ecba 4 renewable energy kalimantan technical report

Renewable Energy Options in Kalimantan: A Green Growth Assessment Extended cost benefit analysis of four renewable energy projects Component 1B: Green Growth Assessment of Capital Projects Government of Indonesia - GGGI Green Growth Program

Final draft for discussion, not to be quoted February 2015

DRAFT FOR DISCUSSION

Table of Contents EXECUTIVE SUMMARY .................................................................................................................................. 8 1 INTRODUCTION .............................................................................................................................. 19 2 OPTIONS FOR ELECTRICITY PRODUCTION IN KALIMANTAN .......................................................... 25 3 METHODOLOGY ............................................................................................................................. 32 4 SCOPE OF ANALYSIS ....................................................................................................................... 42 5 RESULTS AND FINDINGS................................................................................................................. 48 6 POLICY IMPLICATIONS ................................................................................................................... 74 APPENDIX A MODEL ARCHITECTURE .................................................................................................. 87 APPENDIX B STAKEHOLDER COMMENTS............................................................................................ 88

DRAFT FOR DISCUSSION

List of Figures Figure 1: The five desired outcomes of green growth developed with key stakeholders in Indonesia . 8 Figure 2: Map of project locations in Kalimantan ................................................................................. 10 Figure 3: Financial analysis; comparison of the 4 renewable technologies.......................................... 11 Figure 4: eCBA analysis; comparison of the 4 renewable energy technologies ................................... 12 Figure 5: Potential net benefits from full deployment, and associated investment needs ................. 17 Figure 6: The five desired outcomes of green growth developed with key stakeholders in Indonesia .............................................................................................................................................................. 20 Figure 7 : Stages in conducting project-level eCBA............................................................................... 22 Figure 8: Stylized overview of a “greened” planning and project appraisal process in Indonesia ....... 24 Figure 9: Installed Generation Capacity in Indonesia (MW) ................................................................. 25 Figure 10: National Installed Capacity of Power Plant by Type (MW) .................................................. 26 Figure 11: Indonesia’s Projected CO2 Emissions from Power Generation ........................................... 27 Figure 12: Source of Power for Electricity Generation in Kalimantan (MW) ........................................ 28 Figure 13 Map of project locations in Kalimantan ................................................................................ 30 Figure 14: An impact pathway .............................................................................................................. 42 Figure 15: Financial analysis; comparison of the 4 renewable energy technologies ........................... 52 Figure 16: International benchmarks for capital costs and levelized costs .......................................... 55 Figure 17: eCBA analysis; comparison of the 4 renewable energy technologies ................................. 58 Figure 18: Potential net benefits from full deployment, and associated investment needs ............... 65 Figure 19: Variation in financial Net Present Value .............................................................................. 71 Figure 20: Variation in Extended Net Present Value ............................................................................ 72 Figure 21: Architecture of eCBA model ............................................................................................... 87

DRAFT FOR DISCUSSION

List of Tables Table 1: Summary of key policy suggestions ........................................................................................ 15 Table 2: National Energy Potential, 2005 ............................................................................................. 26 Table 3: Opportunity cost of electricity generated in Central Kalimantan ........................................... 33 Table 4: Key assumptions applied across the analysis.......................................................................... 35 Table 5: Renewable energy potential in Megawatts by technology and province .............................. 40 Table 6: Impact Pathways for renewable energy ................................................................................. 44 Table 7: Summary of results and findings (USD million)....................................................................... 48 Table 8: Summary of costs and benefits in each scenario .................................................................... 50 Table 9: Investment cost by technology and province ......................................................................... 67 Table 10: Net benefits by technology and province ............................................................................. 67 Table 11: Variation of input variables in sensitivity analysis (financial) ............................................... 69 Table 12: Variation of input variables in sensitivity analysis (eCBA) .................................................... 70 Table 13: Summary of key policy suggestions ...................................................................................... 84 Table 14: Stakeholder comments ......................................................................................................... 88

DRAFT FOR DISCUSSION

Glossary Acronym

Explanation

AMDAL BAU

Analisis Dampak Lingkungan Environment Impact Assessment Business As Usual

BCR

Benefit-Cost ratio

BPS c/kWh

Badan Pusat Statistik Statistics Indonesia US cents per Kilowatt Hour

CDM

Clean Development Mechanism

CO2

Carbon Dioxide

eCBA

Extended Cost Benefit Analysis

DNPI

FiT

Dewan Nasional Perubahan Iklim National Climate Change Committee Kementrian Energi dan Sumber Daya Mineral Ministry of Energy and Mineral Resources Feed In Tariff

Feasibility Study

GIMS

Green Industry Mapping Study

GGA

Green Growth Assessment

GGAP

Green Growth Assessment Process

GGF

Green Growth Framework

GGGI

Global Green Growth Institute

GHG

Green House Gas

GIZ

Gesellschaft f端r Internationale Zusammenarbeit

GoI

Government of Indonesia

IDR

Indonesian Rupiah

IIGF IPCC

PT Penjamin Infrastruktur Indonesia Indonesia Infrastructure Guarantee Fund Intergovernmental Panel on Climate Change

IPP

Independent Power Producer

IRR

Internal Rate of Return

IUPTL

kWh

Ijin Usaha Penyediaan Tenaga Listrik Electricity Supply Business Permit Kawasan Ekonomi Khusus Special Economic Zone Kawasan Strategis Nasional Strategic National Zone Kilowatt hour

LCOE

Levelized Cost Of Electricity

M&E

Monitoring and Evaluation

m/s

Meter per second

MCC

Millennium Challenge Corporation

ESDM

KEK KSN

DRAFT FOR DISCUSSION Menhut MHP

Kementrian Kehutanan Ministry of Forestry Micro Hydro Power

MP3EI

Master Plan for the Acceleration of Economic Development

MtCO2

Megatonne of Carbon Dioxide

Mega Watt

NOx

Nitrogen Oxides

NPV

Net Present Value

PDD

Project Design Document

PLTBm

Pembangkit Listrik Tenaga Biomassa Biomass Power Plant Pembangkit Listrik Tenaga Mikro Hidro Micro Hydro Power Plant Perusahaan Listrik Negara National Utility Company Particular Matter

POME

Palm Oil Mill Effluent

PPA

Power Purchase Agreement

PPU

Private Power Utility

PwC

Pricewaterhouse Coopers

REDD+

Reducing Emissions from Deforestation and Forest Degradation

RUED

Rencana Umum Energi Daerah

RUKN

sCBA

Rencana Umum Ketenagalistrikan Nasional National Electricity Plan Rencana Usaha Penyediaan Tenaga Listrik Electricity Supply Business Plan Social Cost Benefit Analysis

SDR

Social Discount Rate

SHS

Solar Home System

SOC

Social Opportunity Cost

Solar PV

Solar Photovoltaic

SOx

Sulfur Oxides

tCO2

Tonnes of Carbon Dioxide

TEV

Total Economic Value

United Nations

UNFCCC

United Nations Framework Convention on Climate Change

VAT

Value Added Tax

WACC

Weighted Average Cost of Capital

WHO

World Health Organization

PLTMH PLN

RUPTL

DRAFT FOR DISCUSSION

GoI-GGGI Green Growth Program Our joint Government of Indonesia (GoI) and Global Green Growth Institute (GGGI) goal “To promote green growth in Indonesia that recognizes the value of natural capital, improves resilience, builds local economies and is inclusive and equitable”. To achieve this, GGGI provides technical support, research and capacity building that is in line with GoI’s vision and direction

Our objectives The specific objectives of the GoI-GGGI Green Growth Program are: 1. 2. 3.

4. 5.

To ensure the green growth vision matches or exceeds existing development targets; To track the achievement of green growth priorities of Indonesia by providing relevant targets and indicators; To evaluate the implications of the country’s current development path against green growth targets and indicators and assessing projects and potential policy and investment interventions against this baseline; To identify the key sectors and high potential green growth projects and investment interventions that will help deliver green growth development; To harness private sector engagement and investment in support of delivering green growth opportunities in Indonesia; To undertake economic modeling to analyze each project showing the financial returns and identifying any gaps in the incremental spend required to secure green projects

How GoI and GGGI will meet these objectives The program has three complementary work components: “To mainstream green growth within Indonesia’s economic and development planning processes”

Greening the planning process

REDD+ for green growth

“To support the development of a funding mechanism that disburses REDD+ finance to catalyze green growth”

Regional engagement

“To support key provincial governments in prioritizing and implementing green growth”

“To increase the use of green technology and increase capital investment in green industry” (GIMS)

The combined work of these components will help to achieve the objectives and the overarching goal of GoI and GGGI.

DRAFT FOR DISCUSSION

Executive Summary Introduction The Government of Indonesia (GoI)-Global Green Growth Institute (GGGI) Green Growth Program for Indonesia aims to promote green growth in Indonesia that recognizes the value of natural capital, improves resilience, builds local economies and is inclusive and equitable. A fundamental part of this will be mainstreaming green growth within Indonesiaâ&#x20AC;&#x2122;s economic and development planning processes. To this end, GGGI and GoI are developing a framework and suite of tools that can be used by GoI to help embed green growth concepts into existing planning and investment appraisal instruments. Full details of the framework can be found in an accompanying report1, but the essence of the framework is to make green growth measurable along the desired five outcomes outlined in Figure 1 below. These outcomes are interrelated and a positive contribution to one can often simultaneously provide benefits to others. Only by making progress along all of these outcomes can Indonesia plan for inclusive and equitable growth that is sustainable over the course of generations. Figure 1: The five desired outcomes of green growth developed with key stakeholders in Indonesia

Similarly, full details of the range of tools needed to embed green growth within planning processes can be found in accompanying reports2, but at the heart of the suite of tools lies a comprehensive and integrated assessment of the monetary Costs and Benefits of capital projects in Indonesia. This includes, but is not limited to, those projects contained in the Master Plan for the Acceleration of Economic Development (MP3EI). This green growth assessment must not only look at financial costs and benefits but economic, social and environmental costs and benefits as well: an Extended Cost Benefit Analysis (eCBA). An eCBA can be used by decision makers in government and the private sector to answer key questions such as: 1

GGGI (2015) Scoping green growth in Indonesia. Working Paper GGGI Indonesia Program GGGI (2015) The Role of Extended Cost Benefit Analysis in Public Policy and Planning in Indonesia. Working Paper GGGI Indonesia Program 2

DRAFT FOR DISCUSSION      

What is the green growth performance of the project compared to a Business As Usual scenario? What is the value to the economy, society and the environment of this project and performance? How can one re-design a project to improve its green growth performance? What are the synergies and trade-offs among the different outcomes of green growth in doing this? How much capital investment is required to achieve this improved performance? What policy instruments are needed to drive investment and behavioural change?

Thus, a project-level eCBA can be viewed as an analytical tool that governments can use to identify the monetary values of public goods, environmental externalities and social returns associated with many projects. In this sense, results of an eCBA can be used as part of a base of evidence to determine the size of public and private investment flows needed to maximize these values enhancements over time. This report is the fourth in a series performing project-level eCBAs on selected investments across Indonesia. This report also looks at the implications for the Kalimantan economic corridor as a whole. Electricity in Kalimantan The current energy situation in Kalimantan and specifically in Central Kalimantan is characterized by a shortage of supply, a significant number of households (42%) still lacking access to the grid, high fossil fuel content in generation (91%), including imported diesel (66%). Looking ahead, the main change to this situation on-grid is likely to be the construction of new coal fired power plants, which may alleviate cost and supply issues, but not environmental concerns. Furthermore, this benefits only households and businesses connected to the grid. Off-grid, renewables have increasingly penetrated the energy mix (around 50% in 2010), but still have a low base in Kalimantan, and diesel generator sets (“gensets”) are still the electrification solution of choice for many communities. Clearly, the implementation of green energy technology faces challenges. But, there are examples of ongoing and proposed new renewable energy projects in Kalimantan. For this analysis, we3 have selected four of these projects from Central and East Kalimantan with various operational and regulatory setups: micro hydro, solar PV, biomass (woodchip), and biogas (POME). 1.

The micro hydro (MHP) project is planned to be installed in the village of Tumbang Kunyi, Sumber Barito district, Murung Raya regency, Central Kalimantan. Based on the feasibility study, a 130kW plant is proposed, which would supply electricity to around 430 homes and 40 other users over a low-voltage mini-grid. Previously, communities were relying on diesel generators and kerosene lamps for power and lighting.

2. The solar PV project is an early-stage analysis in the village of Sungai Gula, Permata Intan district, Murung Raya regency, Central Kalimantan. A 140kW Solar PV array is proposed here, which would supply power to around 300 homes and 12 other users over a lowvoltage mini-grid. Currently, some households have diesel gensets and some have no power at all. The village is expected to install a mini-grid 140kW diesel generator in the absence of renewables investment. 3. The biomass (woodchip) project in Natai Peramuan village, Kumai district, Kotawaringin regency, Central Kalimantan was registered under the UN Clean Development 3

Throughout this document “we” refers to the GGGI project team

DRAFT FOR DISCUSSION Mechanism in 2012, and uses waste residue from chipping operations to power a 7.3 MW biomass generator. The electricity generated powers the chipping mill and the excess power (around half the kWh) is sold back to PLN on the grid. Without this project, the chipping mill would buy power from the grid, which in Central Kalimantan is diesel and coal dominated. Although the project is CDM-registered, it has not issued any carbon credits to date. 4. The biogas (Palm Oil Mill Effluent; POME) project in Muai village, Kembang Janggut district, Kutai Kartanegara regency, East Kalimantan, has been operational since 2012, and captures biogas from wastewater treatment in a palm oil mill.The project is CDMregistered and has issued 27,782 CERs to date. The biogas is fed to two biogas engine with generator sets, with a total capacity of 2.1 MW to power the palm oil mill. There is no excess power and any excess biogas is flared in an enclosed system. Prior to the project, the electricity was generated with a biomass boiler running on palm kernel shell and palm oil fibro as well as a number of diesel generator sets. Figure 2: Map of project locations in Kalimantan

DRAFT FOR DISCUSSION Results and Findings: The Projects4 Looking solely at the cashflows expected from these four projects, and based on a range of assumptions, we find that two technologies (micro hydro, solar PV) are unattractive to private investors (at a cost of capital of 10%) without additional public support. The Micro hydro project generates a negative Net Present Value (NPV) and the Solar PV project generates an NPV ten times lower. We note here that some of the costings in the feasibility studies (FS) are quite high: higher than we would expect. However, even moving these costs in line with regional benchmarks does not change the fact that these projects are unlikely to be attractive private investments based on commercial returns. Biomass (woodchip) and biogas (POME) are considered to be attractive to private investors with IRRs of 12.1% for biomass (woodchip) and 16.0% for biogas (POME). These findings are illustrated in Figure 3 below. This should not draw the conclusion that micro hydro and solar PV technologies are not appropriate for government incentive schemes. Technology learning rates, particularly for solar, 5 are reducing costs at a rapid rate and it may become cost effective in the near future.

2,860

3,000

NPV

30%

IRR 1,752

2,000

16.0% 12.1%

1,000 -290

-302

Benchmark

-2,796

-1,000

-5.3% Micro Hydro

-6.8%

Benchmark Solar PV

20%

10%

-640

Intenral Rate of Return

Thousand USD

Figure 3: Financial analysis; comparison of the 4 renewable technologies

0% FS

Woodchip

POME

-10%

-2,000

-20%

-3,000

-30%

-4,000 Note: FS = Feasibility Study data. Benchmark = Substituting some FS data for international benchmarks (see relevant section for explanation)

-40%

The quantitative results throughout this report are derived from a Microsoft Excel file entitled â&#x20AC;&#x153;GGGI Indonesia- eCBA Technical Model- Renewable Energy Projects- December 2014- v.1.1.xlsxâ&#x20AC;? 5

World Energy Outlook, International Energy Agency (2014)

DRAFT FOR DISCUSSION Conducting an Extended Cost Benefit Analysis tells a more comprehensive story. Accounting for economic benefits that accrue to communities no longer reliant on expensive diesel or kerosene fuel, and also valuing social and environmental benefits of more reliable and cleaner energy, we estimate that all four technologies provide net social benefits as long as cost control can be maintained. The Economic Rates of Return range with Economic Rates of Return all above 25% (replacing certain Feasibility Study assumptions). These findings are illustrated in Figure 4 below.

110,000

NPV

220%

102,414

IRR

100,000

200%

90,000

180%

80,000

160%

70,000

121%

60,000 50,000

120% 100%

85% 39,068

40,000 55%

30,000

50%

20,000 10,000

40%

26% 3,844

2,375

Benchmark

-910 1%

80% 60%

20%

1,300

-10,000

140%

Economic Rate of Return

Thousand USD

Figure 4: eCBA analysis; comparison of the 4 renewable energy technologies

0% MHP

Benchmark Solar PV

Woodchip

POME

-20%

Note: FS = Feasibility Study data. Benchmark = Substituting some FS data for international benchmarks (see relevant section for explanation)

The benefits of this value across the four projects can be broken down as follows: •

Economic Growth benefits of $83m; the value of avoided generation cost by PLN (and associated subsidy by Ministry of Finance) and diesel and kerosene fuel savings for local communities, minus capital and operational costs. Proportionately more of the income benefits derive from the community renewables projects (Micro Hydro Power and Solar PV). This estimate is dependent on our assumptions of fuel subsidies, oil prices and the baseline generation costs discussed in chapters 2 and 3.

