river could make to the national economy (about 470 MW). At the time of appraisal, local government had awarded 4 other hydro development licenses on the Poonch river. The company undertook a basin-level Cumulative Impacts Assessment (CIA) as an integral component of the updated ESIA. This assessment identified that the main potential cumulative impacts for cascading hydropower development in the Poonch river were related to sediment transport and impaired fish migration, and predicted severe impacts on fish populations if all five HPPs are constructed in the absence of basin-wide cumulative impact mitigation measures. Land Acquisition & Involuntary Resettlement: As stated above, the original project would have resulted in the physical displacement of approximately 115 households with over 700 people and economic displacement of even a larger number of affected people. The new project design has greatly reduced the amount of land directly affected by the reservoir, and resulted only in the physical displacement of 4 households with 26 affected persons, and the economic displacement of 76 households. A draft Land Acquisition, Livelihood Restoration and Involuntary Resettlement Plan (LARP) was prepared by a social consulting firm (Sustainable Solutions) on behalf of the company. The land acquisition process for Gulpur HPP is still underway and follows the Land Acquisition Act (LAA) of 1894. LARP development and implementation are a joint responsibility of the Land Acquisition


CDM-PDD-FORM Collector (LAC), District Commissioner and the company’s project implementation unit (PIU) based at Kotli. Following section 4 of LAA 1894, those potentially affected were initially notified on 16 September 2013. Due to project design modification the number of originally affected people was greatly reduced and this notification was withdrawn. Re‐notification for entire villages was performed on 11 April 2014 based on the final design of the project. This notification date has also been taken as the cut-off date for the LARP. The Normal Operating Level (NOL) of the project after the final design shall be at an elevation of 532 meters from the sea level which was modified from an NOL of 540 meters in the original design, which determined the extent of the land to be required for the project (e.g. flooded area plus buffer zone). LARP related public consultation and information disclosure sessions are still ongoing, and the most recent consultation was held in Feb 2016 in all the villages. Gulpur HPP will result in the permanent acquisition of 93.18 acres (37.7 ha) of private land, including 18 acres (7.25 ha) of cropped area (cultivated land). Land acquisition will result in the physical displacement of 4 households with a total of 26 affected persons, and the flooding of 73 fruit trees and 27,944 timber trees, affecting the livelihood of 76 households. Other structures such as an animal shed, a flour water-mill and two suspension bridges will also be affected. Most of the affected private land is barren and/or is unused because it lies within the river bed. The remaining land is agricultural and forest which is presently being used for crops and grazing respectively. All of the residential houses that will be impacted are located in the Barali Village with a population of about 4,000 and located on the left bank of the Poonch rover about 5 km upstream of the proposed dam. An entitlement and compensation matrix was developed in the draft LARP to replace and compensate lost assets based on the principle of replacement cost. Land for land compensation was found unfeasible. The company attempted to identify potential replacement plots in the project’s area of influence, but due to the hilly terrain this proved to be impossible. Compensation and various forms of assistance will be provided to the affected persons in a way that ensures their standards of living is improved or at least restored to pre-project levels. Those affected peoples belonging to vulnerable groups (such as poor households, landless tenants / workers, or women-headed households) will be assisted to improve their socio-economic status. The entitlement matrix includes a compensation structure for those entitled from land loss, loss of structures, loss of income from crops and trees, loss of public services, and contains special provisions for vulnerable persons and women. The Company will manage all resettlement related matters through the Land Acquisition and Resettlement Unit (LARU) in coordination with local government. The LARU will also assist the project company in reviewing and preparing resettlement documents (internal monitoring reports, breach and corrective actions, among others) and assure compliance with the LARP. The LARU will provide the necessary training and capacity building interventions to field staff including contractor, consultant, grievance redress committee and affected persons. The LARP implementation schedule for the proposed project includes LARP updating, disclosure, disbursement of compensation, internal and external monitoring, and reporting. The timeline for implementation of LARP will be scheduled as per the overall project implementation. All activities related to the land acquisition, livelihood restoration and involuntary resettlement are planned to ensure that compensation is paid prior to any displacement. LARP activities under the project will be subjected to monitoring. As part of the ESAP, an as an integral component of the LARP, the company will commission an independent party to perform an ex-post Land Acquisition, Livelihood Restoration and Resettlement Completion Report. Biodiversity Conservation & Sustainable Management of Living Natural Resources: The Poonch River is a warm water river and the water temperature approaches almost 30oC during the summer months. A total of 37 fish species have been recorded from the Poonch river. Six fish species observed in the study area are listed on the global IUCN Red List of Threatened Species. The Kashmir Catfish (Glyptothorax kashmirensis) is listed as Critically Endangered (CR), the Mahseer (Tor putitora) is listed as Endangered (EN) while the Common Carp (Cyprinus carpio) and Twin-banded Loach (Botia rostrata) are listed as Vulnerable (VU). Moreover, Pabdah Catfish


CDM-PDD-FORM (Ompok pabda) and Butter Catfish (Ompok bimaculatus) are listed as Near Threatened (NT). Other important endemic fish species found in the project’s area include Pakistani Baril (Barilius pakistanicus), Punjab Loach (Schistura punjabensis) and Nazir‟s Catfish (Glyptothorax naziri). Critical Habitat: Due to its high fish diversity and importance in supporting fish of both conservation and economic importance, in December 2010, the Poonch river along with its tributaries was declared as Poonch River Mahaseer National Park by local environmental authorities. The nomination of this National Park has been promoted and/or endorsed by a number of reputable environmental NGO, including but not limited to IUCN, WWF, Himalayan Wildlife Foundation, and Snow Leopard Foundation, as they argue that the Poonch river is essential for the global survival of Kashmir Catfish, and presents a unique natural abundance of the Mahaseer fish, an endangered species whose population has been consistently declining all over Himalayan rivers. As an integral component of the ESIA, a Critical Habitat Assessment (CHA) was conducted. This assessment confirmed that the project will be sited in a Critical Habitat, and therefore the project company will developed a Biodiversity Action Plan (BAP), of which an advanced draft is disclosed together with this review summary. The Project ESIA evaluated various scenarios to address both flow and non-flow related pressures on the biodiversity of the Poonch River. See below for discussion of flow related pressures. The non-flow related pressures include selective fishing (with nets and rods), non-selective fishing (with gill nets, poisons and dynamite), sediment mining (sand, gravel and boulders), nutrient enrichment (waste water from human population centers), and harvesting of riparian vegetation for building materials. The ESIA scenarios predict that under a “business as usual” (BAU) scenario, even without the Gulpur HPP, the non-flow related pressures on the aquatic ecosystem will double in intensity over the next fifty years, predictably resulting in significant decline in abundance and diversity of the aquatic and semi-aquatic flora and fauna. The ESIA proposes a scenario (Pro 2 Scenario) that includes actions (proposed in the BAP) to reduce 2013 levels of these pressures by 50%, which is predicted to achieve net gain of aquatic biodiversity in the project area. For the two fish species that trigger Critical Habitat (Mahaseer and Kashmir Catfish), the ESIA “business as usual” (BAU) scenario – i.e. even in the absence of the Gulpur HPP - predicts extreme losses (46 - 100% loss) relative to 2013 levels over the next 50 years without any preventive actions. The ESIA Pro 2 scenario, with the BAP actions, predicts an overall net gain for both fish species. Ecological Flow: Hagler Bailly Pakistan appointed Southern Waters to assist with an environmental flow (EFlow) assessment for the Poonch river in the proposed Gulpur HPP’s area of influence. The objectives of the assessment were (a) to evaluate present day condition (i.e. the present structure and functioning) of the Poonch river from upstream of Gulpur HPP to Mangla Dam; and (b) to evaluate how the condition of the river would change under different operational scenarios for the proposed Gulpur HPP, including a non-project business-as-usual (BAU) scenario. Hydrological data collected during the last 50 years, shows that in the project area the Poonch river has an average mean flow of approximately 110 m3/s, with 5-day high and low flows of 726 m3/s and 17 m3/s, respectively. Downstream Response to Imposed Flow Transformations (DRIFT - http://www.southernwaters.co.za/downloads/drift.pdf) methodology was used to assess impact of varying levels of downstream releases / environmental flow on project economics and aquatic ecosystem integrity. To finally select an EFlow regime that achieves a balance between ecosystem integrity and project financial viability, the company discussed these modelled impacts with key stakeholders, including environmental authorities and representatives from the environmental NGOs that promoted the Poonch River Mahaseer National Park nomination. Given the limited length of the dewatered section from the dam to the power house tailrace of only 700 meters and the company’s commitment to a true run-of-river operation (e.g. non-peaking), the study determined that the optimal trade-off was at 4 m3/s, and that beyond this release, there was limited-to-nil ecological gains by increasing Eflow at the expense of power generation. Prior to plan commissioning, as a requirement to IFC financing, Gulpur HPP will complete a comprehensive Ecological Flow Management Plan, consistent with good international industry practices and PS6 requirements.