•

Social Development benefits of $1m; the value of better educational attainment from longer and more productive studying hours, and better health from reduced indoor air pollution. Proportionately more of the social benefits derive from the community renewables projects (Micro Hydro Power and Solar PV). Because these projects are small in MW terms, these benefits appear small; but, they would be of an order of magnitude higher if the projects were replicated to the same level as the industrial projects.

•

GHG Emissions benefits of $61m; reduced CO2 emissions as kerosene and diesel displaced from village fuel mixes, and from reduced coal and diesel generation from on-grid power plants. The social cost of carbon is valued at USD 80/tCO2. Proportionately more of the GHG benefits derive from the POME and Biomass projects.

DRAFT FOR DISCUSSION There may also be indirect ecosystem benefits. For example, in the case of micro-hydro, it has been observed that as water flow becomes a key economic asset for communities, the incentive to protect upstream assets and report illegal logging was significantly increased. Communities are also more resilient to fluctuations in fuel prices (a big issue at the time of writing) while improved health and education outcomes means that they are more socially resilient. If the economic benefits are large and positive, then why are the financial returns limited in some cases? While the economic benefits for the larger public are large and positive, private financial returns are limited in some cases. On-grid, the reduced consumption of diesel would not only reduce GHG emissions, but reduce fiscal pressures for PLN and/or Ministry of Finance. But the business model for several off-grid technologies is intractable, as socially-acceptable and affordable tariffs would cover running costs but not the investment costs with interest. This is true even though it is less than the cost of diesel in the long-run, because only some households have access to diesel in the first place but everyone pays for electrification. In this instance, green growth pays for itself, with profit, if all parties’ impacts are taken into account. As mentioned above, for several off grid technologies this is not the case and policy implications discussed below are required to create the right circumstances for the more promising opportunities to succeed. If successful, such policies and green growth interventions would generate significant social and environmental co-benefits for local communities. Policy Implications for the Kalimantan Corridor The quantitative analysis that was undertaken for this study suggests two major conclusions: 1.

Renewable energy technologies in the geographies and markets considered provide a strong positive net social benefit (based on assumptions adopted in the analysis).

2. But, under current market prices, the incentive to invest is limited. This is true even after the raising of fossil fuel prices on 1 January 2015. Given these two points and the large public benefits and co-benefits, there is a clear rationale for public policy intervention. Important steps have already been taken in recent years including establishment of Feed-in Tariffs, reform of fuel subsidies and market structure, tax incentives, financial facilities, guarantees and other de-risking measures. But, based on our quantitative analysis, a literature review, and stakeholder consultation, we have identified a number of additional policy interventions that would be helpful to support renewable energy projects and drive investment in Kalimantan: 

Improving financial performance; revenue incentives (feed-in tariff and carbon incentives), capital grants and subsidies. Enhancing access to foreign capital is critical.



Addressing technical and human capacity; training of local technicians, certification of external parties, and national guidelines on feasibility studies.



Integrated planning; Kalimantan-wide resource assessment and energy planning.



Reducing business and regulatory risks; clearer identification of areas to be electrified by PLN, faster permitting procedures for IPP and PPU to obtain operating license.

We have mapped which policies are most relevant to each technology in the matrix in Chapter 6 (a summary of the most important suggestions is included in Table 1 below), based on the evidence collected during this project. In short: 

Off-grid rural electrification technologies in the 100-200kW range need substantial capital grants to be commercially viable. For projects operating under favorable conditions and 13

DRAFT FOR DISCUSSION for wealthier communities it is possible that private sector investment could be mobilised through bank guarantees and subsidized finance, but this is not the general expectation. Key practical steps include enhancing the quality of decision making in the planning stage, careful equipment maintenance and easier business management through simple, standardized tools. ď&#x201A;ˇ

Off-grid, industrial Private Power Utility projects in the 1-10 MW range such as POME would benefit from resurgence in carbon financing or subsidized debt that reduces the cost of the project.

ď&#x201A;ˇ

On-grid, industrial Private Power Utility projects in the 1-10 MW range such as woodchip biomass would benefit mainly from an increase in industrial user tariffs to reflect the true cost of generation. Better resource data and biomass supply-chain infrastructure would support investment as well.

DRAFT FOR DISCUSSION

Legal and regulatory policies

Operational and enabling policies

Financial investment c policies

Macroeconomic and market policies

Table 1: Summary of key policy suggestions

Potential barrier to investment

Potential Policy Intervention

Low financial viability

Reform diesel and power prices

Debt guarantees for domestic lenders Access to capital Capital grants

Outcome

Stronger incentive to uptake renewables

Lower hurdle rates and better financial viability of investments

On-grid

Off-grid





Capacity building and involvement of wider (including foreign) expertise

Well-designed and maintained projects





Poor resource data

Government investment in resource mapping and research

Lower development risk and higher investment





Lack of transparency in grid expansion plans

Clearer earmarking of PLN electrification budget to certain areas and better coordination between local PLN staff and local government

Avoiding stranded assets and reduced risk for investments





Low technical expertise in design and operational stage



Rarely relevant



Sometimes/often relevant



Frequently relevant

DRAFT FOR DISCUSSION Scaled Up; Kalimantan as a corridor Under the Master Plan for the Acceleration of Economic Development (MP3EI), Kalimantan was designated as a national economic corridor â&#x20AC;&#x201C; a geographical area focusing on common economic activities to drive synergies in development â&#x20AC;&#x201C; with a focus on natural resources. To be an effective driver of green growth, the corridor will need to deploy green technologies at scale. If we significantly increase the share of the four technologies assessed for this paper in the energy mix, what would be the benefits across the Kalimantan economic corridor? The estimated annual average net social benefit of implementing the four technologies would be USD 1.4-8.9bn (3-16% of the GRDP of Kalimantan) if about USD 10-57bn of investment is made today. The biggest potential impact derives from POME, but per unit of investment, microhydropower provides the greatest impact. Part of this investment could be provided as a grant from government.

DRAFT FOR DISCUSSION Figure 5: Potential net benefits from full deployment, and associated investment needs

Investment costs (billions US$)

45 MHP (Low)

MHP (High) Solar PV (Low)

Solar PV (High) Woodchip (Low)

Woodchip (High) POME (Low)

5 -100

-5

POME (High) 0

100

200

Net Benefits (billions US$)

Investment Costs (millions US$)

-15

650

550

450

MHP (Low)

350

MHP (High) Woodchip (Low) 250

Woodchip (High)

150

50 -1

-50

Note: Horizontal axis is net benefits from full deployment (billions USD) Vertical axis is investment costs (millions/billions USD) Bubble area is proportional to total Megawatts potentially deployable

DRAFT FOR DISCUSSION Final remarks We believe that these results and findings provide a valuable contribution to the evidence base for green growth policymaking in Indonesia, both at national and sub-national levels. However, there are some caveats. While the principles of the methodology are well-established, the application is experimental and only the fourth, pilot, analysis in a series of analyses to be refined with stakeholders. Despite the best efforts of the team to validate all assumptions and findings with stakeholders, inevitably the results are subject to a degree of uncertainty. Therefore, some data gaps had to be filled with national and international proxies. The specific results and findings of this analysis are not, by themselves, suitable for investment decision making. While effort has been made to use local information wherever possible, data has not been universally available, and international proxies have been used in the analysis. Business implications are drawn without detailed feasibility studies, and the analysis has been designed to inform the policy debate rather than capital allocation decisions. In addition, we have not assured the data provided to us by project developers or government agencies. The Global Green Growth Institute, its partners and contractors, do not verify, validate or endorse the social, economic or environmental performance of individual investments or projects. We note that the â&#x20AC;&#x2DC;scaling-upâ&#x20AC;&#x2122; of the project-level results to the Kalimantan corridor is subject to significant uncertainties, relies on simplifying assumptions and has limitations. These are listed in detail on page 65. Nonetheless, we hope that the analysis provides a tangible example of how to quantify and monetize a broad range of impacts at the project-level, and provides inspiration for the practical embedding of green growth theory into everyday planning processes. All feedback and comments are gratefully received by the project team.

DRAFT FOR DISCUSSION

1 Introduction Indonesia Green Growth Program The Government of Indonesia (GoI) and Global Green Growth Institute (GGGI) have developed a program of activity that is aligned and wholly supportive of achieving Indonesia’s existing vision for economic development planning. The aim is to show, using real examples of Indonesia’s development and investment plans at national, provincial and district levels, how economic growth can be maintained while reducing poverty and social inequality, maximizing the value of ecosystem services, reducing GHG emissions, and making communities, economies, and the enviroment more resilient to economic and climate shocks. The overarching goal of the Government of Indonesia-Global Green Growth Institute Green Growth Program for Indonesia is to promote green growth in Indonesia that recognizes the value of natural capital, improves resilience, builds local economies and is inclusive and equitable. The program has a number of specific objectives (see page 5), and three complementary components: 1.

Greening the Planning process. Aim: “To mainstream green growth within Indonesia’s economic and development planning processes” and “To increase the use of green technology and increase capital investment in green industry”

2. REDD+ for green growth. Aim: “To support the development of a funding mechanism that disburses REDD+ finance to catalyze green growth” 3. Regional engagement. Aim: “To support key provincial governments in prioritizing and implementing green growth” This report supports Component 1 in mainstreaming green growth in planning processes. As part of this component, the GoI and GGGI are developing a framework and suite of tools that can be used by GoI to help embed green growth principles into existing planning and investment appraisal instruments and processes. Mainstreaming green growth in planning processes Currently there is no single, internationally accepted analytical framework or set of indicators to monitor green growth performance6. As a starting point, GoI and GGGI have initiated a discussion with key stakeholders on what represents an appropriate framework to define what green growth means to stakeholders in Indonesia. Green growth planning needs to be undertaken in an integrated manner and on a comprehensive basis. It is important to understand the interdependencies between the country’s economic competitiveness drivers and their implications for social development and environmental performance. A Green Growth Framework (GGF) is being developed which brings together a set of social, economic and environmental indicators across 5 outcomes of green growth. These are all quantifiable and measurable, and provide a relevant framework for Indonesia to think about what green growth means to the country and the desired outcomes to be achieved through green growth.

Green Growth Best Practice, Green Growth in Practice: Lessons from Country Experience, 2014

DRAFT FOR DISCUSSION Figure 6: The five desired outcomes of green growth developed with key stakeholders in Indonesia

This Green Growth Framework can support decision making and prioritization of economic planning instruments, across national and sub-national government. A key part of decision making in this context is the selection and improvement of capital projects, such as those found in the Master Plan for the Acceleration of Economic Development (MP3EI). The GoI together with the GGGI is developing a tool to help operationalize the GGF within government and measure the green growth performance of investments. This tool is called the Green Growth Assessment Process (GGAP). GGAP is a 9-step process using indicators specific to projects, sectors, districts, provinces and Indonesia as a nation, as well as a range of other tools, and can be used by government: 

To allocate resources to the projects with the highest green growth potential;



To re-design and optimize publicly-funded projects; and,



To build a business case for projects with green growth benefits in order to attract private investment.

A full overview of the GGF and GGAP is available in an accompanying report7, but in brief proposed capital projects from different government economic development strategies and sectoral development plans are entered into GGAP, and indicators applied under the GGF to prioritize those that contribute most to green growth. Different design options for this shortlist of prioritized investments undergo a Green Growth Assessment. For the purpose of capital project assessments we apply a project-level Extended Cost Benefit Analysis (eCBA) methodology. The project-level eCBA is intended to provide a holistic and comprehensive understanding of the impacts of investments through a focus on the measurement and valuation of their green growth implications in rigorous, economic terms. It is often used in the application of Multi Criteria Analysis (see page 25), providing the social, economic and environmental valuations needed to make decisions. Based on the results and findings of the project-level eCBA, and ongoing monitoring of green growth performance, aspects of these investments can potentially be re-designed. The identification of potential project re-designs can help inform policy developments and other enablers. 7

GGGI (2015) Scoping green growth in Indonesia. Working Paper GGGI Indonesia Program

DRAFT FOR DISCUSSION This paper is the fourth in a series of papers conducting project-level eCBAs on a range of individual investments. Box 1: Green Growth Indicators The Green Growth Framework ultimately rests on the indicators used to define and measure green growth in practice. There are three broad functions/types of these indicators: 1.

Diagnostic indicators: designed to assess the overall sustainability of Indonesia and to identify key issues that should be considered in the mainstreaming of the green growth Planning process;

2. Planning indicators: designed in accordance with the Pressure-State-Response approach and so useful for assessing the cause-effect linkages between sustainability issues highlighted by diagnostic indicators and their pressures and impacts; 3. Monitoring and Evaluation (M&E) indicators: designed to help track green growth progress and performance of Indonesia. Indicators can be applied at different levels, including at the national, regional, sectoral and micro (project) levels (see Figure 6). All indicators within this report fall under the category of “projectlevel” indicators. The methodology applied at project level naturally supports functions 1 and 3 above: Diagnosis and M&E. eCBA provides a set of indicators that can be used for diagnosis of the project baseline across each of the five outcomes of green growth, and also sets out rigorous indicators that can be used for future project Monitoring and Evaluation. When aggregated across a number of projects, or particularly large projects, they may also support planning functions (Function 2). For further details on indicators and their role in the planning framework, the reader is referred to the references footnoted on the previous page6.

Green Growth Assessment Within the Green Growth Assessment of Capital Projects, eCBA is the key methodology used to value social, economic and environmental costs and benefits. Cost Benefit Analysis (CBA) is a toolkit used by economists and other decision makers to evaluate the desirability of a policy or project by systematically comparing costs and benefits. These costs and benefits are measured in terms of “social welfare”. Social welfare is a technical term used by economists to measure the “utility” of a population, as opposed to “private welfare” which is just the utility of the individual. Social welfare includes all economic (material goods), social (community cohesion), and environmental (ecosystem services) benefits that an economy, society and nature provide. In practice, calculating social welfare entails focusing on measurable economic costs and benefits, and including social and environmental factors not accounted for in market prices. We use the term Extended CBA (eCBA) to emphasize that our methodology assesses these nonmarket, social and environmental externalities as much as is practical and takes account of redesign options for the project to improve its green growth performance (this latter point differentiates eCBA from Social Cost Benefit Analysis (sCBA). Non-market values are inherently uncertain, so an important part of our eCBA method is its sensitivity analysis. We test the sensitivity of the results to variations on the underlying assumptions, including costs, quantities, prices and discount rates. All input values are flexed by ±25%, and a number of additional assumptions are also flexed by a custom amount if there are grounds for believing the uncertainty is likely greater than 25% (e.g. potential carbon prices). 21

DRAFT FOR DISCUSSION A project-level eCBA provides evidence for decision makers to inform decisions on whether a project should go ahead. If the total benefits exceed the total costs, then the project can be considered to be justified in net social welfare terms although the decision to proceed will inevitably be subject to a wider range of considerations (such as affordability). But, private investors will usually only take forward projects where the private benefits exceed the private costs. Due to the presence of market imperfections and “missing” markets (e.g. ‘public goods’ such as clean air), private incentives are not always aligned with achieving optimal social outcomes. Therefore, a key objective of the project-level eCBA is to cast light on the difference between these and suggest policies to help align them. The practical process of conducting a project-level eCBA requires 6 stages as outlined in the Figure 7 below. Figure 7 : Stages in conducting project-level eCBA Stage 1

Identify project baseline

Identify and consult project stakeholders

Stage 2

Identify Green Growth options

Consult project stakeholders

Stage 3

Stage 4

Map Impact Pathways

Collect data

Identify outputs, outcomes and impacts

Collect data from project documentation

Identify potential scope for eCBA

Collect local market data

Assess materiality: Identify actual scope for eCBA

Collect international technology data

Consult experts Review project documentation

Establish project rationale and need

Literature review

Stage 5

Cost Benefit Analysis

Value costs and benefits of green growth interventions

Stage 6

Validate Findings

Validate findings with stakeholders

Consider implications of results and findings for policy

Consider implications for project re-design and investment

Understanding the Results and Findings In this report we calculate the costs and benefits of four renewable energy projects compared to BAU scenario (full detail about these projects can be found in the next section). Our headline results and findings is that the implementation of these projects could result in significant net societal benefits. The full quantitative results and findings are presented in Section 5. The details of scope and methodology are presented in Sections 3 and 4, but it is important to provide context for interpretation of the headline results and findings. Cost Benefit Analysis is part of a broader project appraisal process and can fit into existing processes as explained in Figure 8 on the following page. This allows for key decisions to be made before implementations, for example:  Does it offer positive net benefits and should it proceed? 