CDM-PDD-FORM Terrestrial and riparian Natural Habitat: Site clearance and construction of project infrastructure will result in immediate and direct modification of land and a loss of terrestrial habitat leading to loss of plants and animals in the project’s influence area, including the area to be flooded by the new reservoir. The area of habitat loss consists largely of riparian habitat and scrub forest. No threatened flora or fauna species were found or reported from this area. Limited signs of the Otter (Lutra lutra, listed as Near Threatened in the IUCN Red List) were observed, and this species is known to be present in similar habitat. No critical habitat, threatened or unique ecosystems were identified in the terrestrial and riparian impact area. The decrease in biodiversity and ecological function caused by construction related disturbances is predicted to be minor. Mitigation measures include following the measures outlined in the Construction Management Plan, such as development of a reforestation program, and prohibition of hunting, poaching and/or logging by the workforce. Biodiversity Action Plan (BAP): A comprehensive BAP has been developed, outlining Pro2 scenario commitments to achieve net positive gain in the ecological values that triggered Critical Habitat classification, namely (a) Kashmir Catfish, (b) Mahaseer fish and (c) Poonch River Mahaseer National Park conservation objectives. These actions will include, among others: (i) implementing an effective watch and ward system supported by institutional arrangements to reduce illegal and indiscriminate hunting and killing of wildlife (both aquatic and terrestrial) including several bans on non-selective fishing, fishing in tributary breeding grounds, fishing during the breeding season, and sediment mining in ecologically sensitive areas; (ii) prohibiting removal of vegetation that is important for supporting biodiversity; (iii) increasing park staff, patrols and mining inspectors; (iv) limiting areas designated for sediment mining; (v) banning of livestock grazing and wood collection in sensitive areas; and (vi) conducting environmental awareness workshops for local communities. The Sponsors will finance supplemental park staff, equipment, facilities, and logistics to close the existing capacity gaps – including the construction of two park management offices and support to the local Fish and Wildlife Department (FWD) on the construction of a hatchery for Mahaseer on the Poonch river. This hatchery is a key component of the actions needed to increase numbers of the Mahaseer in the downstream portion of the Poonch river after the dam is in place as they will be cut off from their breeding grounds upstream. Therefore, success of this hatchery is critical to the success of the BAP actions and will be planned and monitored carefully. In addition, project sponsors will provide technical support to the local FWD by engaging experts in park management and river ecology. Institutional arrangements proposed in the BAP consists of (vii) putting in place a protection system for Poonch River Mahaseer National Park partly financed by the project and implemented by an independent organization; (viii) active support from the local FWD by making available existing staff for protection and assistance in coordination with other government line departments such as police and district administration; (ix) commitment by the local FWD to provide legal authority to the staff of the independent organization for exercising powers under wildlife legislation; (x) oversight and monitoring by the Wildlife Management Board of the local FWD; and (xi) monitoring by an independent third party on a long term basis. These actions, along with development of a strong Poonch River Mahaseer National Park management plan, are expected to lead to net gain on the indicator fish species populations and strengthen and support conservation objectives of the park. Climate Change / GHG: This is a renewable energy project, which is expected to have a net positive impact by offsetting energy sourced from fossil fuel power projects. A climate change study was conducted to evaluate climate change impacts on issues that are relevant to the operation of the hydropower plant. This study included an initial risk screening, analysis of downscaled Global Climate Models (GCM) results, analysis of hydrological changes, estimates of reservoir sedimentation, projected climate change impacts on water supply, greenhouse gas (GHG) emissions from the Gulpur HPP reservoir, and evaluation of disease risks. Results of the study showed that evaporation changes in the Gulpur HPP basin may occur as a result of climate change, even in the absence of irrigation demand. Pollution Prevention and Control: Construction activities will include excavation, blasting,


CDM-PDD-FORM drilling, quarrying and burrowing, aggregate crushing, concrete batching, muck disposal, concrete laying, brickwork, cabling, erection of structures and equipment. The sections that follow describe principal measures included in the EMMP to address impacts from these activities. Air pollution: The ESIA indicates that there are no major sources of air pollution, i.e., no industries in the project’s air-shed. Measured concentrations of carbon monoxide, nitrogen dioxide, sulfur dioxide and particulate matter PM10 in ambient air were found to be within National Environmental Quality Standards (NEQS). The ESIA also indicates that dust impacts on air quality during construction are deemed to be moderate. A batching plant on site will contribute to dust emissions in the area. Vehicle and machinery exhaust emissions will also affect air quality with potential impacts on the surrounding community. The EMMP includes measures to mitigate atmospheric pollution, based mainly on regular sprinkling unpaved roads and work areas, and systematic maintenance of construction vehicles and equipment. Noise: During construction activities for the project, particularly drilling, blasting, excavation, generators and operation of batching plant, noise levels are expected to increase in the area. Noise control measures will be adopted by the EPC contractor to make sure that noise levels are kept close to existing background. It is expected that the noise impact will be limited and not be beyond 200 meters from construction site, construction will be performed only during day time, and traffic will be managed to avoid congestion on the public roads. Waste: The potential impact from domestic solid and wastewater disposal is significant as it is expected that approximately 400 people will be deployed on the construction site for approximately four years. An assessment on the impact of the physical environment was carried out under the ESIA. Waste such as sewage, wastewater, construction waste, chemical waste and other solid waste pose a risk in the area if not disposed of carefully. The main surface water resource of the project area is the Poonch river, which flows along Kotli-Mirpur Road and drains into Mangla reservoir. Water quality of the river is generally fair and it is used for recreation, washing, and other non-consumptive purposes (e.g. illegal mining, mills). However, since the river water is contaminated from the disposal of sewage from towns, villages and settlements along the river, the Poonch river water is not used for human consumption or irrigation. The main source of drinking water in the area is ground water and springs. Groundwater drawdown impacts are not expected as there is no inhabitants on the ridge through which tunneling will be drilled, and the settlements closest to the dam construction are located more than 500 m away from the area where major excavation activities will take place. Measures included in the EMMP to manage waste-related impacts include control of soil erosion, treatment of wastewater from camp and office facilities, and proper collection, storage and disposal of solid waste. Depending upon the quality of the excavated material, some of the excavated material will be used to meet the requirement of aggregate rock fill at cofferdams and stone pitching. Surplus excavated material will be deposited in a designated spoil area at the project site and slope stabilization measures will be adopted. Community Health and Safety: The local community, especially women and children, suffer from water borne diseases including diarrhea. Of the three diseases in Pakistan addressed in the ESIA, it is noted that the projected temperature and precipitation pattern changes as a result of global climate change could increase the future risk of malaria, dengue fever and Crimean-Congo hemorrhagic fever (CCHF) in the project’s area of influence. The EMMP proposes to provide potable water by constructing small-scale drinking water supply systems or installing hand-pumps at certain convenient points in the potentially affected urban and rural communities including Rehmani Mohalla and Naroch Colony located in the vicinity of the project site. Provision of clean drinking water to communities will contribute to improve the general health of women and children, save families from extra efforts / fatigue and reduce water buying costs. The EMMP outlines that the CSR Plan will allow access of local communities to the health infrastructure constructed for project workers, as well as provide health care services to the local community (e.g. polio vaccination, dispensary facilities, and local clinics). Dam Safety: Saman Engineering was hired as external expert with relevant and recognized experience in similar project - and different from those responsible for the Gulpur HPP’s design


CDM-PDD-FORM and construction- to perform a Dam Break Analysis Report. This report provides risk and hazard classification in the case of dam failure. The results of a dam break study include the extent of the areas impacted as the flood wave progresses. In the case of dam breach, downstream areas will be inundated with potential damage to bridges, houses, and cultivated lands. The EMMP discusses details for provisions to account for dam break analysis and on-going monitoring. As noted in the ESAP, the company will develop a detailed Emergency Response Procedure (ERP) including detailed emergency response in the cases of dam breaks, natural disasters, earthquakes, fire / explosion, severe traffic accidents, violence and/or social unrest, hazardous products spills, floods, landslides, fall of people into water channels, and forest fires. Road Traffic: The ESIA includes an assessment of impacts on traffic during the construction of the project on two junctions, Gulpur and Palak, and was seen to have low traffic volume, and well below the recommended usage limits. Currently the roads can cater for the needs of the traffic but with the anticipated increase due to the project, there are likely to be impacts on the existing road infrastructure. The EPC contractor will be responsible to upgrade and maintain existing roads and develop a new 650 meter access road to connect the project facilities to the main road. Negative impacts on ecology from road construction as well as increased traffic on the newly constructed road are expected to be minimal. Mitigation measures are outlined in the EMMP to includ e size of trucks and vehicle in specific access routes, place of parking of machinery and vehicles, paving of access routes and paths, among others. Security: Preliminary information obtained during appraisal is that Gulpur HPP will hire a government-certified private security company to manage security, in addition to implementing standard site security arrangements such as a perimeter fence, controlled access, and road checkpoints. This licensed security provider will supply armed guards trained in the use of weapons and appropriate and proportionate use of force. Government security may also be provided to maintain the security of project area as a whole. Given the potentially volatile security situation in this region, as part of the ESAP, the project company will follow key elements of PS 4. The company will perform a Security Risk Assessment (SRA) with a qualified international security risks firm and will present a Security Management Plan (SMP) to assure that employees, sub-contractors, as well as physical assets are safe, under surveillance, and in a controlled environment. The SMP will be (a) site specific and comprehensive (b) commensurate to the security risks, (c) describe security risks and detailed response procedures, (d) aligned with the Voluntary Principles on Security and Human Rights (http://www.voluntaryprinciples.org), and (e) assure that all security personnel, but especially those who will bear arms, are trained and operate consistently with such principles. This plan will also include an initial awareness workshop and site briefing for all employees. The SRA will also identify any potential risks that its own and/or government-owned security arrangements may pose to those within and outside the project site, including the residents of the nearest towns. As a general rule, the company’s security response will be guided by principles of proportionality, avoidance of confrontation, use of a preventive and defensive approach commensurate to the nature and extent of the threat, and respect for human life and basic human rights. The company will make reasonable inquiries to ensure that those providing security are not implicated in past abuses; will train them adequately in the use of force and fire arms, and will impose a Code of Conduct toward workers and nearby communities. The project company will use best efforts to ensure that Government security personnel act in a manner consistent with these principles. Labour and Working Conditions: The project will employ about 700 skilled, semi-skilled and unskilled workers for construction. The Company is using its best efforts to hire the majority of unskilled labour and, to the extent possible semi-skilled and skilled workers from the local area. While most of the locally-hired workforce go back home on a daily basis, the remainder are accommodated in the labour camps. Occupational Health and Safety (OHS): As outlined in the EMMP, OHS risks and management procedures will be included in the Construction Management Plan. As identified in ESAP, this plan will ensure that the EPC contractor / O&M provider develop a site-specific over-arching OHS procedure for the construction and operations phases of the project as a whole. The procedure will


CDM-PDD-FORM identify task-specific OHS risks, define safety protocols to follow for each task, personnel qualification, limitations and equipment needs (e.g. personal protective equipment), and training programs. The company will also ensure that the EPC contractor / O&M provider track OHS performance during both construction and operations. The E&S Manager will record and track any OHS incidents through an incident tracker and will report on incidence and severity rates during both construction and operations.