Are there opportunities to re-design this project to enhance green growth performance?

DRAFT FOR DISCUSSION ď&#x201A;ˇ

Are there policies that might drive better outcomes for this and other projects (see next section)?

We note that Social Cost Benefit Analysis (sCBA) is already mandatory for Pubic Private Partnership projects in Indonesia, but not necessarily for other investments. Moreover, the historical release of the results of sCBA has often been limited in scope and transparency. The aim of the eCBA in this report is to test the tool in development on a real life project and to contribute to the evidence base for green growth policy in Indonesia, highlighting potential options for improving green growth performance but more importantly demonstrating that valuing the wider implications of decision making, and internalizing them into the project appraisal process, can lead to improved policy outcomes. The eCBA does not substitute for a full feasibility analysis and/or financial appraisal, rather, it complements them. For maximum impact, the eCBA should be combined alongside other green growth tools such as Green Project Prioritization tools, Strategic Environmental Assessment and impact assessment techniques. The specific results and findings of this analysis are not, by themselves, suitable for investment decision making. While effort has been made to use local information wherever possible, data has not been universally available, and international proxies have been used in the analysis. Business implications are drawn without detailed feasibility studies, and the analysis has been designed to inform the policy debate rather than capital allocation decisions. Structure of this report In summary, the rest of this report is structured as follows:

Section 2 provides different options for delivery and introduces the Green Growth scenarios

Section 3 provides detailed methodology and reporting framework used in this report

Section 6 outlines some policy implications of the results and findings

Section 4 provides a detailed scope of analysis Section 5 presents the quantitative results and findings of the Cost Benefit Analysis for four renewable energy projects, also scaled up to the level of the Kalimantan corridor

Appendix A outlines the architecture of the eCBA model Appendix B provides stakeholder comments from the validation workshop

Figure 8: Stylized overview of a “greened” planning and project appraisal process in Indonesia

Stage 0 Preproject policy planning

Stage 1

Feasibility and options analysis

• RPJMN/D

• Market appraisal

• Spatial Plan

• Technical appraisal

• Economic Zones (KEK, KSN) • List of investments • Strategic Environmental Assessment

• GGAP filtering of projects • Strategic Environmental Assessment

Stage 2

Financial analysis

• Appraisal of financial costs and benefits

Stage 3 Extended Cost Benefit Analysis

• Appraisal of social costs and benefits

Stage 4

Multi Criteria Analysis

• Integrating wider qualitative and strategic impacts

Stage 5

Impact Assessme nt

• AMDAL • Socio-Economic Impact Assessment

2 Options for electricity production in Kalimantan This section provides some background on the electricity sector in Indonesia and Kalimantan, and provides details of the Business As Usual and Green Growth scenarios used in the eCBA analysis. Business As Usual Scenario In Indonesia, power generation is still dominated by the national utility company; Perusahaan Listrik Negara (PLN). Historically, PLN had a monopoly on the generation, transmission, and distribution of electricity in Indonesia. Law number 5/1985 opened up the market for other companies to participate in the power market by selling power to the national grid; these sales are known as “on-grid”. The 1985 law was replaced by the Electricity Law number 30/2009. This law stated that PLN has priority over Independent Power Producers (IPP) (i.e.: the private sector, cooperatives, and non-governmental agencies). But, the 2009 law relaxed restrictions on IPP operations, specifically in allowing IPPs to sell power directly to end-customers as well as PLN, subject to obtaining an Electricity Supply Business Permit (IUPTL)8. If IPPs are selling to customers without the use of PLN’s transmission grid, then these sales are known as “off-grid”. Investors who generate electricity mainly for their own use are known as Private Power Utilities (PPUs). Figure 9: Installed Generation Capacity in Indonesia (MW)

IPP & PPU 12,032 MW PLN 33,221 MW

Source: Statistik Ketenagalistrikan 2013. Direktorat Jenderal Ketenagalistrikan.

Following this enhanced access to the grid, ESDM9 has launched a regulation that obliges PLN to purchase electricity from IPP renewable energy generators with a capacity of up to 10 MW via regulated Feed in Tariffs. In 2013, Indonesia had a total installed capacity of 48,161 MWe and an electrification rate of 80.5%10. The proportion of power generated by PLN is around 75% and total IPP and PPU combined is around 25% as shown in the in the Figure 9.

Source: PwC (2013) Power in Indonesia. Taxation and Investment Guide.

Ministry of Energy and Mineral Resources (Kementrian Energi dan Sumber Daya Mineral)

Dewan Energi Nasional or the National Energy Council (DEN) (2014) Executive Reference Data National Energy Management page 38

DRAFT FOR DISCUSSION Both on-grid and off-grid schemes utilize renewable and non-renewable energy sources to generate power. Most on-grid power plant generation is dominated by non-renewable energy such as coal and natural gas (as can be seen in Figure 10 below). Figure 10: National Installed Capacity of Power Plant by Type (MW)

Gas 14,004

Diesel 5,974

Geothermal 1,344

Other 5,521

Hydro 4,146

Wind 0.9 Solar 4.1

Coal 19,755 Waste 26 Source: Statistik Ketenagalistrikan, 2013. Direktorat Jenderal Ketenagalistrikan

Currently, renewable energy sources only comprise a small percentage (12%) of on-grid electricity generation: mainly hydro and geothermal. But, low renewable penetration is not due to lack of physical resources; installed capacity for most renewable energy is less than 5% of potential (as shown in Table 2 below). However, the off-grid proportion of renewable energy is high, accounting for 50% of total energy generated. Half of this in turn comes from Solar Home Systems (Solar PV) and Micro Hydro Power (MHP). Table 2: National Energy Potential, 2005 (updated data required when available)

Renewable Energy Source

Potential Power Generation

Installed Capacity (2005)

Non-Utilized Capacity

Hydro Power

76.67 GW

4.2 GW

94.5%

Geothermal

27 GW

0.8 GW

97%

Mini/Micro Hydro

0.45 GW

0.26 GW

45%

Biomass

49.81 GW

0.3 GW

99.3%

Solar PV

4.80 kWh/m2/day

0.01 GW

9.29 GW

0.0006 GW

99.9%

3 GW

Wind Power Nuclear

*Only in South Kalimantan and West Kalimantan Source: Blueprint National Energy Planning, 2007

DRAFT FOR DISCUSSION One of the consequences of fossil fuel domination is high CO2 emissions. In 2013, national emissions from on-grid electricity generation were 165 MtCO211 . The RUPTL12 2013-2022 forecast that electricity development in Indonesia will continue to rely heavily on coal and only use a small proportion of renewable energy until 2020. Figure 11 below shows predicted CO2 emissions until 2022; CO2 emissions are expected to double to 339 MtCO2 within 10 years. Figure 11: Indonesia’s Projected CO2 Emissions from Power Generation

Source: Rencana Usaha Penyediaan Tenaga Listrik (RUPTL) 2013-2022.

At the beginning of 2010, there was a major deficit of electricity supply in 15 out of the 26 major PLN grids. This gap between supply and demand (low reserve margin) causes blackouts in many areas, especially outside Java and Bali. Given delays in the development of new power plants, this deficit may worsen. Delays are caused by lack of project financing and other difficulties13. PLN’s long-term plan to solve the electricity crisis is to build more power plants and purchase excess power from IPPs. This is expected to increase the margin reserve to 35% for Java and Bali system and 40% for the Western and Eastern parts of Indonesia’s main grid14. PLN efforts to increase the electricity supply through Fast Track Program I mainly rely on coal, Fast Track Program II relies on a mix of coal, hydro, and geothermal. Dewan Energi Nasional or the National Energy Council – with the mandate of energy policy 15 formulation – aims for 23% of energy to come from Renewable Sources by 2025 . Clearly, expanding access to the 23% of people who do not have power is key for economic development. Also, to reduce CO2 emissions, reduced reliance on fossil fuels going forward will be important. The use of coal in Indonesia is mainly driven by low prices and abundant supply. But, not all fossil fuels are economically superior; diesel is expensive and largely imported.

Electricity Supply Business Plan (Rencana Usaha Penyediaan Tenaga Listrik or RUPTL) 2013-2022

Ibid.

Electricity Supply Business Plan (Rencana Usaha Penyediaan Tenaga Listrik or RUPTL) 2010-2019

Ibid.

Dewan Energi Nasional or the National Energy Council, RPP Kebijakan Energi Nasional, Disetujui, RABU, 29 JANUARI 2014 11:24 WIB: http://www.esdm.go.id/berita/umum/37-umum/6679-rpp-kebijakan-energinasional-disetujui.html

DRAFT FOR DISCUSSION Kalimantan has a similar profile to Indonesia as a whole, although with lower renewables use. In 2012, Kalimantan had a total installed capacity of 1,470 MW and an electrification rate of 66%. The proportion of each energy source in the mix is indicated in Figure 12. Figure 12: Source of Power for Electricity Generation in Kalimantan (MW)

32 39 201

Diesel Natural Gas

IPP (unknown fuel) Coal

173

Hydro

969

Others

Source: Electricity Power Development in Indonesia. I Made Ro Sakya. PT PLN (Persero) 2012.

This figure shows that as for the country as a whole, Kalimantan power generation is also dominated by fossil fuel. The key difference is that diesel accounts for a much higher proportion (65%) of generation and coal much lower. This makes power expensive to generate and leads to a high CO2 emissions intensity. The situation in Central Kalimantan is also similar. Current peak loads are higher than capacity, and electricity demand is predicted to grow 9.7% per year, but planned supply only 8.5%. Given such generation shortages, and also fragmented transmission grids (consisting of the Barito system and a large number of isolated grids and mini-grids), it is remarkable that 42% of households still have no access to electricity. To address this gap, PLN is planning to build 11 power plants with 632MW total capacity by 201616. All of these future power plants will utilize fossil fuel and 80% of will use coal as the fuel source. Given the current profile of the electricity market in Indonesia and Kalimantan and announced 17 investments and plans by PLN and IPPs , it is unclear whether they are aligned to, or will achieve, the government’s renewable target. A Business As Usual scenario for Kalimantan might be expected to have the following characteristics:

•

Increase in grid generation capacity, with an increasing share of coal fired power plants in the fuel mix



Increased CO2 emissions



Inadequate reserve margins

•

Gentle increases in the electrification rate following generation capacity and infrastructure access

•

For remaining off-grid areas, ongoing reliance on diesel generation except for villages actively targeted by SHS/MHP programs

Ibid.

See RUPTL, the Electricity Supply Business Plan for 2013 – 2022, PT PLN (Persero)

DRAFT FOR DISCUSSION

Green Growth Scenario The Business As Usual is expected in the absence of major policy change or investment. But, it is not a foregone conclusion and there is an alternative to reliance on centralized generation using fossil fuels. Large-scale electricity generation is looking increasingly profitable internationally and by some estimates 2014 is the year when solar power reached grid parity (i.e., the same cost as) with natural gas generation in the United States18. Off-grid, distributed generation is increasingly recognized around the world as an economically attractive option where there is no fossil-fuel legacy or existing transmission infrastructure; electrification and clean energy goals can be achieved in one go. This is particularly true in Kalimantan. Low electrification rates, remote communities reliant on expensive diesel generators, limited transmission infrastructure and high-cost diesel-based power plants even for those that are connected to the grid suggest that an economic alternative to BAU would be welcome. The main challenge in providing access to electricity in Central Kalimantan is the high cost of investment due to its geography and dispersed population. But, there are several options for green growth in the energy sector in Kalimantan. 

Hydro generation: Major rivers run from the Heart of Borneo through Kalimantan and potential for Micro and Mini Hydro of 243MW has been identified19. Specifically there is hydro power potential in the range 15 kW to 3.2 MW in the area of Barito River, Katingan, and Lamandu20.



Solar Photovoltaic (Solar PV) generation: the potential for Solar PV at Utility-Scale or via distributed Solar Home Systems (SHS) has been identified in Kalimantan, given the market characteristics discussed above and the intense solar irradiation levels21. Indeed, 887kW SHSs were deployed between 2005 and 2010, and PLN plans to develop around 113MW of Solar PV by 202022 through the “thousand islands” program, supported by Diesel backup.



Wind generation: wind speeds in Kalimantan average around 3-4 m/s. In places it is technically possible to generate wind power, especially coastal/offshore locations where the wind is strongest, but the overall case is marginal.23



Biomass generation: Kalimantan is heavily forested and agriculture is a key sector of the economy. There are significant sources of biomass feedstock from coconut, rice husk, palm oil, forestry operations and mills across the provinces and active power generation projects in these areas.24



Biogas generation: Kalimantan produces about 28.5% of the palm oil production in Indonesia25. With capacity factor of 80% and all-year round operations, the total estimated energy potential from palm oil mills liquid waste in Central Kalimantan alone is 422.5 MW26.

Financial Times. “Solar and Wind Start to Substitute Gas”. 18 September 2014

Electricity for All: Options for Increasing Access in Indonesia. The World Bank. 2005

Energy and Environmental Partership with Indonesia (EEP Indonesia).Baseline Study I. April 2012

Global Green Growth Institute (2014) Green Industry Mapping Strategy Business Case: Solar PV In East Kalimantan http://energy-indonesia.com/03dge/0130227pln-taiyoko.pdf 23 Martosaputro and Murti (2014) Blowing the Wind Energy in Indonesia Energy Procedia 24 Energy and Environmental Partnership with Indonesia (2012) Baseline Study in Riau and Central Kalimantan 25 http://www.bps.go.id/tab_sub/view.php?kat=3&tabel=1&daftar=1&id_subyek=54&notab=8 22

Energy and Environmental Partership with Indonesia (EEP Indonesia).Baseline Study I. April 2012

DRAFT FOR DISCUSSION Kalimantan is not currently considered a strong candidate for geothermal energy. We did not consider marine energy, which is an immature technology: to the best of our knowledge, there are no projects currently planned in Indonesia for this technology. The purpose of this report is to demonstrate in monetary terms the value of a Green Growth scenario and identify policy measures required to drive uptake of the scenario. To achieve this, we have drawn on four representative projects in Kalimantan. First, a micro hydro project is planned to be installed in the village of Tumbang Kunyi, Sumber Barito district, Murung Raya regency, Central Kalimantan. Based on the feasibility study, a 130kW plant is proposed, which would supply electricity to around 400 homes and 40 other users over a low-voltage mini-grid. Previously, communities were relying on diesel generators and kerosene lamps for lighting. A not-for-profit community co-operative is expected to run the plant following a capital grant from provincial government. As an intra-regency off-grid project, licensing jurisdiction will sit with local government. Second, a solar PV project is an early-stage analysis in the village of Sungai Gula, Permata Intan district, Murung Raya regency, Central Kalimantan. A 140kW Solar PV array is proposed here, which would supply power to around 300 homes and 12 other users, over a low-voltage mini-grid. Currently, some households have diesel gensets and some have no power at all. The village is expected to install a mini-grid 140kW diesel generator in the absence of renewables investments though. The business model is yet to be determined but it is expected that local government would fund the capital costs. As an intra-regency off-grid project, licensing jurisdiction will sit with local government. Third, a biomass (woodchip) project in Natai Peramuan village, Kumai district, Kotawaringin regency, Central Kalimantan was registered under the UN Clean Development Mechanism in 2012, and uses waste residue from chipping operations to power a 7.3 MW biomass generator. The electricity generated powers the chipping mill and the excess power (around half the kWh) is sold back to PLN on the grid. Without this project, the chipping mill would buy power from the grid, which in Central Kalimantan is diesel and coal dominated. Although the project is CDMregistered, it has not issued any carbon credits to date. As a Private Power Utility, the project would require an Izin Operasi license. Fourth, a biogas (Palm Oil Mill Effluent; POME) project in Muai village, Kembang Janggut district, Kutai Kartanegara regency, East Kalimantan, has been operational since 2012, and captures biogas from wastewater treatment in a palm oil mill. The biogas is fed to two biogas engines with generator sets with a total capacity of 2.1 MW to power the palm oil mill. There is no excess power, and any excess biogas is flared in an enclosed system. Prior to the project, the electricity was generated with a biomass boiler running on palm kernel shell and palm oil fibro as well as a number of diesel generator sets. The project is CDM-registered and has issued 27,782 CERs to date. As a Private Power Utility, the project would require an Izin Operasi license. Figure 13 Map of project locations in Kalimantan

DRAFT FOR DISCUSSION

3 Methodology This section summarises the methodological approach used to evaluate the societal costs and benefits likely to be generated by the green growth activities at Katingan. Introduction to Green Growth Assessment Within the Green Growth Assessment of Capital Projects, eCBA is the key methodology used to value social, economic and environmental costs and benefits, and underpins the results and findings in this report. These costs and benefits are not always taken into account in decision making as individuals maximize their own private welfare, not necessarily social welfare. Private costs and benefits and social costs and benefits diverge due to the presence of market imperfections. For example, an investor does not always pay for the health damage that industrial effluent from their factory generates to communities downstream so the factory over-produces relative to what would be ‘best for society’, or does not pay for pollution-control technology even though this is cheaper than the health damages inflicted. Principles of Cost Benefit Analysis It is necessary to consider a much wider range of prices than pure market prices to arrive at the social costs and benefits of a decision (the “social opportunity cost”). We note that these principles are crucial in differentiating eCBA (similar to “social cost benefit analysis”) from “financial appraisal” or “financial cost-benefit analysis”, which only considers market costs and benefits from the perspective of a private investor. Social discounting: Discounting is used to compare costs and benefits that occur in different time periods. Society generally prefers one dollar now to one dollar next year. The rate at which costs and benefits are compared across time (‘discounted’) is called the Social Discount Rate (SDR)27. We use a (real) SDR of 5% in our analysis, which is slightly below the standard range for developing countries (8-15%)28. This reflects the dominance of climate change and long-term environmental impacts in the analysis, and clearly differentiates the eCBA analysis from the Weighted Average Cost of Capital (WACC) used in financial analysis. The financial analysis in this report uses a WACC of 10%, which in general is a weighted average of some assumed cost of debt and equity, and depends on corporate/project risk, access to finance, investor characteristics etc. Individual companies would use a different WACC to reflect their own opportunity cost of capital, as well as views on specific technologies. In order to facilitate direct comparisons between financial cases, we use 10% in real terms (excluding inflation). Taxes and subsidies: If there are significant taxes or subsidies present, then market prices will not represent the Social Opportunity Costs (SOC) of a resource (since taxes/subsidies are simply a transfer payment to/from government). In practice, it is not common to remove taxes and subsidies from all market prices in the analysis, but only where it makes a material difference to decision making. This is generally where markets are highly distorted. In the context of the electricity sector in Indonesia, there are two major distortions:

Or: Social Rate of Time Preference. In the Ramsey (1928) model, SDR is defined as the sum of: the Pure Rate of Time Preference; and the Marginal Elasticity of Utility with respect to Income, multiplied by expected Income Growth. 28 Zhuang et al (2007) “Theory and Practice in the Choice of Social Discount Rate for Cost Benefit Analysis”

DRAFT FOR DISCUSSION 

The retail price of diesel ‘at the pump’ (IDR 7,500 in Jakarta at the end of 2014) is subsidized. This is the price that local communities will pay for diesel genset fuel. The true opportunity cost varies with the international price of crude oil (plus refining costs) which varies rapidly, as seen in late 2014 and early 2015. The import price at the time of analysis was around IDR 10,750/liter29 in Jakarta. The implied cash subsidy is IDR 3,250/liter. To this we add transport costs to get the fuel to rural Kalimantan, based on the difference between the market price in Jakarta and Kalimantan.



The price of electricity sold by the National Utility PLN is subsidized. The exact level of subsidy depends on the user, since tariffs are differentiated for industrial and residential users, and by annual consumption. The market distortion happens both upstream and downstream of PLN: o

Fossil fuel inputs are purchased below international prices (e.g. Pertamina is obliged to sell imported diesel to PLN for less than its claimed import plus distribution costs30. Implicitly coal is subsidized due to the Domestic Market Obligation. At the margin, liquefied natural gas is directly imported at cost, so is not considered subsidized31).

Power output is then sold at less than the cost of generation, transmission and distribution (even accounting for the artificially cheap fuel).

While the former reflects an opportunity cost to Pertamina and the Coal Industry, it is difficult to quantify precisely. Only the per-kWh distortion is captured in the required subsidy to PLN from Ministry of Finance (in 2013 this totaled IDR 33.6 trn, or 0.35% of GDP32), and it is this subsidy which we include in our analysis. This subsidy is equal to approximately 13 US cents/kWh for Grid-purchased electricity for a light industrial user such as the Korindo Woodchip Project (calculated as a tariff of IDR 937/kWh (7.7 US cents) minus the estimated LCOE in the table below). At the time of writing in late 2014 both international oil prices and Indonesia subsidy policy were changing rapidly. See further discussion on page 70. Table 3: Opportunity cost of electricity generated in Central Kalimantan

Generation Fuel

Share in Central and South Kalimantan Fuel Mix

PLN’s reported LCOE (IDR/kWh)

PLN’s reported LCOE (USD/kWh)

Coal

26.3%

810.14

0.07

Natural Gas (Single Cycle)

3.5%

2,362.99

0.20

Diesel

65.2%

3168.58

0.26

Hydro

5.0%

155.87

0.01 Weighted Average

0.19

Weighted Average plus 10% Transmission and Distribution Costs @ 10%

0.21

Note: LCOE = Levelized Cost Of Electricity Source: PLN Statistics Annual 2012 29

Pertamina circular “Penyesuaian Harga Jual Keekonomian BBM Pertamina Sektor Industri dan Bunker”, 28 November 2014 30

http://en.tempo.co/read/news/2014/08/14/056599583/Pertamina-Resupplies-PLN-with-Subsidized-Diesel http://thejakartaglobe.beritasatu.com/business/pln-allowed-import-lng-power-generation-government-says/ 32 http://www.indonesia-investments.com/finance/financial-columns/indonesias-budget-deficit-reaches-idr-25.9-trillionas-of-may-2013/item801 31

DRAFT FOR DISCUSSION

Externalities: Where the social cost of the extraction or consumption of a resource differs from the private cost (or equivalently, the benefits), there is said to be an “externality”. In extremis, where everyone is affected by the externality, there is said to be a “public good” (clean air) or “public bad” (climate change). Again the market price, determined solely by private costs and benefits, will not reflect the true SOC of the resource or activity. The key negative externalities arising from the combustion of fossil fuel to generate power include: 

Release of Green House Gases resulting in climate change



Localized air pollution including health and agricultural productivity damage from SOx, NOx, and Particulate Matter (from on-grid power plants)



For indoor diesel gensets and/or kerosene lamps, highly localized health impacts on individual households

Conversely, there are positive externalities associated with energy substitution from diesel gensets and kerosene lamps towards mini-grid renewables and/or decentralized solar systems: 

Improved educational attainment from better lighting



A more stable and reliable supply opens up new business opportunities

Market power: Similarly, if a market is distorted due to oligopolistic or monopolistic market structures, then the market prices will fail to reflect the true opportunity cost of a resource. The most likely relevant distortion is the presence of national electricity monopoly, PLN. However, the monopoly is balanced out by government regulation; the temptation to over-charge is mitigated by fixed tariffs and subsidies in the market (see above). Perhaps more relevantly is the temptation to suppress competition through high system access charges; however, this has already been addressed by regulation in some areas. We discuss this in the policy implications section, but do not explicitly adjust for monopoly in our eCBA. Tradable goods and Exchange Rates: Tradable goods must be valued as if there are no impediments to trade (i.e., no quantitative restrictions, no import/export tariffs or subsidies). Power is not considered tradable in the absence of under-sea transmission lines to/from Kalimantan and over the border to Malaysian Borneo (from Central Kalimantan). We assume that the official exchange rate represents the true opportunity cost of foreign exchange. All dollar values are uplifted as needed to a 2014 base year using the United States GDP Deflator. We acknowledge that international prices and exchange rate changes can influence both the costs of factors of production such as oil and the competitiveness of products on the international market. This would have an impact on the viability of some of the projects discussed in this report and a variable that necessitates broad ranges in our sensitivity analysis. Costs relating to finance: The payment of interest and repayment of principal is often a key part of financial analyses. But, debt service is not relevant for economic and financial analysis in this context because “in both cases what matters is assessing the quality of the project independently of its financing mode”33. Debt service also represents a transfer rather than a use of resources. Key data and assumptions for this project

World Bank Handbook on Economic Analysis of Investment Operations

DRAFT FOR DISCUSSION The eCBA relies on a wide range of physical and monetary data. It is not always clear cut as to which value to use in a particular calculation due to the constant evolution of markets, uncertainty about the future, missing or inaccessible data, unknown project operational details and so on. As a general rule, preference was given to data in the following order: 1) Project-specific data (e.g. from project feasibility studies and UNFCCC documents) 2) Province-specific data (e.g. energy prices and population density in Central Kalimantan) 3) Indonesia-specific data (e.g. capital costs of coal fired power plant) 4) South East Asia-specific data 5) Other comparable international technology or market data In addition to these quantitative assumptions below, there were two qualitative assumptions made across all areas of analysis. The first of these was that demand curves are inelastic. That is to say, in no scenario are these projects expected to have an impact on market prices by changing the overall amount of power generated; all prices were held constant in the BAU and Green Growth scenario (this is not an unrealistic simplification in the context of fixed tariffs for end users). At the same time productivity and technology outside of the direct scope of analysis have been held constant. The second is that the relevant geographical scope of analysis is Central Kalimantan – direct costs and benefits to other provinces are excluded (although for example it is possible that East Kalimantan or Java would benefit from activity later in the same supply-chain or transport of the produced commodities). The only exception to this was in relation to climate change. As this is considered a global problem, the valuations were made on the basis of the global damages attributable to one tonne of carbon emitted in Indonesia, not just the Indonesia-specific damages. A draft version of this report was presented to stakeholders in November 2014 for data and assumption validation. Their comments can be found in Appendix B. Table 4: Key assumptions applied across the analysis Parameter

Value

Source

Weighted Average Cost of Capital (“WACC”)

10%

Team Assumption

Social discount rate

Team Assumption

Social Cost of carbon

USD 80/tCO2

Carbon price

USD 0.14

Market price of diesel in Kalimantan

IDR 17,000/liter

Subsidy for diesel

IDR 3,250/liter

Market price of kerosene in Kalimantan

IDR 12,000/liter

Tol, 2009, assuming 0% Pure Rate of Time Preference, peer reviewed studies only Gazprom Energy, 2014. Weekly Carbon Report (06/10/2014) Stakeholders Comments from 1-day validation workshop in Palangkaraya, Central Kalimantan on 20 November 2014, adjusted for the recent increase Calculation based on PERTAMINA circular on "Penyesuaian Harga Jual Keekonomian BBM Pertamina Sektor Industri dan Bunker" 28 November 2014 Stakeholders Comments from 1-day validation workshop in Palangkaraya, Central Kalimantan on 20 November 2014, adjusted

Note: In this table and the following table, units are generally quoted in their source year currency units. In the actual CBA calculations, all values were automatically adjusted for inflation using the US GDP deflator as published by the World Bank World Development Indicators.

DRAFT FOR DISCUSSION for the recent increase

Subsidy for kerosene

Capex (FS and Benchmark) Total cost of repair for year 7th and year 13th (FS)

USD 425,880 USD 32,760

Operation (FS)

USD 6,388/year

Maintenance (FS)

USD 7,639/year

Operation and Maintenance (Benchmark)

Micro Hydro

Calculation based on PERTAMINA circular on "Penyesuaian Harga Jual Keekonomian BBM Pertamina Sektor Industri dan Bunker" 28 November 2014 Green Growth (Renewable Energy)

IDR 6,300/liter

USD 1,269

FS PLTMH Onkong Taba'ang

Millennium Challenge Corporation (2012) Ex Ante Economic Analysis for Micro Hydro Electric Systems in Remote Communities in Indonesia (unpublished)

Capacity factor (FS)

50%

FS PLTMH Onkong Taba'ang

Capacity factor (Benchmark)

38%

World Bank (2012) Micro Hydro Power (MHP) Return of Investment and Cost Effectiveness Analysis35

Tariff (FS)

USD 0.06

FS PLTMH Onkong Taba'ang

Tariff (Benchmark)

USD 0.05

World Bank (2012) Micro Hydro Power (MHP) Return of Investment and Cost Effectiveness Analysis

Number of children per household Additional future income per child Avoided Health cost from indoor pollution Incremental economic development benefit, i.e: additional income from longer trading hours for kiosks and small shops and total fuel savings from genset welding Number of households Number of public facilities

Calculation based on FS PLTMH Ongkong Taba'ang

USD 13/child/month

World Bank, 2008.The Welfare Impact of Rural Electrification: A Reassessment of Costs and Benefits-An IEG Impact Evaluation36

USD 2.7/year per HH

World Bank, 2008.The Welfare Impact of Rural Electrification: A Reassessment of Costs and Benefits-An IEG Impact Evaluation

USD 15,292/year

Millennium Challenge Corporation (2012) Ex Ante Economic Analysis for Micro Hydro Electric Systems in Remote Communities in Indonesia (unpublished)

433 FS PLTMH Onkong Taba'ang 42

Business as Usual (Non-renewable energy)

Sol ar PV

Use of small genset in one village Use of kerosene (for lighting) in one village

93% of households FS PLTMH Onkong Taba'ang 7% of households

Green Growth (Renewable Energy)

https://energypedia.info/images/c/c5/MHP_Indonesia_Cost_Effectiveness_Analysis_Report_-_World_Bank_Group__September_2012.pdf 36

http://siteresources.worldbank.org/EXTRURELECT/Resources/full_doc.pdf

DRAFT FOR DISCUSSION

Capex (FS) Capex (Benchmark) Opex (FS and Benchmark) Total cost of battery replacement in the 5th, 10th, and 5th year (Benchmark) Total cost of inverter replacement in the 11thyear (Benchmark) Tariff Number of children per household Additional future income per child Avoided Health cost from indoor pollution Number of household Number of Public facilities

USD 3,102,088

Inventarisasi dan Survei Potensi Energi Air dan Energi Surya (Sistem Terpusat). Desa Sungai Gula. Dinas Pertambangan dan Energi Kabupaten Murung Raya, 2014

USD 622,678 USD 5,999/year

USD 202,168

National Renewable Energy Laboratory, 2012. Opportunities and Challenges for Solar Minigrid Development in Rural India 37

USD 42,118

USD 0.05/kWh

World Bank (2012) Micro Hydro Power (MHP) Return of Investment and Cost Effectiveness Analysis

Millennium Challenge Corporation (2012) Ex Ante Economic Analysis for Micro Hydro Electric Systems in Remote Communities in Indonesia (unpublished)

USD 13/child/month

World Bank, 2008.The Welfare Impact of Rural Electrification: A Reassessment of Costs and Benefits-An IEG Impact Evaluation

USD 2.7/year per HH

World Bank, 2008.The Welfare Impact of Rural Electrification: A Reassessment of Costs and Benefits-An IEG Impact Evaluation

300

Inventarisasi dan Survei Potensi Energi Air dan Energi Surya (Sistem Terpusat). Desa Sungai Gula. Dinas Pertambangan dan Energi Kabupaten Murung Raya, 2014

Business as Usual (Non-renewable energy)

Biomass (Woodchip)

Use of small genset 38% in one village Use of kerosene (for lighting) in one 62% village Green Growth (Renewable Energy) Capex

USD 24,075,586

Opex

USD 2,622,215/year

Refurbishment cost in the 11th year Annual power plant operating hour

USD 4,735,185

FS PLTMH Onkong Taba'ang

Project Design Document of “Korindo Biomass Power Plant, Indonesia” version 5.1 (Ref: Project No 8144)

8,000 hours/year

Electricity Sales (FiT)

USD 0.16/kWh

Amount of excess electricity to be sold to the grid per year

26,179,000 kWh/year

Annual carbon credit potential

46,800tCO2/year

Permen ESDM 27/2014, rate for PLTBm, medium voltage, with F=1.3 for Kalimantan

Project Design Document of “Korindo Biomass Power Plant, Indonesia” version 5.1 (Ref: Project No 8144)

Business as Usual (Non-renewable energy)

http://www.nrel.gov/docs/fy12osti/55562.pdf

DRAFT FOR DISCUSSION Grid emission factor for Central Kalimantan

0.9tCO2/MWh

DNPI, 2013. Grid emission factor 201338

Biogas (POME)

Green Growth (Renewable Energy) Capex

USD 4,407,525

Opex

USD 310,584

Annual power plant operating hour

8,760 hours/year

FFB Fresh Fruit Bunch projection

350,000tonne/ye ar

POME-FFB conversion rate

0.88m3 POME/tonne FFB

Amount of electricity displaced by the project

8,020 MWh/year

Project Design Document version 14 and Appendix 2 ER calculation of “Cakra Methane Capture Project” (Ref: Project No 6256)

Business as Usual (Non-renewable energy)

Average diesel consumption

804 tonne/year (908,153 liter/year)

Project Design Document version 14 and Appendix 2 ER calculation of “Cakra Methane Capture Project” (Ref: Project No 6256)

Scaled Up; Kalimantan as a corridor As part of this analysis, we attempted to ‘scale-up’ some of the findings of the project-level eCBAs to estimate: 