D.2. Environmental impact assessment In September 2013, an Environmental and Social Impact Assessment was completed. This ESIA referred to the project as originally conceived; it involved a smaller dam of 45 meters high located further upstream on the ridge, leading to large reservoir of 22 million m3, and a flooded area of 3.6 km2 potentially displacing 115 households (over 700 people), and a dewatered river reach of 6.1 kilometers from the dam to the powerhouse. After an exhaustive alternatives analysis that involved environmental, social, technical, and financial considerations, the company decided on the current Gulpur HPP design. This new designed resulted on a project with the same generation capacity, a taller dam and a deeper reservoir of 42 million m3, but with significantly less environmental and social impacts, including minimal need for involuntary resettlement of people. Once the new design had been agreed upon, Hagler Bailly Pakistan updated the Environmental and Social Impact Assessment (2014 ESIA). The ToRs for this updated ESIA were prepared by the client in consultation with the IFC, ADB and other lenders. This ESIA updated in 2014 is aligned with good international industry practices and commensurate with what would be expected for a project of this nature, and included, but was not limited to: (i) collection of additional social and environmental baseline, (ii) a comprehensive downstream release / ecological flow assessment, (iii) a Critical Habitat Assessment (CHA), (iv) a Cumulative Impact Assessment (CIA), (v) climate risk assessment, and (vi) land acquisition, livelihood restoration and involuntary resettlement plan (LARP). All these assessment are included within the ESIA or are stand-alone studies. The ESIA proposes a series of mitigation measure to manage cumulative impacts. The most fundamental measures have been consolidated in a long-term Biodiversity Action Plan (BAP). The ESIA highlights the potential Gulpur HPP has to become a benchmark of good environmental and social practices for all developers, and includes recommendations for collective action to address potential cumulative impacts and their implementation, such as (a) enhancing availability and sharing of basin-level environmental and social data to ensure consistency and uniform access to all developers; (b) coordination of actions to implement a basin-level integrated management plan to protect and develop catchment areas aimed at minimizing erosion and sedimentation and supporting ecosystem conservation; and (c) making efforts to share infrastructure whenever possible (e.g. access roads, transmission lines). In addition, the Department of Wildlife and Fisheries has given a conditional approval to Gulpur HPP stating that all future projects will have to abide by the “net gain” principle. Management Program: As a result of the updated ESIA, the company developed an Environmental and Social Management and Monitoring Plan (EMMP) which summarizes the organizational requirements, and management and monitoring plans to ensure that the necessary measures are taken to (a) avoid or mitigate potentially adverse effects, (b) maximize potential benefits, and (c) operate in compliance with applicable local laws and regulations, IFC’s Performance Standards and ADB. The EMMP include a Construction Management Plan, Air Pollution Control Plan, Waste Management Plan, Muck Disposal Plan, Spill Prevention and Contingency Plan, Construction Labor Management Plan, Traffic Management Plan, Health and Safety Plan, and an Emergency Preparedness Plan. In addition, the EMMP also outlines a series of additional plans that need to be further developed by the client, such as the Biodiversity Action Plan (BAP), Ecological Flow Management Plan, Sediment Mining Plan, Socioeconomic Management Plan, Land Acquisition, Livelihood Restoration and Involuntary Resettlement Plan (LARP), and a Corporate Social Responsibility (CSR) Plan. As a requirement for lenders’ financing, the BAP was prioritized and an advanced draft it is disclosed together with this review summary. A sustainable Sediment Mining Plan will be prepared to develop an understanding of sediment


CDM-PDD-FORM deposition patterns, and to devise a strategy for mining that minimizes impact on the river habitat. The Corporate Social Responsibility (CSR) Plan will provide detailed information on method, roles and responsibilities of interaction with the local community, mitigation of socio-cultural impacts, socio-cultural conflicts and enhancement of positive impacts. The proposed Socioeconomic Management Plan will include providing water supply and health care facilities, skills training, and capacity building activities, among others. Terms of Reference for these plans are included in the ESIA’s EMMP and presentation of these plans is both a local legal requirement and will be a requirement for IFC’s investment. In order to ensure compliance of the EMMP and other plans, as part of the ESAP, the Company shall develop an overarching Environmental and Social Management System (ESMS) for the project. This ESMS will build on the company’s corporate ESHS policies and procedures and follow good international industry practices (GIIP) and be consistent with the lenders’ requirements; as a minimum it shall include an ESHS Policy, proposed organizational structure, a procedure to identify of ESHS risks and impacts, management programs, an overarching monitoring, reporting and non-compliances tracking mechanism; and a stakeholder engagement plan. The ESMS will be reviewed and approved by the client’s upper management and will be applicable to the EPC contractor / O&M provider and major sub-contractors. Towards achieving this goal, as also noted in the ESAP, the company shall assure that the EPC Contractor prepares a Construction Environmental and Social Management Plan (CMP) demonstrating the manner in which it will comply with the requirements of the EMMP. Furthermore, KOSEP (O&M) will be mobilized to the project site ten months prior to construction completion to ensure smooth transition/taking-over and plant commissioning. Per the ESAP, prior to the commencement of operations, the company shall develop the operations environmental and social management plan conforming to good international industry practices. Organizational Structure, Monitoring Programs, and Reporting: At the corporate level, the company has a comprehensive ESHS Policy and procedures, organizational structure, and has a dedicated ESHS & CSR Manager for the project. The latter is in charge of customizing the corporate policies and procedure to the project, and managing and supervising project’s compliance with ESHS requirements and EMMP, as well as delivering training and preparing periodic ESHS compliance reports. In addition, all sponsor companies also have their own environmental, social, health and safety policies and responsible personnel. In total, there are 6 professionals with ESHS responsibility working on this project. Regular monitoring of construction and commissioning activities are being undertaken against the environmental requirements as per relevant standards, specifications and EMMP. External experts are engaged for ecological monitoring during the construction and will be engaged for operation phases of the project; key parameters that will be monitored will include fish abundance and diversity with special attention to the Mahaseer fish and Kashmir Catfish, macro-invertebrate communities, periphyton biomass, bankside vegetation, and Eurasian Otter population. In addition, river water quality, environmental releases from the dam, and changes in hydrology and geomorphology of the river due to project operation will also be monitored. The purpose of monitoring will be to assess the performance of the undertaken mitigation measures and to immediately formulate additional mitigation measures and/or modify the existing ones aimed at meeting the environmental compliance as appropriate during construction and operations. Key environmental and social milestones of the Project are as follows:

01 Agreement for Preparation and Development of ESIA & RAP 04/30/2013 02 Finalization of ESIA & RAP 03 Recognition of Project Location in National Park 05/03/2013 04 Agreement for Carrying out Studies of CHA & BAP 09/13/2013


CDM-PDD-FORM 05 Peer Review Meeting with ADB in Manila 09/30/2013 06 Additional Agreement with Hagler Bailly for Climate Change Assessment

Report and Updating the ESIA 02/27/2014

07 Reviews and Objection of ESIA by EPA 02/28/2014 08 Submission of Revised ESIA 03/31/2014 09 Acceptance of ESIA by EPA 04/09/2014 10 Public Hearing 05/15/2014 11 Approval for Construction in National Park 05/21/2014 12 Issuance of Environmental NOC 06/18/2014 13 Baseline Biodiversity Assessment 09/23/2014 14 Biodiversity Action Plan Draft Report 09/23/2014 15 Ecohydraulics Specialist Report 09/23/2014 16 Environmental Flow Assessment 09/23/2014 17 Environmental and Social Management System (ESMS) Framework 09/23/2014 18 Frameworks for Management Plans 09/23/2014 19 Geomorphology Specialist Report 09/23/2014 20 Mitigation Strategies with Respect to the Impact of Sand and Gravel

Mining in the Poonch Basin 09/23/2014

21 Physical Baseline 09/23/2014 22 Finalization of Road Map for National Park Management Plan 09/25/2014 23 Finalization of ESIA 09/25/2014 24 Cumulative Impact Assessment 11/01/2014 25 Approval of Wildlife & Fisheries Department, GoAJK for BAP 01/02/2015 26 Agreement for Carrying out Additional Studies for Updating BAP 01/13/2015 27 Agreement for Carrying out Security Risk Assessment, Developing a

Security Management Plan and Related Procedures 01/27/2015

28 Security Risk Assessment 02/15/2015 29 ESIA Submission to EPA 02/20/2014 30 Approval of Wildlife & Fisheries Department, GoAJK for updated BAP 03/11/2015 31 Land Acquisition and Resettlement Plan (LARP) 06/15/2015 32 Construction Environmental and Social Management Plan 09/15/2015 33 Emergency Response and Contingency Plan 09/15/2015 34 Biodiversity Action Plan 10/01/2015 35 Stakeholders Engagement Plan 10/06/2015 36 Environmental and Social Management System (ESMS) 10/06/2015 37 EHS Plan for Diversion Tunnels 10/15/2015 38 Fire Emergency Response Plan 10/15/2015 39 Environment, Occupational Health and Safety Program 10/15/2015 40 Muck Disposal Plan 10/15/2015 41 Malaria Management Plan 10/15/2015 42 Spill Contingency Plan 10/15/2015 43 Traffic Management Plan 10/15/2015 44 Waste Management Plan 10/15/2015 45 Agreement for Development of Detailed Livelihood Restoration Plan

(DLRP) 11/17/2015

46 Stakeholders Consultation Ongoing 47 Finalization of Site Specific Plans Ongoing 48 CSR Plan In Progress 49 Finalization of Climate Change Assessment Report 50 Finalization of Glacier Lake Outburst Floods (GLOF) Assessment


CDM-PDD-FORM 51 Approval of Wildlife & Fisheries Department for Execution of BAP

Implementation Agreement 02/19/2016

52 Execution of BAP Implementation Agreement 02/22/2016 SECTION E. Local stakeholder consultation

E.1. Solicitation of comments from local stakeholders A basin wide study approach was used for the ESIA of Gulpur HPP therefore 11 rural communities were consulted along the Poonch River. In addition to the potentially affected communities, local government and local NGO officials were also consulted. As part of the updated ESIA process, consultations were undertaken with communities and institutions that may have interest in the proposed project or may be affected by it. The Company did several meetings with the government and civil society including the local community and publicized through different channels regarding the scope, nature and details of the project. Series of events occurred in order to engage different types of stakeholders. The details are given below:

(i) Consultations with stakeholders were undertaken during the third and fourth week of February 2014. The meetings were attended by heads of local councils, chief executives of the municipalities within the Project area, representative of local administration, environmental protection agency and members of civil society.

(ii) For institutional consultation, Hagler Bailly organized one meeting in Muzaffarabad for government departments and agencies and one in Islamabad for the remaining institutions.

(iii) Individual meetings with the Traders Association of Kotli and the Deputy Commissioner of Kotli were also conducted on February 11th and 12th 2014 respectively

(iv) For the Public Hearing, it was advertised in the local newspapers and community that an open meeting for the public, civil society and other stakeholders would be organized in April-May 2014. This hearing was meant for all the stakeholders to put forward their stance, concerns and insecurities regarding the project.

(v) On 19th February, 2014, consultation meeting was held between Hagler Bailly and the representatives of WWF-P, HWF, PPIB, Snow Leopard Foundation and independent ecologists at MPL office in Islamabad.

(vi) On 20th March, 2014, consultation meeting was held between Haglier Bailly and the representatives of EPA-AJK, HEB-EPA and Forest Department in Pearl Continental Hotel, Muzaffarabad.

The updated ESIA and the draft LARP include a grievance mechanism for community members and affected parties. An overall project grievances redress mechanism has been developed whereby project stakeholders are entitled to lodge complaints regarding any aspect of the project. Complaints will be able to be made verbally or in written form. To allow for grievances to be handled effectively, the Company has established the following: (i) A Public Complaints Unit (PCU), which will be responsible to receive, log, and resolve complaints; (ii) A Grievance Redress Committee (GRC), responsible to oversee the functioning of the PCU as well as the final non-judicial authority on resolving grievances that cannot be resolved by PCU; and (iii) Grievance Focal Points (GFPs), which will be educated people from each community that can be approached by the community members for their grievances against the Project. The GFPs are provided training by the Project in facilitating grievance redress. The stakeholders are informed of the establishment of the PCU through a short and intensive awareness campaign that will share the objective, function and the responsibilities of the PCU; means of accessing the PCU and the mechanics of registering a grievance at the PCU; operating principles of the PCU; and contact details of who to reach and how to reach them in order to file a complaint. A detailed procedure for the functions of the PCU is included in the ESIA and the draft LARP.


CDM-PDD-FORM Stakeholder engagement and consultation is addressed in several places in project documentation, covering various aspects, and is also incorporated into a single stand-alone Stakeholder Engagement Plan (SEP).

E.2. Summary of comments received >> Summary of concerns received from Community and other stakeholders and how they have been addressed is provided below: Table: Summary of Concerns Expressed in Scoping Consultation and How They Have Been Addressed in the ESIA

Issues raised by Community Stakeholders Addressed in the ESIA

Resettlement and Related

If anyone is losing their land/property due to the reservoir or camping site, adequate compensation should be provided to them

Will be addressed in Land Acquisition and Resettlement Plan (LARP)

Physical Environment and Related

There may be noise and disturbance during construction and blasting. Contractors should ensure that blasting activities are avoided at night and controlled blasting is carried out

Baseline sound measurements are taken at the receptors to ensure that the sound levels are below the tolerance levels (ESIA Section 5.2.7)

Construction activities may increase dust in the area and the local people may get sick

Ambient air quality monitoring has been carried out to establish baseline levels. Strict measures will be adopted to make sure that the health and livelihood is not affected in any way due to excessive dust and particulate matter in the air. (EIA Section 7.2.5 and 7.2.6)

Social and Other issues

The Project authorities will not follow mitigation measures proposed for the project.

Implementation of the EMMP is a legal and contractual obligation of the project proponent (ESIA Section 11)

Villagers should be given employment opportunities in the project

Recruitment from nearby communities will be given preference provided they meet the requirements for the job

Local villages should get uninterrupted supply of electricity at subsidized rates. The power produced from the Gulpur Hydropower Project should first attend to the local power demand.

Power distribution is not in legal mandate of MPL.

Construction of reservoir and changes in flow may result in limited availability of sand mining sites. Alternate sites should be provided to the locals dependent upon sand mining for livelihood.

Sand Mining Plan will be prepared by experts and alternate mining sites will be provided to the local community whose livelihood will be affected (ESIA- Appendix E)

In most of the villages, the stakeholders expressed the problems due to lack of development. The amenities that were demanded included link roads, school, teachers in school, clean drinking water, health facilities, sewerage system, rehabilitation of disabled people, and improvements of housing.

Although these issues are not in the scope of MPL, the Company is proposing to invest for social augmentation of the area (ESIA Section 11).

Wildlife/ Biodiversity Issues

Reduced flow downstream of the dam may result in lesser habitat available for the fish

MPL has specified a minimum Environmental flow in the low flow section (ESIA Section 6)


CDM-PDD-FORM Issues raised by Community Stakeholders Addressed in the ESIA

Reduced flow downstream may increase the concentration of contaminants in river water

The concentration of the toxic metals in the effluent from the Project were all found to be within the NEQS limits for liquid effluents as well as those for the drinking water. (ESIA Section 5.2). Mitigation and good practice measures have been identified and will be applied (ESIA Section 7)

Issues specific to women

Adequate water and access should be available for washing purposes

Access to the river for locals will not be obstructed and minimum flow will be released in the low flow stretch of the river

The project management of the power plant should ensure that the health and livelihoods of the locals are not be affected by the project.