The indicative net benefits from full deployment



The indicative capital investment required to realize these benefits

The full results, findings and valuation methodology are provided in Section 5. In this section we outline the methodology and data used to estimate the maximum technical potential (‘full deployment’), measured in Megawatts (MW). For micro-hydro, we have roughly estimated that the maximum technical potential of hydropower lies between 29 and 136MW across Kalimantan. This calculation rests on data from Government of Indonesia39, 40, and technical energy assumptions from a feasibility study of PLTMH Ongkong Taba'ang. The hydropower potential data from the World Bank report was heavily influenced by one hydropower plant in Lampung (2.7 GW). Thus, the technical potential of micro-hydro was calculated with two different values of total hydropower potential in Indonesia: with and without inclusion of hydropower potential in Lampung. This estimate should be treated with caution as it does not account for technical potential that has already been exploited by MHP programs. Moreover, the geography and demography of some areas means that some proportion of this potential is not economically viable. For solar PV, we have roughly estimated that the maximum technical potential of photovoltaic lies between 1,295 and 1,752 MW across Kalimantan. Strictly speaking, this is not the ‘maximum’ technical potential, which in an area of high solar irradiance such as Kalimantan is practically 38

http://pasarkarbon.dnpi.go.id/web/index.php/dnacdm/read/24/pembaruan-faktor-emisi

World Bank, 2005. ELECTRICITY FOR ALL: Options for Increasing Access in Indonesia. Renewable Energy and Rural Electrification Development Policies. Directorate for New Renewable Energy and Energy Conservation December 2003, as cited in UNDP "Promoting Environmentally Sound and Renewable Energy Resources through: Integrated Microhydro Development and Application Program (IMIDAP)" 40

DRAFT FOR DISCUSSION unbounded relative to demand (and perhaps land being a key constraint). Rather it is the maximum potential given the size of the off-grid population not serviceable by micro-hydro. Specifically, we took the total number of off-grid households in each Kalimantan province (from ESDM), subtracted the number of households we expected to be served by micro-hydro above (it is assumed that MHP is universally cheaper and therefore preferred). Although the analysis did not generally consider economic factors, we did screen out all villages with less than 50 people using BPS census data41, based on findings from Flores42 that villages with less than 10 households were unserviceable by mini-grids and that more decentralized solutions such as Solar Home Systems are required. We then used average power consumption in Indonesia to convert the remaining population to total power demand, and assumed a 20% capacity factor to establish the required capacity. This estimate must be treated with caution because:  Economic viability is based on highly localized population density, not village-level population density (in Indonesia, “villages” or Desa are administrative districts which can be many tens or hundreds of square kilometers)  The demography of Flores on which the 50-person cut-off was derived differs from Kalimantan (although this cut-off is not material to the results)  Although typical, 20% is not a universal capacity factor and depends on supply-side factors such as angulation and proper maintenance and demand-side factors such as user demand and population density  Persons per household varies village-by-village and we used an average of 3.7-4.3 persons per household in each province43 For woodchip (biomass), we have roughly estimated that the maximum technical potential of woodchip lies between 14 and 87MW across Kalimantan. This calculation takes the total (legal) roundwood production from Ministry of Forestry44 and estimates the waste proportion that could form fuel for a chipping mill boiler. This determines the maximum capacity in MW. The technical assumptions used include:      

Net calorific value of wood from Intergovernmental Panel on Climate Change (IPCC)45 Density of wood from Food and Agriculture Organization (FAO)46 and California State University Dominguez Hills47 Technical energy assumptions from the Project Design Document (PDD) that was submitted to the UNFCCC That the type of wood is Eucalyptus or Acacia That the amount of dry wood is about 49.8% by weight That the amount of bark waste is about 10.2% of total round wood production by weight

This estimate should be treated with caution as all the above coefficients are subject to uncertainty depending on local conditions.

BPS, 2010. Penduduk Indonesia menurut desa, hasil sensus penduduk 2010. page 1502-1697

http://wwwwds.worldbank.org/external/default/WDSContentServer/WDSP/IB/2014/01/30/000461832_20140130154855/Rendered/P DF/843140BRI0Indo0ox0382136B00PUBLIC00.pdf 43

http://www.bps.go.id/tab_sub/view.php?kat=1&tabel=1&daftar=1&id_subyek=12&notab=21

Ministry of Forestry, 2012. Profil Kehutanan 33 Provinsi.

2006 IPCC Guidelines for National Greenhouse Gas Inventories

http://www.fao.org/docrep/w4095e/w4095e0c.htm

http://www.csudh.edu/oliver/chemdata/woods.htm

DRAFT FOR DISCUSSION For biogas (POME), we have roughly estimated that the maximum technical potential of POME lies between 250 and 999 MW across Kalimantan. This calculation takes the total crude palm oil (CPO) production from Statistics Indonesia48 and estimates the associated fresh fruit bunch (FFB) production and wastewater proportion that could form fuel for a biogas engine in palm oil mill. This determines the maximum capacity in Megawatts. The technical assumptions used include:  Net calorific value of biogas from Intergovernmental Panel on Climate Change (IPCC)49  Technical energy assumptions from the Project Design Document (PDD) that was submitted to the UNFCCC.  That 5 tonnes of FFB will produce 1 tonne of CPO50  That processing 1 tonne of FFB will produce 0.9m3 of POME This estimate should be treated with caution as all the above coefficients are subject to uncertainty depending on local conditions. A summary of these results, disaggregated by province, is shown below. Across the four technologies, the largest potential across Kalimantan is for solar PV as shown. This is the same in all four provinces: Central Kalimantan, West Kalimantan, East Kalimantan and South Kalimantan. Most of the coefficients and assumptions in this section discussed are subject to uncertainty. Where we were able to obtain a low and high range for these inputs we used them to calculate a low and a high range for potential deployment. Table 5: Renewable energy potential in Megawatts by technology and province

POME (High)

POME (Low)

Wood Chip (High)

Wood Chip (Low)

Solar PV (High)

Solar PV (Low)

Micro Hydro (High)

Area

Micro Hydro (Low)

Potential (MW)

Central Kalimantan

0.3

1.6

432

443

398

East Kalimantan*

0.2

0.7

507

513

182

South Kalimantan

0.4

1.8

356

368

0.3

167

West Kalimantan

28.5

132.3

428

253

Kalimantan

29.4

136.4

1,295

1,752

250

999

Note: These data are from the year before the break-up of East Kalimantan into East Kalimantan and North Kalimantan. Therefore East Kalimantan also includes what is now known as North Kalimantan.

Care must be taken in adding up the numbers across technologies. To some extent they are additive. Solar PV and micro hydro are residential whereas biomass (woodchip) and biogas (POME) are primarily industrial, and we have separated out micro hydro and solar PV explicitly. But, biomass (woodchip) and biogas (POME) would be substitutes in some industrial facilities. And even where there is no direct technological overlap, market displacement effects as demand for one fuel changes the price of another mean that the total maximum potential may not be economically viable.

http://www.bps.go.id/tab_sub/view.php?kat=3&tabel=1&daftar=1&id_subyek=54&notab=8

2006 IPCC Guidelines for National Greenhouse Gas Inventories

From plantation agency of East Kalimantan data, 1 tonne of CPO is equivalent to 4.55 tonne of FFB. http://disbun.kaltimprov.go.id/statis-35-komoditi-kelapa-sawit.html

DRAFT FOR DISCUSSION We note that another recent study estimated that in Central Kalimantan, the estimated potential installed capacity for biomass/biogas energy generation is 337MW from palm oil waste (e.g. empty fruit bunch, shell fiber), 36.1MW from POME, 24.9MW from rice husk, 25.7MW from coconut, and 1.1MW from livestock.51

Energy and Environmental Partnership with Indonesia. EEP Indonesia Baseline Study I, 2012.

DRAFT FOR DISCUSSION

4 Scope of Analysis This section explains the impact pathway approach we use to structure our valuation. Impact pathways provide a rigorous way of categorizing activities, outcomes and stakeholders and deciding which items to include in the quantitative scope of analysis. Impact pathways and Indicators In order to determine the net benefit that each of our “green growth interventions” will generate, we must first establish how each intervention is likely to affect the environment, the economy and society as a whole. We use ‘impact pathways’ to describe the linkages between interventions (activities), the expected outputs from those activities, and the positive and negative outcomes that are generated in both the short and longer term. The structure of an impact pathway is outlined in Figure 14 below. Beneath Figure 14 there is an example from later in this report. By explicitly outlining this “theory of change”, we make sure that each outcome is clearly defined and that each is derived from tangible activities and outputs. Outcomes must be expressed in monetary terms to allow them to be compatible with a monetary Cost Benefit Analysis. Figure 14: An impact pathway

Inputs  What resources have been committed?

Activities

Outputs

Outcomes

Impacts

 How are the

 What are the

 How are

 The net change

resources used?

direct results of those activities?

stakeholders affected as a result of the outputs?

to stakeholders as a result of outputs

Illustrative example for the energy sector: Investment in micro hydro energy capacity

Power generation

Lower GHG emissions

Mitigated climate change

Lower air pollution

Improved health

Diesel fuel savings

Higher community incomes

Better quality evening lighting

Higher educational attainment and higher lifetime earnings

Deduct BAU outcome from project outcomes to get net impact

Table 6 below sets out the impact pathways constructed for the Green Growth scenario. These impact pathways define the scope of our cost-benefit analysis and identify the key indicators and outcomes that we will seek to quantify in our approach, as well as to whom these accrue. It is worth noting that this is not an exhaustive list of impacts, but rather a selection of high-impact interventions as identified through a brief literature review as well as those explicitly suggested by project stakeholders. Those impacts that are included in the eCBA (marked with a “”) are defined very strictly with respect to impacts and stakeholders; these have to be absolutely clear for the valuation to be

DRAFT FOR DISCUSSION robust. Those impacts not included in the eCBA are defined more flexibly (and marked with a “”) The costs and benefits associated with each impact have been “allocated” to one of the five outcomes for reporting purposes. This does not affect the valuation methodology but it determines how each outcome in Table 7, each cost or benefit is categorized. This process is now subject to uncertainty since many of the costs and benefits are cross-cutting; i.e., they contribute to more than one outcome of green growth. In particular, resilience is a cross-cutting outcome and interventions affecting resilience are likely to affect at least one of the other 4 outcomes as well. GHG emissions reduction through carbon storage and sequestration is also considered an outcome in its own right, although ‘nested’ within broader ecosystem benefits. It is explicitly separated due to the global prominence of climate change as an environmental issue and the key role Indonesia will play in mitigation. This is discussed further in accompanying GGGI reports52.

GGGI (2015) Scoping green growth in Indonesia. Working Paper GGGI Indonesia Program

DRAFT FOR DISCUSSION Table 6: Impact Pathways for renewable energy

GREEN GROWTH SCENARIO

BUSINESS AS USUAL SCENARIO

OUTPUT Output 1

Output 2

IMPACTED STAKEHOLDERS

Included in Scope of Model 

Market value of products sold (e.g. Extra trading hours)



Added market value of better information (e.g. improved price discovery)



Income generated from new job creation



Value of knowledge spill over to other communities



Value of new economic activities/ additional income from new economic activities



Mainly local communities

Value of preserved catchment area/forest (i.e. intrinsic value of biodiversity, water preserved, CO2 saving, etc.)



Existence of street light

Local Communities

Value of increased security



Decrease/eliminate use of fuel (diesel and kerosene)

Government

Avoided subsidy expense

Productive end-use of electricity (e.g. longer shop opening hours, use of sewing machine)

Access to information and technology

Local School Age Children/Local students Local small and medium enterprises (e.g. warung, restaurant)

POSITIVE OUTCOME / BENEFIT Potential future income from improved educational attainment

Better source of lighting and longer studying hours

Local Communities

Establishment of local cooperative to manage Micro Hydro Off-Grid Micro Hydro Plant (MHP)

NEGATIVE OUTCOME / COST

Kerosene for lighting and diesel generator

Local Communities New economic activities led by the cooperative (e.g. saving and loan activities to local business) Socialisation of the importance of catchment area/forest for providing good water flow

Higher rates of reporting of illegal activity and better preserved ecosystem services

Cost of Micro Hydro Plant installation, operation and maintenance, price of electricity installation and electricity/kWh



DRAFT FOR DISCUSSION

Local Communities

CO2 saving from less use of fuel Better source of lighting and longer studying hours Productive end-use of electricity (e.g. longer shop opening hours, use of sewing machine)

Off-Grid Solar PV

Kerosene for lighting and diesel generator

Access to information and technology

Avoided Fuel Cost



Avoided healthcare cost caused by indoor pollution from use of kerosene



Decrease mortality rate/morbidity from use of kerosene



Value from avoided fire risk from use of kerosene



Global Stakeholders

Climate change mitigated



Local School Age Children/Local students Local small and medium enterprises (e.g. warung, restaurant)

Potential future income from improved educational attainment



Local Communities

Establishment of local cooperative to concentrate Solar PV

Cost of Solar PV installation, operation and maintenance, price of electricity installation and electricity/kWh

Market value of products sold (e.g. Extra trading hours)



Added market value of better information (e.g. improved price discovery)



Income generated from new job creation



Value of knowledge spill over to other communities



Local Communities

DRAFT FOR DISCUSSION

New economic activities led by the cooperative (e.g. saving and loan activities to local business)

Value of new economic activities/ additional income from new economic activities



Existence of street light

Value of increased security



Avoided subsidy expenses



Avoided Fuel Cost



Avoided healthcare cost caused by indoor pollution from use of kerosene



Decrease mortality rate/morbidity from use of kerosene



Value from avoided fire risk from use of kerosene



Decrease/eliminate use of fuel (diesel and kerosene)

Government

Local Communities

CO2 saving from less use of fuel

Global Stakeholders Grid electricity from PLN Biomass (Woodchip) Diesel generator

Less electricity consumed by company and generated by PLN Less use of genset

Less coal and diesel combusted

PLN, Chipping Mill

Change in air pollution

Local communities

Change in CO2 emissions

Global Stakeholder

Cost of Biomass Plant establishment, operation, and maintenance

Climate change mitigated



Avoided cost of electricity



Lower subsidy bill



Climate change mitigated



Avoided cost of diesel fuel



DRAFT FOR DISCUSSION Excess Power to be sold to PLN Diesel generator Less use of genset Off-Grid Biogas (POME)

Increase of electricity ratio in Kalimantan

Company

Less diesel combusted

Company

Change in air pollution

Local communities

Change in CO2 emissions Biomass Boiler (Palm Kernel Shell and Palm Oil Fiber)

Global Stakeholder

Less biomass (PKS and Palm Oil fiber) combusted

Income from electricity sales to PLN



Cost of Biomass Plant establishment, operation, and maintenance

Lower subsidy bill

 

Climate change mitigated

 

Avoided cost of diesel fuel

Increased compost/fertilizer available

Note: Extra trading hours included in MHP and not Solar since there were no identified power-connected kiosks in the latter village.





DRAFT FOR DISCUSSION

5 Results and Findings This section outlines the results and findings of the Financial Analysis and Extended Cost Benefit Analysis of the selected four renewable energy projects, based on a range of assumptions. Summary of results and findings; Key messages Our analysis concludes that the four green energy technologies are not attractive private sector investments given their current design and application. However, extending the analysis to consider the wider social, environmental and economic costs and benefits suggest that all four technologies could be attractive public investments based on assumptions adopted in our analysis. The benefits of the Green Growth scenario above can be broken down as follows: •

•

Social Development benefits of $1m; the value of better educational attainment from longer and more productive studying hours, and better health from reduced indoor air pollution. Proportionately more of the social benefits derive from the community renewables projects (Micro Hydro Power and Solar PV). Because these projects are small in MW terms, these benefits appear small; but, they would be of an order of magnitude higher if the projects were scaled up to the same level as the industrial projects.

•

GHG Emissions benefits of $61m; reduced CO2 emissions as kerosene and diesel displaced from village fuel mixes, and from reduced coal and diesel generation from on-grid power plants. Carbon valued at USD 80/tCO2. Proportionately more of the GHG benefits derive from the POME and Biomass projects.

A summary of the results and findings is provided in Table 7 below, and the key cost and benefit categories that drive them in Table 8 below. Table 7: Summary of results and findings (USD million) Financial Metrics Net Present Value (USD million)

IRR (%)

Micro Hydro (FS)

-0.29

Micro Hydro (Benchmark)

Extended CBA metrics

Outcomes of Green Growth

Net Present Value (USD million)

EIRR (%)

-5.3

3.8

84.5

3.0

0.4

-0.30

-6.8

2.4

55.2

1.7

0.4

0.3

Solar PV (FS)

-2.8

n/a

-0.9

1.0

-1.6

0.5

0.2

Solar PV (Benchmark)

-0.6

n/a

1.3

25.6

0.6

0.5

0.2

Biomass (woodchip)

2.9

12.1

102.4

50.3

74.9

27.5

Biogas (POME)

1.7

16.0

39.1

120.7

6.6

32.4

Economic Growth (USD million)

Social Development (USD million)

GHG emissions (USD million)

DRAFT FOR DISCUSSION Total incremental 1.5 n/a 144.4 n/a 82.8 1.0 60.6 on BAU (FS only) Note: It is best to compare different scenarios on the same basis (e.g. financial BAU with financial GG); comparison between the same scenario under financial/eCBA parameters can be misleading due to the differing discount rate and treatment of taxes. NPV rather than BCR rankings should be used for ranking projects. Totals may not add up due to rounding.