Mitigation measures have been proposed to ensure that national and ADB standards for air and water quality are met (ESIA Section 5.2).

Figure: Photographs of Community Consultations

Consultation with Men at Aghar Consultation with Women at Aghar

Consultation with Men at Barali Consultation with Women at Barali

Consultation with Men at Bialian Consultation with Women at Bialian


CDM-PDD-FORM

Consultation with Men at Gulpur Consultation with Women at Gulpur

Consultation with Men at Hill Killan Consultation with Women at Hill Killan

Consultation with Men at Kameli Consultation with Women at Kameli

Consultation with Men at Kohali Consultation with Women at Kohali


CDM-PDD-FORM Consultation with Men at Naroch Colony Consultation with Women at Naroch Colony

Consultation with Men at Pagwari Consultation with Women at Pagwari

Consultation with Men at Rajdhani Consultation with Women at Rajdhani

Consultation with Men at Rehmani Mohallah Consultation with Women at Rehmani Mohallah

Table: Summary of Institutional Stakeholder Consultations and Comments

Issues raised Stakeholder Comments

PPIB awarded the contract for the development of Gulpur Hydropower Ltd in 2005 and the Poonch River was declared a national park in 2010 without consulting the PPIB or their counterpart in AJK (Azad Jammu and Kashmir). In view of the ongoing electricity shortages and load shedding, power generation is very important for the economy.

PPIB The Poonch River provides habitat for two fish species, Mahaseer (Tor putitora) and Kashmir Catfish (Glyptothorax kashmirensis) listed as Endangered and Critically Endangered respectively in the IUCN Red List 2013. Therefore, the Poonch River is a Critical Habitat according to IFC Guidelines whether or not it is declared a national park. Communication gaps between PPIB and AJK Government is not a Project concern. If EIAs were done on time then PPIB and developers would have known the environmental concerns.

How far back will the reservoir extend upstream of the Project location?

HWF The Project is a run of river (RoR) type hydropower project so no reservoir like the Mangla reservoir will be created. The water level in the River will rise but will not go beyond the flood line. No houses will be submerged and no agricultural land will be lost

The Poonch River is an ecologically HWF The Cumulative Impact Assessment of the planned


CDM-PDD-FORM Issues raised Stakeholder Comments sensitive river, and provides habitat for fish of conservation and socio-economic importance. So PPIB should not authorize any more projects on this river.

hydropower projects on the Poonch river is being investigated. Only when this is done, we can determine if there is room for any more projects. Keeping in view the ecological sensitivity of the Poonch River, it seems unlikely that more hydropower projects can be built and can achieve the net gain for conservation as proposed in the IFC guidelines. If any more Projects are to be sanctioned on the Poonch River at all, it is recommended that they be considered first downstream of the Gulpur Hydropower Project. This will avoid blocking the important fish breeding areas located in the Ban Nallah and Rangar Nallah

The information document provides information only about baseline biodiversity assessment surveys done in October. How will seasonality be captured?

WWF-P In addition to literature reviews, field surveys have been conducted in June (for the ESIA), October and December (fish survey). Spring surveys are scheduled for April 2014. So seasonal variations in biodiversity will be captured. Full details are available in the Baseline Biodiversity Assessment Report that can be shared with the stakeholders upon request.

Local communities in the Poonch River basin will be affected by decline in fish resources. They are also dependent on sand and gravel extraction from the river bed for construction. How will this be dealt with?

HWF A draft Biodiversity Management Plan has been developed and work is in progress for the Biodiversity Action Plan. Measures to conserve the fish resources include reactivation and rehabilitation of the Mangla hatchery and stocking the fish like Mahaseer upstream of the Project location. If the protection measures outlined in the Pro 2 scenario are implemented and the Biodiversity Action Plan is implemented, a net gain for conservation can be achieved. However, the 0.7 km stretch of the River that will experience low flows due to Project operations is likely to suffer negative ecological impacts. But this is only 0.7% of the total length of the Poonch River in Pakistan. As for sand and gravel extraction, a sand and gravel mining plan will be developed and locals will be allowed to extract the sand and gravel trapped upstream of the dam (of the Project).

Have fish ladders been incorporated in to the Project design

Independent Ecologist

According to the feedback provided by local and international fish experts, fish ladders are seldom successful, and are not going to be useful for protecting the fish species of the Poonch River especially considering the gradient of the landscape.

We are depending on the AJK Fisheries and Wildlife department to implement the environmnetal conservation and protection measures while we know that they are inefficient. The Poonch River is already a national park yet conservation measures are presently inadequate.

HWF Subject to agreement with government of AJK on the Biodiversity Action Plan (BAP) for the project, The AJK Fisheries and Wildlife Department will have to sign an agreement for effective implementation of the conservation and protection measures outlined in the BAP. In addition, there will be external third party monitoring to ensure that goals are being met. Training and capacity building measures for the AJK Wildlife and Fisheries Department will be included in the BAP.

What about the impacts of Project construction and operation on the terrestrial biodiversity of conservation importance such as the Common

WWF-P Terrestrial Impact Assessment of the Project has been completed, and no significant impact of the Project on the terrestrial ecological resources is expected, considering the small size of terrestrial habitats that


CDM-PDD-FORM Issues raised Stakeholder Comments Leopard, vultures as well as the aquatic mammals particularly the Otter?

will be inundated due to Project construction. Signs of otters were absent from the Project location and vicinity. Otters are present upstream and downstream of the dam but they are not likely to be impacted. Otters depend on impact on fish population as fish is the main source of food for the otter. If fish abundance increases assuming Pro2 Scenario, then the otters will benefit. The Project design will include adequate facilities for solid waste disposal and waste water treatment to minimize impacts on the terrestrial and aquatic resources.

As long as the BAP assures improvement in ecosystem integrity as defined in the Enhanced Protection or Pro2 scenario, 4 cumecs eflow is acceptable.

HWF Noted.

There could be some potential positive ecological impacts in the river stretch that will experience low flows due to Project operations. These may include an increase in the number of waders and birds that prefer to sit on slow moving water with a consequent increase in their predator bird species. The droppings of these birds will increase the organic contect in the dewatered river stretch.

Independent Ecologist

Noted. Comments will be incorporated in to the Final Impact Assessment Report.

Data on the forest area that will be damaged by the project has not been provided. Plantation will be required to compensate for the vegetation lost.

Forest Department

The section on terrestrial ecology in the ESIA will provide this detail. There is only scrub cover in the area that will be used by the Project, and only a limited area in the ownership of Forest Department will be required for the project. A budget for plantation and re-vegetation will be allocated in the EMMP.