DRAFT FOR DISCUSSION In Table 8 below, we have provided the individual items included in model calculations. Table 8: Summary of costs and benefits in each scenario

Costs

Benefits

 Capital costs (including scheduled repairs)

 Sales of power to local community at socially acceptable tariffs

Financial Cost Benefit Analysis (@ 10%) Micro Hydro

 O&M costs  Scrap value Solar PV

 Capital costs battery and replacement)

(including inverter

 Sales of power to local community at socially acceptable tariffs

(including

 Sales of power to PLN at prevailing Feed-in Tariff

 O&M costs Biomass (woodchip)

 Capital costs refurbishment)  O&M costs

 Reduced power consumption from the grid

 Tax/Subsidy  Fuel costs assumed zero Biogas (POME)

 Revenues from carbon credits (UN CDM)

 Capital costs

 Reduced diesel consumption

 O&M costs

 Revenues from carbon credits (UN CDM)

 Scrap value  Tax/Subsidy  Fuel cost assumed zero Extended Cost Benefit Analysis (@ 5%) Micro Hydro

 Capital costs (including scheduled repairs)



Avoided health pollution

 O&M costs



Improved educational outcomes from enhanced light



Avoided diesel and kerosene fuel costs



Value of GHGs mitigated



Economic development benefits to local businesses



Avoided health pollution



Improved educational outcomes from enhanced light



Avoided diesel and kerosene fuel costs



Value of GHGs mitigated



Avoided electricity generation costs for PLN (including subsidy)



Value of GHGs mitigated

 Scrap value

Solar PV

 Capital costs battery and replacement)

(including inverter

 O&M costs

Biomass (woodchip)

 Capital costs refurbishment)

(including

 O&M costs

cost

from

indoor

DRAFT FOR DISCUSSION  Tax/Subsidy  Fuel costs assumed zero  Increment of damage cost due to air pollutant (NOx and PM) Biogas (POME)

 Capital costs



Avoided diesel fuel costs

 O&M costs



Value of GHGs mitigated

 Scrap value  Tax/Subsidy  Fuel costs assumed zero

DRAFT FOR DISCUSSION Results and Findings: Financial The financial analysis uses only cash costs and benefits such as revenue, capital and operating costs, over a 20-year timeframe. This is a fundamental tool for private sector and other investors to make decisions. This section will explain the financial analysis for the four renewable energy technologies. A core assumption running through the financial analysis is that the cost of capital is 10% (in real terms). The financial costs and benefits of each technology are presented in Figure 15 below. These are quite different, although if combined across the 4 renewable technologies, would generate an NPV of USD 1.5m when discounted at 10%; and a maximum Internal Rate of Return of 16% for the POME project. On the following pages we explain in detail the scope, assumptions and data sources used to calculate the financial costs and benefits.

Millions USD

Figure 15: Financial analysis; comparison of the 4 renewable energy technologies

30%

12.1%

16.0% 10%

0% FS -0.29

-1

-5.3%

Benchmark -0.3 MHP

Benchmark Solar PV

Woodchip

POME

-1

-6.8%

-10%

-2

-3

20%

-20%

NPV

-3

IRR

Note: FS = Feasibility Study data. Benchmark = Substituting some FS data for international benchmarks (see relevant section for explanation)

-30%

DRAFT FOR DISCUSSION Micro Hydro The Micro Hydro Plant (MHP) financial numbers are drawn from a Feasibility Study provided to the project team by Dinas Pertambangan dan Energi (“Distamben”) in Murung Raya district, Central Kalimantan. This study examined a 130kW run-of-the-river MHP sited in Tumbang Kunyi village. Capital costs are estimated at IDR 5.2 bn (around USD 3,000/kW) with a 5% scrap value after 20 years. 7-yearly maintenance expenditures of IDR 200 million (USD 16,000) are also identified. It is assumed that the co-operative running the MHP is tax-exempt. Costs and revenues are dependent on the capacity factor (i.e., how many hours and to what extent the MHP is actually generating power). The Feasibility Study provides a range of scenarios from 40% to 80%; we have selected 50% as our base case therefore. This figure is calculated after accounting for 9% of annual hours’ downtime for maintenance. The ongoing operational and maintenance costs are IDR 171 million (USD 14,000) a year. Revenue is equal to total generation (560 MWh), less 10% Transmission and Distribution losses53, multiplied by the quoted tariff of IDR 750/kWh. This amounts to USD 28,645 per year. In our analysis, no connection fee was charged. In total, the NPV is equal to USD -290,054; equivalent to an Internal Rate of Return of -5.3%. In short, while revenues are sufficient to cover operational costs, they will not adequately fund capital repayments. This is essentially the same as the original conclusion of the Feasibility Study: “From a financial perspective, the development of the MHP Air Terjun Ongkong Taba’ang…is not financially feasible …with private sector investment.” They calculate a NPV of IDR 652 million (USD 52,000); equivalent to an IRR of 4.5%54. The project team has made several observations on the provided analysis:  The tariff charged is unlikely to be affordable or socially acceptable; based on evidence from remote communities running MHPs in Sumatera and Sulawesi we would expect tariffs to be in the range of IDR 5,000 - 50,000 per month per household, not IDR 60,000110,000 as implied in our model.  Although reasonable compared to capex or on a per kWh basis (see Figure 16 below), the O&M costs are unusually high in absolute terms. Since wages typically account for around 80% of O&M55, these costs (USD 14,000/year) appear high when compared to a benchmark wage bill for rural Indonesian operation for MHP (USD 1,200/year)56. These two observations are of course linked, since tariffs are generally set at a level to recover O&M costs (but typically not capital costs). To account for these outliers, we have re-run the analysis using the benchmark assumptions discussed above (IDR 579/kWh, a capacity factor of 38%, and O&M of around USD 1,200/year). Replacing these three assumptions, the NPV is equal to USD -302,253; equivalent to an Internal Rate of Return of -6.8%. This suggests that the 53

Source: based on personal correspondence with MHP developer in Indonesia

Differences are due to differing discount rates and our inclusion of T&D losses and scrap value.

World Bank (2012) Micro Hydro Power (MHP) Return of Investment and Cost Effectiveness Analysis

Millennium Challenge Corporation (2012) Ex Ante Economic Analysis for Micro Hydro Electric Systems in Remote Communities in Indonesia (unpublished)

DRAFT FOR DISCUSSION implications for financial viability will remain unchanged if market-based tariffs are combined with better cost control. It is important to be realistic about attainable capacity factors, too. Solar PV The Solar PV financial numbers are drawn from an Inventory Study (i.e., site selection study, prefeasibility) provided to the project team by Dinas Pertambangan dan Energi (“Distamben”) in Murung Raya district, Central Kalimantan. This study proposed a 140kW Solar PV array sited in Sungai Gula village. Capital costs were estimated in the Inventory Study at IDR 38bn (around USD 22,000/kW). Battery replacement costs were not included. A capacity factor of 14% was used, which is an estimate of equipment performance based on the prevailing solar intensity in Central Kalimantan (4.6 kWh/m2/yr) as well as scheduled downtime for maintenance. The ongoing operational and maintenance costs were not estimated in the inventory study, but were based on data from Solar PV min-grids in rural India. These were USD 0.03/kWh or USD 6,000/year. Revenue is equal to total annual generation (170 MWh), less 10% Transmission and Distribution losses57, multiplied by a benchmark tariff for mini-grid renewables in Indonesia of IDR 579/kWh58. This amounts to USD 8,000 per year. In our analysis, no connection fee was charged. In total, the NPV is equal to USD -2.8m. These results suggest that this technology is an extremely expensive way to electrify an area. Not only is this financially nonviable for private investors, but even with government capital grants, the revenues do not exceed the running costs by a large margin (25%), suggesting the fiscal sustainability is not assured. This is much the same conclusion the Inventory Study came to: “To electrify this village, given the estimated capital costs, we suggest to instead use a diesel generator”59. While we agree that these conclusions are sensible based on the evidence, we do not necessarily agree with the evidence itself. Reliable costing data for this size (10-999kW) of Solar PV panel is not available in Indonesia, but a handful of international benchmarks exist, which all suggest that the capital costs in the Inventory Study are over-stated.

Source: based on personal correspondence with MHP developer in Indonesia

Source: World Bank (2012) Micro Hydro Power (MHP) Return of Investment and Cost Effectiveness Analysis

Shortened translation from pre-feasibility study

DRAFT FOR DISCUSSION Figure 16: International benchmarks for capital costs and levelized costs

25,000

Levelized Costs c/kWh

140 120

Using international capital costs

Using Feasibility Study capital costs

100

20,000 15,000

80 10,000

60 40

5,000

20 0

Capital Costs USD/kW

160

0 ESMAP (2007): International [25kW]

ESMAP/McKinsey NREL (2010): India (2011): [250kW] International [n.a.] Capital Costs

Sungai Gula Inventory Study (2014) [140kW]

Levelized Cost

To account for this potential over-estimation of the capital costs we ran an additional scenario, substituting the original cost estimates with the international panel costs60 from the most appropriate benchmark (rural India in terms of remoteness, ease of doing business, and GDP/capita). The results of this scenario are different although still negative; the total NPV is equal to USD 649,076 Using these assumptions significantly alters the conclusions in economic terms; we discuss this in the Extended CBA Section.

Retaining the original distribution and installation costs from Murung Raya.

DRAFT FOR DISCUSSION Biomass (woodchip) The biomass (woodchip) financial numbers are drawn from the public documentation associated with the registration of the PT Korindo Woodchip Biomass project under the UN Clean Development Mechanism61. This study proposed a 7.3MW woodchip-fired boiler in the chipping mill at Kumai, Central Kalimantan. On the cost side, capital costs were estimated in the financial analysis performed for Project Validation at USD 24 million (around USD 3,200/kW) plus a refurbishment in the tenth year of operation, costing USD 4.7 million. A capacity factor of 72% was used, corresponding to a throughput of 1.35 million tonnes of wood per year. The ongoing operational and maintenance costs are USD 2.6 million a year plus corporation tax due (at 25% of positive operating income). The financial benefits stream is formed of three parts: 1. The avoided costs of power purchase off the grid (required for chipping operations). This is equal to 25.8 million kWh at IDR 937/kWh. 2. The sales of excess power back to the grid. This is equal to 26.2 million kWh at the current Feed-in Tariff rate of IDR 1,380/kWh62. 3. The payment of carbon credit revenues through the CDM. We use the current market price of USD 0.14/tCO2, rather than the price in the PDD which makes this revenue stream negligible (0.1% of revenue). In total, the NPV is equal to USD 2.9m; equivalent to an Internal Rate of Return of 12.1%. The project is financially marginal at a cost of capital of 10%; any slight changes to the engineering or financial assumptions and the IRR would likely dip below 10%.

https://cdm.unfccc.int/Projects/DB/TUEV-RHEIN1352458882.32/view. PDD = Project Design Document

Permen ESDM 27/2014, for PLTBm medium voltage, with F=1.3 for Kalimantan

DRAFT FOR DISCUSSION Biogas (POME) The POME financial numbers are drawn from the public documentation associated with the registration of the PT Rea Kaltim Plantations Cakra Methane Capture project under the UN Clean Development Mechanism63. This study proposed a biogas digester to capture methane emissions of their wastewater treatment system for use in 2.1 MW biogas engines in the palm oil mill at Kutai Kartanegara district, East Kalimantan. On the cost side, capital costs were estimated in the financial analysis performed for Project Validation at USD 4.4 million (around USD 2,000/kW) with a scrap value of USD 3,299 after 20 years. The mill produces a throughput of 0.35 million tonnes of fresh fruit bunch (FFB) per year. The ongoing operational and maintenance costs are USD 310,000 a year plus corporation tax due (at 25% of positive operating income). The financial benefits stream is formed of two parts: 1. The avoided costs of diesel fuel (required for mill operations). This is equal to about 0.9 million liters of diesel64 at IDR 16,500/liter. 2. The payment of carbon credit revenues through the CDM. We use the current market price of USD 0.14/tCO2, rather than the price in the PDD which makes this revenue stream negligible (0.3% of revenue). In total, the NPV is equal to USD 1.7m; equivalent to an Internal Rate of Return of 16%. The project may thus be financially feasible at a cost of capital of 10% (although as the sensitivity analysis will demonstrate, only minor changes to the engineering or financial assumptions would be required to take the project â&#x20AC;&#x2DC;into the red).

http://cdm.unfccc.int/Projects/DB/DNV-CUK1337678112.09/view. PDD = Project Design Document

The amount of diesel saved is based on the historical data. Prior to the project, biomass was also used to generate electricity

DRAFT FOR DISCUSSION Results and Findings: Extended Cost Benefit Analysis The eCBA extends the financial analysis to account for externalities and other market failures, expressing all costs and benefits in terms of shadow prices. This section will explain the eCBA of the four renewable energy technologies. There are three assumptions running through the eCBA analysis:  The social discount rate used to generate Net Present Values is 5% (in real terms)  Cash costs that are social transfers (i.e., taxes) are excluded from the analysis  Market wages provide a reasonable proxy for the opportunity cost of skilled labor in Central Kalimantan The eCBA costs and benefits of each technology are presented in Figure 17 below. Overall, the feasibility study renewable technologies generate an extended NPV of USD 144m when discounted at 5%; with Economic Rates of Return generally above 25% (with one exception). On the following pages we explain in detail the scope, assumptions and data sources used to calculate the extended costs and benefits.

Millions USD

Figure 17: eCBA analysis; comparison of the 4 renewable energy technologies 121%

130 NPV

120

IRR

120%

110 100 90

110%

102

100%

85%

90%

80%

70%

55%

50%

60 50

60% 39

26%

40%

20% 4

Benchmark

MHP

10%

-10

50%

30%

20 10

130%

FS -1

Benchmark Solar PV

0% FS

Woodchip

POME

Note: FS = Feasibility Study data. Benchmark = Substituting some FS data for international benchmarks (see relevant section for explanation)

-10%

DRAFT FOR DISCUSSION Micro Hydro The extended Cost Benefit Analysis broadens and enhances the financial analysis to include the full range of social, economic and environmental benefits from the MHP program. These are consistently higher than the purely financial value of power as reflected by the tariffs. We note that many of the impact pathways described here draw on two Millennium Challenge Corporation and World Bank-commissioned analyses of MHP programs in Sulawesi and Sumatera.65 Firstly, the replacement of diesel gensets (for main power loads) and kerosene lamps (for light only) save households the cost of buying fuel. This can be a substantial portion of their monthly income (around IDR 660,000/month or 19.8%66 of typical household income in Central Kalimantan). Furthermore, there is an additional saving to government for fuel consumption avoided, equal to the per unit subsidy on diesel and kerosene. Taking these together gives a shadow price of diesel of around IDR 20,250/liter and IDR 18,300/liter for kerosene (see Section 3 on Methodology), or annual savings of USD 266,027 for diesel and USD 18,456 for kerosene. Secondly, avoiding the combustion of kerosene indoors brings significant health benefits. Kerosene lamps typically emit 51Âľg/hour of PM10 Particulate Matter (a known carcinogen). This compares to a World Health Organization recommended limit of 50Âľg/m3 over 24 hours (i.e., in a small room with poor ventilation the WHO limit will almost certainly be breached). Based on the resultant reductions in risk of infant mortality as well as increased adult working days, the elimination of kerosene lamps has been estimated at USD 2.70/household/year; equivalent to USD 415/year for the village of Tumbang Kunyi. Thirdly, the light from kerosene lamps is notoriously poor, and even a 60W electric light bulb emits more than 10 times more light. Improved lighting quality has been shown in Indonesia and elsewhere to extend studying time and result in higher educational attainment. These benefits has been estimated at USD 13/month/child; equivalent to USD 37,127 per year for the village of Tumbang Kunyi. Fourthly, reduced combustion of both kerosene and diesel results in reduced CO2 emissions that contribute to global climate change. Using standard factors for the carbon content of each fuel67, and a value of USD 80/tCO2 for the Social Cost of Carbon68, we estimate these benefits are worth around USD 37,132 a year. Fifthly, it is not only households that benefit. Retail businesses (kiosks etc.) can have longer opening hours, generating additional revenue. The 3 workshops in Tumbang Kunyi will also save diesel fuel expenses in their energy0-intensive welding operations. Lastly, a number of other public facilities including 7 schools, 6 clinics, 6 prayer facilities and 3 government offices save on their diesel fuel bills. It is conservatively assumed that they each use the same amount of fuel as the average household; 2 liters per day. These savings are included in the USD 267,522 for diesel and USD 68,878 for kerosene figure above.