General opinion of all the participants was that commitments made in ESIA for environmental improvements and CSR are not kept by the project owners. The participants provided examples of other hydropower projects in AJK where this had occurred. Concern was expressed that the BAP and CSR commitments will not be implemented

EPA will not comment on the EFlow at this point. The EPA will review the EIA to be submitted by the Project Owner and will give its opinion after examining the analysis and justification provided for the suggested flow in the EIA

EPA-AJK Peaking flow which causes substantial damage to downstream section of the river will be avoided. After switching to Option 3 in design the low flow section of the river downstream of the dam and upstream of the power house where major impacts will occur is only 700 meters. A net gain will be achieved through implementation of the BAP in the remaining stretches of the river.


CDM-PDD-FORM Figure: Photographs of the Institutional Stakeholder Consultations

Consultation with Deputy Commissioner, Kotli Consultation with Traders Association, Kotli

Consultation with Superintendent Police, Kotli Consultation with HWF, WWF, SLF, PPIB and Scientists

Consultation with HWF, WWF, SLF, PPIB and Scientists Consultation with EPA-AJK, HEB-AJK and Forest

Department-AJK

E.3. Report on consideration of comments received All the comments were addressed and has been provided in above Section E.2. SECTION F. Approval and authorization Approval for Construction in National Park 21/05/2014 Issuance of Environmental NOC from Environmental Protection Agency 18/06/2014 Approval of Wildlife & Fisheries Department for Execution of BAP Implementation Agreement 19/02/2016


CDM-PDD-FORM

Appendix 1. Contact information of project participants and responsible persons/ entities

Project participant and/or responsible person/ entity

Project participant Responsible person/ entity for application of the selected methodology (ies)

and, where applicable, the selected standardized baselines to the project activity

Organization name Mira Power Limited Street/P.O. Box Street # 1 Building Square 11 Plaza, MPCHS, E-11/1 City Islamabad State/Region Federal Capital Postcode 44000 Country Pakistan Telephone +925121000985 Fax +92512114359 E-mail [email protected] Website www.mira-power.com Contact person Title Chief Executive Officer Salutation Last name Middle name - First name Department Mobile +923449777790 Direct fax +92512114359 Direct tel. +92512100985-86 Personal e-mail [email protected]



http://www.mira-power.com/


CDM-PDD-FORM Appendix 2. Affirmation regarding public funding

There is no public funding or Official Development Funding Assistance is involved in financing of the Project.


CDM-PDD-FORM

Appendix 3. Applicability of methodology and standardized baseline

The applicability of the methodology has been discussed in chapter B.2. No further discussion is required.


CDM-PDD-FORM

Appendix 4. Further background information on ex ante calculation of emission reductions

The below tables summarise the data and calculations to calculate the EF of National Grid. Please see attached spreadsheet for more information. A. Percentage of Least Cost/Must Run Plant of National Grid (Last 5 Years Grid Data)

GROSS GENERATION OF PAKISTAN (NATIONAL GRID & KESC GRID) Source: Pakistan Energy Yearbook 2014 (Table 5.2)

SOURCE/Years 2010-11 2011-12 2012-13 2013-14 2014-15

HYDEL 31,811 28,517 29,857 31,873 32,474

THERMAL 59,152 61,308 61,711 66,706 67,886

WAPDA 14,112 13,605 14,148 14,236 12,133 KESC 7,826 8,029 8,567 8,709 9,318

IPPs 37,214 39,674 38,996 43,761 46,435

NUCLEAR 3,420 5,266 4,553 5,090 5,804

KANUPP (KESC) 221 514 606 328 404 CHASHNUP-I 2,731 2,294 2,295 2,376 2,656 CHASHNUP-II 468 2,458 1,652 2,386 2,744

Renewable 802

IMPORTED 269 274 375 419 443

National Grid + KESC Grid 94,652 95,365 96,496 104,088 107,409

KESC IPPs 1,575 959 1,144 1,402 1,538

Gul Ahmad 771 469 450 592 718 Tapal Energy 804 491 695 811 820

KESC Grid 9,622 9,502 10,317 10,439 11,260

NATIONAL GRID 85,030 85,863 86,179 93,649 96,149.10

Least Cost/ Must Run 35,010 33,269 33,804 36,635 38,676

% of LCMR to National Grid 41.17% 38.75% 39.23% 39.12% 40.23% Note: (i) Generation used for KESC Grid is excluded (ii) LCMR must be less than 50% of generation to use simple OM to calculate EFOM value


CDM-PDD-FORM B. OM Calculation

(1) Fuel Consumption (Both National Grid & KESC Grid)

Fuel Consumption for Thermal Power Generation (2013-14)

Both Grids (National Grid & KESC Grid)

Type of Fuel Quantity Conversion

Factor Quantity (TJ)

Natural Gas (MMCFT) 362,262.00 0.88590 320,927.86 Furnace Oil (thousands Tonnes) 7,541.09 39.80000 300,135.22 Diesel Oil (thousands metric tons) 207.92 41.40000 8,607.81 Coal (Thousands Metric Tons) 63.04 21.60000 1,361.64 Source: Pakistan Energy Yearbook 2013 (Table 3.9 - Natural Gas Consumption by Power Sector in Million CFt) Pakistan Energy Yearbook 2013 (Table 2.9 - Furnace Oil Consumption by Power Sector in Tonnes) Pakistan Energy Yearbook 2013 (Table 2.9 - HSD Consumption by Power Sector in Tonnes) Pakistan Energy Yearbook 2013 (Table 4.4 - Coal Consumption by WAPDA in Tonnes)

Fuel Consumption for Thermal Power Generation (2012-13) Both Grids (National Grid & KESC Grid)




Fuel Consumption for Thermal Power Generation (2012-13) Both Grids (National Grid & KESC Grid)





CDM-PDD-FORM (2) Fuel Consumption (KESC Grid)

Fuel Consumption for Thermal Power Generation (2014-15) KESC Grid Only

S/No Power Plant Fuel Type Technology

Generation GWh Efficiency

Quantity (TJ)

1 GTPS Korangi (ST) Gas Steam Turbine 435.10 37.50% 4,176.96 2 GTPS Site Gas Gas Turbine 159.70 30.00% 1,916.40 3 TPS Bin Qasim Gas Steam Turbine 1,802.50 37.50% 17,304.00 FO Steam Turbine 2,122.40 37.50% 20,375.04 4 Korangi CCP Gas Combined Cycle 891.60 60.00% 5,349.60 5 TPS Bin Qasim-II Gas Steam Turbine 3,907.10 37.50% 37,508.16 FO Steam Turbine 0.00 37.50% 0.00 6 Gul Ahmad (IPP) FO Diesel Engines 718.00 46.00% 5,619.13 7 Tapal Energy (IPP) FO Diesel Engines 819.90 46.00% 6,416.61

TOTAL GENERATION & FUEL HEAT VALUE

FO 3,660.30 32,410.78

Gas 7,196.00 66,255.12 Source: Pakistan Energy Yearbook (Table 5.11 - Energy Data of Thermal Power Generation) Appendix 1: Default Efficiency Factor for Power Plant - Tool to calculate the emission factor for an electricity system


KESC Grid Only



Quantity (TJ)