Millennium Challenge Corporation (2012) Ex Ante Economic Analysis for Micro Hydro Electric Systems in Remote Communities in Indonesia (unpublished) 66

Potret Usaha Pertanian Provinsi Kalimantan Tengah manurut sub sector. P28. BPS 2013.

Source: US Energy Information Administration

Source: Tol (2009) The Economic Effects of Climate Change. Mean value for peer-reviewed literature, assumes Pure Rate of Time Preference of 0%.

DRAFT FOR DISCUSSION The cost side is largely identical to the financial analysis, on the assumption that the engineersâ&#x20AC;&#x2122; wage rate is the best proxy for the shadow wage for skilled labor69. In total, therefore, the Extended NPV of the MHP Inventory is around USD 3.8m; equivalent to an Economic Internal Rate of Return of 85%. Using the alternative benchmark assumptions discussed in the financial analysis provides broadly the same results; USD 2.4m NPV and 55% EIRR. This implies that while MHP generates a negative financial NPV for private investors, accounting for the displacement of expensive fuel as well as wider socio-economic and environmental benefits, the project is economically viable and socially desirable.

This is an assumption used in other Kalimantan Cost Benefit Anlayses, in the absence of more detailed data. See e.g. The Nature Conservancy (2010) Carbon Emissions from Land Use, Land Use Change and Forestry (LULUCF) in Berau District East Kalimantan, Indonesia

DRAFT FOR DISCUSSION Solar PV Since Solar PV and MHP have fundamentally similar setups (mini-grids operating in the 100kW1MW range with around 100-1000 households), the benefit categories and calculations are very similar to MHP. Therefore, the key benefits include: 

Avoided fuel costs



Health benefits from reduced indoor pollution



Better lighting and higher educational attainment



Reduced CO2 emissions

There are some conceptual differences in the way these benefits were calculated. Firstly, the counterfactual is slightly different. In the MHP case in Tumbang Kunyi the village already had substantial energy access through diesel gensets; so the current situation was the baseline. In the case of Sungai Gula though, only around 10% of households have a genset. We have assumed that a centralized mini-grid generator is to be imminently installed, and therefore the baseline is a 140kW diesel generator. The value of diesel savings per unit of demand is also lower, since the centralized generator has a higher thermal efficiency (38%) than individual gensets (30%).70 Given this, and the significant higher capital costs of Solar compared to MHP the Net Present Value was significantly lower than MHP; USD-0.9m, or an Economic Internal Rate of Return of 1%. This suggests that even with the wide range of benefits mentioned above, the project does not justify itself. However, using benchmark capital costs discussed in the financial analysis the economic feasibility significantly improves with an NPV of USD 1,300,193 and an Economic Internal Rate of Return of 26%. In effect, the levelized cost is brought down from 139 to 36c/kWh. Since this is still higher than a socially-acceptable tariff, the Financial Internal Rate of Return would still be less than the cost of capital71 (10%; see previous section). But, when compared to the marginal (shadow) cost of diesel generation of 17c/kWh72, solar starts to look more competitive if other benefits are taken into account. With operational improvements such as a higher capacity factor, the levelized cost could be brought down further. We also note that the Inventory Study has probably under-sized the required capacity for Solar Generation. Comparing a 140kW Diesel generator with a 140kW Solar PV array is inappropriate due to differing capacity factors (say 80% vs. 20% on average). A simple calculation73 suggests that demand would exceed supply at this level of provision.

However, it is likely that some form of diesel generator would be required for backup power and to smooth over the load profile when the Solar PV-batteries are insufficient. This hybrid diesel-Solar PV setup is common in emerging market mini-grids. It does not detract from the findings as we have not included avoided capital costs as a benefit category, just fuel savings, which the Solar project would still generate at the margin. 71

For this series of cash flows, it is not mathematically possible to calculate the IRR. However, given NPV is negative, it would certainly be less than the cost of capital. 72

Calculation based on cash flows in economic model using LCOE formula as per, for example, http://www.nrel.gov/analysis/tech_lcoe_documentation.html 73

300 households * 200W connection = Peak load of 60kW, or half of the 140kW. Yet the maximum peak load a 140kW array could generate is around 20% (i.e., the capacity factor)

DRAFT FOR DISCUSSION Biomass (woodchip) The number of additional benefits (relative to the financial analysis) for the on-grid biomass project is limited74, but the value substantial. The key benefits are two-fold: Firstly, biomass is a low-carbon fuel, with a substantially lower GHG emissions factor than coal and diesel (in Central and South Kalimantan, 900kgCO2/MWh75). Avoided GHG emissions are valued at USD 80/tCO2 amounting to an annual benefit of USD 3.7m. Secondly, the economic value of the biomass generation is not equal to the Feed-in Tariff, which is not a market price but instead set by government. Our assumption is that it is equal to the avoided cost of generation for the 52,000 MWh that no longer have to be generated by PLN. Using PLN’s average generation cost estimates from 2012 by fuel, combined with data on the grid-connected power plants across South and Central Kalimantan (see Section 3 on Methodology), we estimate that each unit of biomass power generated saves USD 0.19kWh, or USD 0.21/kWh including avoided Transmission and Distribution Costs. Since PLN’s losses are subsidized, this USD 11.1m annual benefit accrues largely to Ministry of Finance. In total, therefore, the Extended NPV of the biomass (woodchip) plant is around USD 102.4m; equivalent to an Economic Internal Rate of Return of 50.3%. In short, this green growth technology generates huge value for the taxpayer while reducing Indonesia’s GHG emissions at the same time.

There is also likely to be a small local air pollution impact but we were unable to obtain credible air pollution coefficients for a site like this relative to the baseline coal power plant technology. 75

We use an average South/Central Kalimantan rather than marginal grid factor for the site in line with the UN CDM Project Design Document. This is not strictly accurate presently since the Barito System transmission grid is not connected to the local grid yet; however, plans are underway to connect them and so the 20-year emissions factor is more likely to correspond to the whole system than the local diesel power plant (Sistem Pangkalan Bun). The quantitative affect in the short-run is to slightly over-estimate the carbon benefits. But, at the same time it underestimates the economic savings from avoided generation cost. On balance, this assumption underplays the potential long-term benefits and so is conservative.

DRAFT FOR DISCUSSION Biogas (POME) The number of additional benefits (relative to the financial analysis) for the off-grid biogas project is limited, but the value substantial76. The key benefits are two-fold: Firstly, biogas is a low-carbon fuel, with a substantially lower GHG emissions factor than diesel (3.19 tCO2/tonne77). Avoided GHG emissions are valued at USD 80/tCO2 amounting to an annual benefit of USD 4.4m. Secondly, the replacement of diesel gensets saves the company the cost of buying 0.9 million liter per year of diesel fuel. Since this is in principle industrial, unsubsidized diesel, we assume that the shadow price is equal to the market price (IDR 16,500/liter). In total, therefore, the Extended NPV of the POME based power generation is around USD 39m; equivalent to an Economic Internal Rate of Return of 121%. In short, this green growth technology generates substantial value for the taxpayer while reducing Indonesiaâ&#x20AC;&#x2122;s GHG emissions at the same time.

There is also likely to be a small local air pollution impact but because the site is rural and the generator relatively small we have not considered this in the analysis, as it is likely to be immaterial. 77

We refer to the IPCC Volume 2 Chapter 1, Table 1,2; Net calorific value of diesel fuel is 43 GJ/tonne and the CO2 emission factor for diesel fuel is 0.0741 tCO2/GJ.

DRAFT FOR DISCUSSION Scaled Up; Kalimantan as a corridor The results of the previous four technologies were each based on real projects in Kalimantan. The financial and extended costs and benefits and investment needs relate to those villages or industrial facilities. Please refer to the executive summary for the limitation and assumption made for this analysis. However, we have sought to understand what the scale of these costs and benefits might be if these project types could be ‘scaled up’ to their maximum technical potential across Kalimantan. To do this we have: a) Estimated (roughly) the maximum technical potential (in MW) for each technology in Kalimantan (see Section 3 for full methodology and results) b) Calculated the net benefit per MW and capex per MW for each technology c) Multiplied (a) by (b) together. The range is derived by taking the lowest and highest value for each parameter (drawn from across the Feasibility Studies and international benchmarks). This is calculated using the maximum technical potential (in MW) calculated in Section 3, combined with the net benefits per MW and capital expenditure per MW implicit in this Section. The lowest and highest value for each assumption or source of uncertainty is drawn from across the Feasibility Studies and international benchmarks. We estimate that annual average net social benefits of USD 1.4-8.9bn (3-16% of GRDP) would be realized if investment of USD 10-57bn were committed today. The biggest potential impact derives from POME, but per unit of investment, micro-hydropower provides the greatest impact. Table 9 below provides the full results, but in short, for each technology:  The maximum potential net benefits are between USD 0.5 and 4.0 billion if investment of USD 0.1-0.4bn is made in micro hydro.  The maximum potential net benefits are between USD -11.4 and 16.3 billion if investment of USD 6-39bn is made in solar PV.  The maximum potential net benefits are between USD 0.2 and 1.4 billion if investment of USD 0.05-0.3bn is made in biomass (woodchip) boilers.  The maximum potential net benefits are between USD 39 and 156 billion if investment of USD 4-18bn is made in biogas (POME) based digester and engine.

DRAFT FOR DISCUSSION Figure 18: Potential net benefits from full deployment, and associated investment needs

Investment costs (billions US$)

45 MHP (Low)

MHP (High) Solar PV (Low)

Solar PV (High) Woodchip (Low)

Woodchip (High) POME (Low)

5 -100

-5

POME (High) 0

100

200

Net Benefits (billions US$)

Investment Costs (millions US$)

-15

650

550

450

MHP (Low)

350

MHP (High) Woodchip (Low) 250

Woodchip (High)

150

50 -1

-50

Note that these results should not be interpreted as saying that some technologies are better than others. Different applications of power (villages, mills) in different locations have different needs. The eCBA has demonstrated that all projects provide valuable social returns in different situations. But, it must be recognized that public and private funds are limited, and so the results

DRAFT FOR DISCUSSION do hint at a potential plan for investment prioritization. Further research is needed in this area to create an integrated renewable energy strategy for Kalimantan.

DRAFT FOR DISCUSSION Table 9: Investment cost by technology and province

Micro Hydro (Low)

Micro Hydro (High)

Solar (Low)

Wood Chip (Low)

Wood Chip (High)

POME (Low)

Central Kalimantan

1.2m

5.1m

1.9bn

9.8bn

15.5m

93m

1.8bn

7.0bn

East Kalimantan*

0.5m

2.4m

2.3bn

11.4bn

25.1m

150.8m

0.8bn

3.2bn

South Kalimantan

1.3m

5.9m

1.6bn

8.2bn

0.7bn

2.9bn

West Kalimantan

93.5m

433.5m

0.0bn

9.5bn

11.8m

71.2m

1.1bn

4.5bn

Kalimantan

0.01bn

0.45bn

5.8bn

38.8bn

0.05bn

0.32bn

4.40bn

17.6bn

Solar (High)

POME (High)

Note: These data are from the year before the break-up of East Kalimantan into East Kalimantan and North Kalimantan. Therefore East Kalimantan also includes what is now known as North Kalimantan.

Table 10: Net benefits by technology and province

Micro Hydro (Low)

Micro Hydro (High)

Solar (Low)

Wood Chip (Low)

Wood Chip (High)

POME (Low)

Central Kalimantan

6.2m

46.4m

-2.9bn

4.1bn

65.7m

395.5m

15.5bn

62.2bn

East Kalimantan*

2.9m

21.6m

-3.3bn

4.8bn

106.6m

641.5m

7.1bn

28.4bn

South Kalimantan

7.1m

53.1m

-2.4bn

3.4bn

4.2m

25.5m

6.5bn

26.0bn

West Kalimantan

0.5bn

3.9bn

-2.8bn

4.0bn

50.4m

303.0m

9.9bn

39.5bn

Kalimantan

0.5bn

4.0bn

-11.4bn

16.3bn

0.2bn

1.4bn

39.0bn

156.1bn

Solar (High)

POME (High)

Note: These data are from the year before the break-up of East Kalimantan into East Kalimantan and North Kalimantan. Therefore East Kalimantan also includes what is now known as North Kalimantan.

DRAFT FOR DISCUSSION Limitations This is a high-level analysis designed to test whether project-level eCBA results and findings can credibly be ‘scaled-up’. It is dependent on several assumptions and has limitations:    



The technical potential ignores broader economic interactions such as General Equilibrium effects when the technologies are deployed at scale A number of physical and engineering uncertainties and factors are not accounted for (angulation, land availability; see Section 3) The analysis draws on external research and data (e.g. from Government of Indonesia) which has not been validated Benefits and cost are assumed to scale-up linearly with capacity (MW). In practice, costs are likely to vary with capacity (e.g. economies of scale), and benefits will decline as other factors kick-in at scale (e.g. fuel rebound effect). In particular, fuel prices are lower in areas well-served by transport infrastructure and so fuel savings will be lower. It assumes that the fundamental characteristics of the projects are the same at scale (e.g. on-grid and off-grid, capacity factors), and that the focus remains on provision of basic connections (~2ooW) rather than upgrading of existing connection (e.g. to 450W)

Most importantly, there is an assumption that biomass is a residual waste product. In practice, there is a risk that increased market demand for the fuel alters the economic incentives of the upstream forestry plantations or logging operations and encourages further deforestation. This would therefore undermine the green case and reduce the net benefits per MW which could even become net costs. Nonetheless, it provides a useful broad-brush range for the benefits possible from deployment of green technologies. To the best of our knowledge, this has not been done before and we hope it inspires further, more detailed, research for which there clearly is a need.

DRAFT FOR DISCUSSION Sensitivity Analysis In this section, we test the sensitivity of the results to variations on the underlying assumptions, including costs, quantities, prices and discount rates. All input values are flexed by Âą25%, and a number of additional assumptions are also flexed by a custom amount if there are grounds for believing the uncertainty is likely greater than 25% (e.g. potential carbon prices). The tables below list the variables which are flexed, and by how much. Table 11: Variation of input variables in sensitivity analysis (financial)

WACC Micro Hydro (FS)

Capacity Factor Tariff Capex WACC

Micro Hydro (Benchmark)

Solar PV (FS)

Solar PV (Benchmark)

Capacity Factor

Base Case Value 10%

Unit

Low

High

7.5%

-25%

12.5%

+25%

50%

38%

-25%

63%

+25%

750 5.2bn 10%

IDR/kWh IDR %

563 3.9bn 7.5%

-25% -25% -25%

938 6.5bn 12.5%

+25% +25% +25%

38%

29%

-25%

47%

+25%

Tariff Capex

561 5.2bn

IDR/kWh IDR

420 3.9m

-25% -25%

701 6.5m

+25% +25%

WACC

10%

7.5%

-25%

12.5%

+25%

Solar insolation

4.6

kWh/m2/day

3.5

-25%

5.8

+25%

561 37.8bn 10%

IDR/kWh IDR %

421 28.4bn 7.5%

-25% -25% -25%

701 47.3bn 12.5%

+25% +25% +25%

4.6

kWh/m2/day

3.5

-25%

5.8

+25%

Tariff WACC

561 10.0%

IDR/kWh %

421 7.5%

-25% -25%

701 12.5%

+25% +25%

Feed-in Tariff

1,380

IDR/kWh

1,035

-25%

1,725

+25%

937

IDR/kWh

703

-25%

1,171

+25%

5,738

hours/year

4,304

-25%

7,173

+25%

Tariff Capex WACC Solar insolation

Industrial user tariff Biomass (woodchip) Annual mill operating hour Capex

Biogas (POME)

22.88m

USD

17.16m

-25%

28.60m

+25%

Carbon price

0.14

USD/tCO2

0.11

-25%

+7140%

WACC

10.0%

7.5%

-25%

12.5%

+25%

Market price of diesel

16,455

IDR/liter

12,341

-25%

20,569

+25%

Capex Carbon price

4.11m 0.14

USD USD/tCO2

3.08m 0.11

-25% -25%

5.14m 10

+25% +7140%

DRAFT FOR DISCUSSION Table 12: Variation of input variables in sensitivity analysis (eCBA)

Micro Hydro (FS)

Micro Hydro (Benchmark)

Solar PV (FS)

Solar PV (Benchmark)

Biomass Woodchip

Base Case Value

Unit

Low

High

Social Discount Rate

3.8%

-25%

6.3%

+ 25%

Capacity Factor

50%

38%

-25%

63%

+ 25%

Social Cost of Carbon Opportunity Cost of Diesel in Kalimantan Opportunity Cost of Kerosene in Kalimantan Capex