1 GTPS Korangi (ST) Gas Steam Turbine 392.90 37.50% 3,771.84 2 GTPS Site Gas Gas Turbine 113.00 30.00% 1,356.00 3 TPS Bin Qasim Gas Steam Turbine 1,865.00 37.50% 17,904.00 FO Steam Turbine 1,900.30 37.50% 18,242.88 4 Korangi CCP Gas Combined Cycle 798.90 60.00% 4,793.40 5 TPS Bin Qasim-II Gas Steam Turbine 3,639.30 37.50% 34,937.28 FO Steam Turbine 0.00 37.50% 0.00 6 Gul Ahmad (IPP) FO Diesel Engines 591.90 46.00% 4,632.26 7 Tapal Energy (IPP) FO Diesel Engines 810.50 46.00% 6,343.04


FO 3,302.70 29,218.18 Gas 6,809.10 62,762.52

Source: Pakistan Energy Yearbook (Table 5.11 - Energy Data of Thermal Power Generation) Appendix 1: Default Efficiency Factor for Power Plant - Tool to calculate the emission factor for an electricity system


KESC Grid Only



Quantity (TJ)

1 GTPS Korangi (ST) Gas Steam Turbine 326.60 37.50% 3,135.36

2 GTPS Site Gas Gas Turbine 156.00 30.00% 1,872.00 3 TPS Bin Qasim Gas Steam Turbine 1,446.30 37.50% 13,884.48 FO Steam Turbine 2,276.10 37.50% 21,850.56


CDM-PDD-FORM 4 Korangi CCP Gas Combined Cycle 795.10 60.00% 4,770.60 5 TPS Bin Qasim-II Gas Steam Turbine 3,567.20 37.50% 34,245.12 FO Steam Turbine 0.10 37.50% 0.96 6 Gul Ahmad (IPP) FO Diesel Engines 449.60 46.00% 3,518.61 7 Tapal Energy (IPP) FO Diesel Engines 694.50 46.00% 5,435.22


FO 3,420.30 30,805.35 Gas 6,291.20 57,907.56

Source: Pakistan Energy Yearbook (Table 5.11 - Energy Data of Thermal Power Generation) Appendix 1: Default Efficiency Factor for Power Plant - Tool to calculate the emission factor for an electricity system

(3) Fuel Consumption (National Grid)


National Grid



Natural Gas (MMCFT) 262,911.61 Furnace Oil (thousands Tonnes) 304,173.64 Diesel Oil (thousands metric Tonnes) 538.34 41.40000 22,287.11 Coal (Thousands Metric Tonnes) 151.18 21.60000 3,265.49 Note: Subtracting Fuel Consumption of KESC Grid from total fuel consumption will result fuel consumption of National Grid No Coal and Diesel were used by KESC Grid in 2015


National Grid





National Grid





CDM-PDD-FORM

(4) Operating Margin (National Grid)

OPERATING MARGIN: Data for 3 years (2012-2014) National Grid

Fuel type and year

Fuel Consumption

(TJ)

Power Generation

GWh CO2 emissions

tonnes

2013 Natural gas 263,020 20,825 14,282,002

Fuel oil 269,330 30,735 20,334,406 Diesel oil 8,608 379 624,927

Coal 1,362 61 128,811

2014

Natural gas 246,890 19,860 13,406,154 Fuel oil 317,678 35,391 23,984,657

Diesel oil 12,011 1,187 871,969 Coal 3,471 157 328,388

2015

Natural gas 262,912 21,156 14,276,101 Fuel oil 304,174 32,772 22,965,110

Diesel oil 22,287 2,957 1,618,044 Coal 3,265 145 308,915

Total 165,625

113,129,485

(tCO2/MWh) 0.68305 Sources (1): Fuel Consumption for National Grid is calculated in sheets Fuel-2013, Fuel-2014 & Fuel 2015 Sources (2):Pakistan Energy Yearbook 2015 Table 5.11, 2014 Table 5.11, 2013 Table 5.11 Note: Electricity generation from the KESC grid is not taken into account


CDM-PDD-FORM

C. BM Calculation

Date of 2015 Plant Total

Fuel Emiss/Oxid/ Emission

Project Name

Commiss- Ioning

Fuel Tech- nology

Gene ration

Effici ency

Heat Value

Mass Conv

GWh TJ Factor CO2 t Total National Grid (excl KESC) 96,149 20% of National Grid 19,229.84

Uch-II Power Apr-14 Gas CCGT 2,415.00 60% 14,490.00 54.30 786,807.00 Gomal Zam Jun-15 Hydro 43.86 - - - - Allai Khwar Mar-13 Hydro 461.78 - - - Jinnah Oct-13 Hydro 190.69 - - - Duber Khwar Dec-13 Hydro 386.83 - - - - Khan Khwar Mar-12 Hydro 253.00 - - - Halmore Power Jun-11 Gas CCGT 103.20 60% 619.20 54.30 33,622.56

Diesel 620.30 46% 4,854.52 72.60 352,438.28 Foundation Power May-11 Gas CCGT 1,322.20 60% 7,933.20 54.30 430,772.76

Diesel 0.40 46% 3.13 72.60 227.27 HUBCO Narowal Apr-11 FO

Diesel Engines 1,418.20 45% 11,345.60 75.50 856,592.80

CHASHNUP-II Jan-11 Nuclear Nuclear 2,744.00 - - - Liberty Power Tech Jan-11 FO DE-ST 1,515.00 45% 12,120.00 75.50 915,060.00 Saphire Electric Oct-10 Gas CCGT 281.50 60% 1,689.00 54.30 91,712.70

Diesel 685.00 46% 5,360.87 72.60 389,199.13 Nishat Chunian Jul-10 FO DE+ST 1,415.00 45% 11,320.00 75.50 854,660.00 Nishat Jun-10 FO RE+ST 1,448.70 45% 11,589.60 75.50 875,014.80 Orient Power Co May-10 Gas CCGT 311.50 60% 1,869.00 54.30 101,486.70

Diesel 725.80 46% 5,680.17 72.60 412,380.63 Engro Energy Mar-10 Gas CCGT 1,429.00 60% 8,574.00 54.30 465,568.20 Atlas Power Dec-09 FO CCGT 1,461.70 46% 11,439.39 75.50 863,674.04 Attock Gen Mar-09 FO DG+ST 1,209.00 45% 9,672.00 75.50 730,236.00

Total 20,442 8,159,452.87 Build Margin =

0.3992


CDM-PDD-FORM D. CM Calculation Combined Margin Emission Factor

WOM = 0.5 (Weighting of operating margin emission Factor) Default Value WBM = 0.5 (Weighting of build margin emission Factor) Default Value

COMBINED MARGIN EMISSION FACTOR OF NATIONAL GRID

Weight Emission factor

(tCO2/MWh) 0.50 0.68305

(tCO2/MWh) 0.50 0.39916

(tCO2/MWh) 0.54110

Baseline Emission =

= Quantity of net electricity generation fed into grid 474,996 MWh= 257,022 (tCO2/yr)


CDM-PDD-FORM

Appendix 5. Further background information on monitoring plan

Comprehensive Monitoring Information is provided in Section B.7. No further detail is required.


CDM-PDD-FORM

Appendix 6. Summary of post registration changes


Documents

PROJECT DESIGN DOCUMENT (PDD) Projects...Gulpur Hydropower Project (“the Project”) is a new scheme of 102 MW run-of-river (“ROR”) hydroelectric power project on Poonch River