USD/tCO2

-25%

100

+ 25%

20,250

IDR/liter

15,188

-25%

25,313

+ 25%

18,300

IDR/liter

13,725

-25%

22,875

+ 25%

5.2bn

IDR

3.9bn

-25%

6.5bn

+ 25%

Social Discount Rate

3.8%

-25%

6.3%

+ 25%

Capacity Factor

38%

28.5%

-25%

47.5%

+ 25%

Social Cost of Carbon Opportunity Cost of Diesel in Kalimantan Opportunity Cost of Kerosene in Kalimantan Capex

USD/tCO2

60.0

-25%

100

+ 25%

20,250

IDR/liter

15,188

-25%

25,313

+ 25%

18,300

IDR/liter

13,725

-25%

22,875

+ 25%

5.2bn

IDR

3.9bn

-25%

6.5bn

+ 25%

Social Discount Rate

3.8%

-25%

6.3%

+ 25%

Solar Insolation

4.6

Social Cost of Carbon Opportunity Cost of Diesel in Kalimantan Opportunity Cost of Kerosene in Kalimantan Capex (FS)

3.45

-25%

5.8

+ 25%

USD/tCO2

-25%

100

+ 25%

20,250

IDR/liter

15,188

-25%

25,313

+ 25%

18,300

IDR/liter

13,725

-25%

22,875

+ 25%

37.8bn

IDR

28.4bn

-25%

47.3bn

+ 25%

Social Discount Rate

3.8%

-25%

6.3%

+ 25%

Solar Insolation

4.6

kWh/m2/day

3.5

-25%

5.8

+ 25%

USD/tCO2

-25%

100

+ 25%

20,250

IDR/liter

15,188

-25%

25,313

+ 25%

18,300

IDR/liter

13,725

-25%

22,875

+ 25%

5% 80 22.9m

% USD/tCO2 USD

3.8% 60 17.2m

-25% -25% -25%

6.3% 100 28.6m

+ 25% + 25% + 25%

3.8%

-25%

6.3%

+ 25%

Shadow price of diesel

10,750

IDR/liter

8,063

-25%

13,438

+ 25%

Capex

4.11m

USD

3.08m

-25%

5.14m

+25%

Social Cost of Carbon Opportunity Cost of Diesel in Kalimantan Opportunity Cost of Kerosene in Kalimantan Social Discount Rate Social Cost of Carbon Capex Social Discount Rate

Biogas POME

kWh/m2/day

DRAFT FOR DISCUSSION

Micro Hydro (Benchmark)

Micro Hydro (FS)

Figure 19: Variation in financial Net Present Value

Capex Tariff Capacity Factor WACC

Capex Tariff Capacity Factor

Solar PV (FS)

WACC

Capex/kW

Low

Tariff

High

Solar insolation

Biogas POME

Solar PV (Benchmark)

WACC

Tariff Solar insolation WACC

Carbon Price Capex Market price of diesel WACC

Biomass Woodchip

-100%-80%-60%-40%-20% 0% 20% 40% 60% 80% 100% Carbon Price Capex Annual mill operating hour Industrial user tariff Feed-in Tariff WACC -300%

Low High

-200%

-100%

Note: Biomass (woodchip) axis has a different scale

100%

200%

300%

DRAFT FOR DISCUSSION Figure 20: Variation in Extended Net Present Value

Micro Hydro (FS)

Capex Opportunity Cost of Kerosene in Kalimantan Opportunity Cost of Diesel in Kalimantan Social Cost of Carbon Capacity Factor Social Discount Rate

Solar PV (FS)

Opportunity Cost of Kerosene in Kalimantan Opportunity Cost of Diesel in Kalimantan Social Cost of Carbon Solar Insolation Social Discount Rate

Biomass Woodchip

Capex (FS) Opportunity Cost of Kerosene in Kalimantan Opportunity Cost of Diesel in Kalimantan Social Cost of Carbon Solar Insolation Social Discount Rate

Solar PV (Benchmark)

Micro Hydro (Benchmark)

Capex Opportunity Cost of Kerosene in Kalimantan Opportunity Cost of Diesel in Kalimantan Social Cost of Carbon Capacity Factor Social Discount Rate

Low High

Biogas POME

Capex Social Cost of Carbon Social Discount Rate Capex Shadow price of diesel Social Discount Rate -100%

-60%

-20%

20%

60%

100%

There are three findings in particular that stand out in the above results: ď&#x201A;ˇ

The four technologies have relatively robust and broad business cases based on the assumptions made, with the exception of woodchip biomass. The NPV of this project could quickly become negative with only minor changes to the input parameters.

ď&#x201A;ˇ

The business case of POME is also notably reliant on one parameter being accurate; the market price of diesel. Since this varies significantly based on location-specific factors such as infrastructure, which determines transport costs and the presence of black markets in fuel, this implies there is a large uncertainty band around both the 72

DRAFT FOR DISCUSSION viability of this project, and the scaled-up results of the benefits of POME to Kalimantan as a corridor. ď&#x201A;ˇ

The extended CBA cases are substantially more robust, with the exception of a large change in diesel generator thermal efficiency (which does not vary much in practice) and the capex for Solar PV in particular (which as discussed was not in line with international benchmarks in the first place). However, it was not possible to test the sensitivity of all projects to all input variables so caution should still be applied to the general conclusion that these projects always justify public policy support.

DRAFT FOR DISCUSSION

6 Policy implications In this section we consider the implications of the CBA results and findings for policymakers: how to ensure that the external benefits are fully realized through investment and the right enabling environment. Introduction The results and findings of the eCBA show that the installation of additional renewable energy capacity across Kalimantan would bring wider social, economic and environmental costs and benefits compared to a Business As Usual scenario. Yet, across all four provinces in Kalimantan, there is only one major, on-grid renewables project under construction78, and key micro-hydro programs have focused on other provinces such as Sumatera and Sulawesi. Across Indonesia progress is visible, but ultimately only 12% of power is currently generated from renewable sources. And while the government has clear targets, for example to consume 17% of energy79 from renewable sources by 2025, recent announcements in the electricity sector largely relate to fossil fuel programs80. This raises the question “why is the deployment of green technologies happening so slowly in the energy sector?” It is important to provide context to this question and give credit to a number of reforms passed and incentives provided by Government of Indonesia in recent years including: 

The reduction of subsidies on various refined fuels including diesel



The establishment of a range of Feed In Tariffs for individual technologies and provincespecific cost multipliers (recently updated for 201481)



The removal of PLN’s monopoly on power generation; and, the obligation as the grid operator to purchase all power produced from installations below 10MW at the FiTs mentioned



Delegation of regional autonomy for rural electrification and permission for regional government to act as off-takers for IPPs under IUPTL license



Various investment tax incentives including the Investment Tax Credit, Accelerated Depreciation, and Tax Carry Forward of up to 10 years



Specific de-risking measures for individual technologies, most notably the funding of exploration costs for geothermal through the Geothermal Revolving Fund



The implementation of the 2012 Land Acquisition Law in 2014, which accelerates legal proceedings for infrastructure projects.



Financial facilities for IPPs under Public Private Partnership (PPP) programs including sovereign guarantees (IIGF82), the Viability Gap Fund83 where projects are economically feasible but financially unviable, Business Viability Guarantees to cover PLN obligations,

Palm Shells Biomass (6MW), Sanggau, West Kalimantan. Source: Appendix H, “Power in Indonesia: PwC Investment and Taxation Guide” 79 Note this should not be directly compared to the previous electricity statistic as it includes all non-electricity forms of energy, e.g. transport fuels. 80 For example: 5,000 MW coal fired plant in Central Java announced November 2014 81 Permen ESDM 27/2014, 82 PT Penjaminan Infrastruktur Indonesia 83 Ministry of Finance Regulation No. 223/2012

DRAFT FOR DISCUSSION and the Infrastructure Financing Fund84 to bridge funding gaps and develop long-term Rupiah debt instruments. These represent tangible progress towards a functioning and well-financed green energy sector in Indonesia. And further proposals currently under consideration, such as the mooted tying of electricity prices to the exchange rate, fuel price and inflation, are welcome. However, further challenges remain. The Financial Analysis and eCBA highlight some of the financial and investment challenges, as well as macroeconomic and market barriers such as fossil fuel or electricity subsidies. Appropriate economic incentives will need to be provided to address these including: 

Higher feed-in tariffs or CO2 incentives for larger on-grid projects



Capital grants or subsidized loans for off-grid projects



Re-pricing fossil fuels and electricity tariffs to account for the true cost of production, environmental externalities, and price volatility

Furthermore, wider literature and stakeholder consultation has suggested that there are wider operational and regulatory issues that also need to be addressed through institutional and legal reform as well as the provision of a solid enabling environment. These policies might include: 

Enhancing technical capacity; improving engineering skills, resource data and standardized processes and guidelines for sub-national government



Integrated, Kalimantan-wide resource planning



Relaxing foreign ownership restrictions below 10MW (restrictions were enacted in May 2014)



Faster land acquisition, and clearer electrification commitments by PLN

It is important to note that there are no ‘blanket’ policy prescriptions for renewables. Barriers to implementation vary by technology, geography, and especially with the form of generation and transmission (i.e., small-scale, mini-grid power vs. large-scale, on-grid power). The recommendations are specific to the four examples chosen for this study. However, it is likely that implementing these recommendations would significantly bolster the business case for a range of other renewables technologies across Indonesia. These would be catalyzed by broader reforms to the business environment including the elimination of overlap between regulations, clearer roles and jurisdictions for government agencies, streamlined permitting processes, more predictable tax collection. And, above this, a firm political commitment by the new President to renewable energy supported by an openness to foreign finance and participation in the sector.

PT Sarana Multi Infrastruktur and its partly-owned subsidiary PT Indonesia Infrastruktur Financing

DRAFT FOR DISCUSSION Financial and Economic Policies Each of the four technologies faces its own challenges with respect to financial viability. Off-grid, rural electrification projects largely rely on capital grants, whereas the business cases for gridconnected projects rely on user tariffs to reflect the full cost of power. Off-grid projects Generating power from micro-hydro is unlikely to be financially viable under most reasonable operating parameters. This is also true – indeed, even more so – for Solar PV. But, taking into account the broader socio-economic benefits, there is a similarly strong economic case for such investments if implemented efficiently. Indeed, the benefit to communities of reduced diesel fuel consumption costs justifies the investment by itself. How, therefore, can policy internalize the green growth benefits to drive investment? A common objective in renewables policy and financing is to seek private investment through the careful leveraging of public funds. This could come from domestic or international commercial banks, equity investors (including utilities), rural entrepreneurs supported by seed capital funds, or other environmental finance sources (carbon finance, green bonds). The Viability Gap Fund is an example of such a policy in the PPP context in Indonesia. However, the practical realities do not favor significant deployment of private capital. Transaction costs are high, demand is uncertain, and project-specific technology risk is common. Crucially, there is a principle for such projects, recognized in international literature85, that tariffs must be set at a level that is affordable for the whole village. Project sustainability dictates that this tariff at least covers O&M and lifecycle costs, but it is not likely to entail full cost recovery (i.e., repayment of principal and interest too): such payments would be socially unacceptable. A standard revenue-augmenting policy to get over this hurdle, such as a FiT or a CO2 incentive, is not practical in the mini-grid context. And although reforming fossil fuel subsidies on diesel would improve the relative business case of renewables compared to gensets, diesel is already more expensive per kWh and this does not fundamentally increase the profitability of renewables investment. What is needed is substantial capital grants from public or semi-public sources (semi-public being State Owned Enterprises or international donors). If government covers 70-90% of capital costs, the affordable tariff levels should be sufficient to cover regular O&M as well as infrequent larger equipment failures. This is broadly recognized already; a handful of micro-hydro schemes already exist. For example:  GoI and GIZ are sponsoring the Energising Development MHP program, and aimed to have installed 240 MHP systems across Sulawesi and Sumatera by end-2013  The National Rural Community Empowerment Program (‘Rural PNPM’) constructed 477 MHP systems across Indonesia between 2004 and 2011 spending IDR 116 billion  The Environmental National Rural Community Empowerment Program (‘Green PNPM’) aimed to build 79 MHP systems by end-2013 with a budget of IDR 51.4 billion.  UNDP sponsored an Integrated MH Development and Application Program from 20072010 with a budget of USD 3 million. Solar PV schemes at this scale are less prominent and the focus is on Solar Home Systems.

See e.g. World Bank (2008) REToolkit: A Resource for Renewable Energy Development

DRAFT FOR DISCUSSION These budgets total around USD 16 million, and although further funding has been promised to, for example, the Green PNPM program, there is likely to be significant funding shortfall relative to potential. Taking the approximate investment need identified in Chapter 5, (see Table 9) as an example, investment in the order of USD 6-39bn would be required for Solar PV and USD 100 – 450 million for MHP. Non-FiT budget allocation would have to be found to support this investment. Money recently released by expected fossil fuel reforms in late 2014, around IDR 200 trillion of which has already been earmarked for infrastructure, may help in this respect. With the adequate provision of capital, probably the more pressing issue for rural electrification schemes is providing operational and institutional support. Indeed, this is what two project evaluations of existing Micro Hydro programs have found86. The Private Power Utility (PPU) project, which produces electricity from POME for its own use, appears financially viable under the base case assumption and with a hurdle rate of less than 16%. This was not true at the time of project registration for the CDM and almost entirely reflects changes in the Indonesian retail price of diesel. This is true even though carbon finance has dried up, with CER carbon prices in late 2014 measured in double-digit cents per tonne of CO2 (as compared to double-digit Euro figures several years ago). However, these findings are reliant on a high industrial diesel price of around IDR 16,000/liter reflecting in large part the substantial transport costs and fuel scarcity in remote areas of Kalimantan. Lower transport costs or (potentially illegal) access to subsidized fuel would render the project financially unviable. In this case, ‘top-up financing’, where public capital leverages a much larger private sector contribution could be useful. Access to low-cost finance is likely to be important (as well as operational support; see later). In principle top-up financing could be achieved through any policy that raises the attractiveness of Green Growth relative to Business As Usual; whether it be a per liter fuel tax, CO2 incentive per tonne, tax credits per kWh, or reduced hurdle rates through subsidized finance. In practice financing faces challenges, however several programs are starting out and attempting to overcome these challenges. The provision of credit lines by donors to support domestic banks in building mid-size renewable portfolios (1-10 MW projects) is a particularly good model. For example, Agence Francaise de Developpement (AFD) has extended a credit line to Bank Mandiri for this purpose87. Another model is provided by the Global Environmental Facility, which has extended incremental financing to POME projects in Malaysia to cover capital costs and make them commercially viable88. This obviously applies in the case where the power generation equipment has not yet been built, so the Green Growth and Business As Usual costs are only incrementally different, and BAU is not a sunk cost. For a more detailed study of the challenges see: NAMA concept note - small and medium scale renewables by Cameron (2014) and the Assessment of Independent power producers in Indonesia by Hayton and Nugraha (2013). On-grid project

Millennium Challenge Corporation (2012) Ex Ante Economic Analysis for Micro Hydro Electric Systems in Remote Communities in Indonesia (unpublished), World Bank (2012) Micro Hydro Power (MHP) Return of Investment and Cost Effectiveness Analysis 87 http://www.afd.fr/lang/en/home/pays/asie/geo-asie/indonesie 88 http://www.undp.org/content/dam/malaysia/docs/EnE/EnEProDocs/Biomass%20Power%20Generation%20and%20Cogeneration%20in%20the%20Palm%20Oil%20Mills%20Prodoc.pdf

DRAFT FOR DISCUSSION Generating power from woodchip biomass just covers the cost of capital at 10%89 with current operational parameters. But, sensitivity analysis demonstrates that small changes to the assumptions could affect NPV markedly. And given estimated generation costs from another woodchip biomass project in Sumba are 20-50% higher than the Korindo project90 (suggesting that costs may already be underestimated) overall the financial case is marginal. Selling more power on-grid at current Feed-In Tariff (FiT) levels would help, which in turn would require a larger boiler or reduced consumption in chipping operations. Assuming the latter is not possible, increasing the boiler size by more than 2-3 MW would require changes in current regulation: the 10MW limit for guaranteed offtake by PLN significantly increases the risk profile of an investment after this point. In addition, raising the industrial power consumption tariff would help. If it costs 10c/kWh to generate, but savings on avoided costs are only 8c/kWh then the project financials will inevitably rely on high Feed In Tariffs. Is this low tariff for the end user justifiable? The eCBA analysis says that 6-7c/kWh is far ‘too low’ a price for power in this area: 

The true economic cost of generation in Central/South Kalimantan is nearly 26c/kWh based on sales from the 39MW Sistem Pangkalen Bun plant nearby, and closer to 21c/kWh if transmission grid consolidation across South and Central Kalimantan is achieved (i.e., the weighted average across the generation fuel portfolio)91.



Further, the true environmental cost of coal and diesel consumption is equal to another 1c/kWh in terms of local air pollution and 6-7c/kWh in terms of global GHG emissions.

And, this excludes the fact that fossil fuel prices are more volatile than operational costs for renewable projects. This volatility is a real cost, as reflected for example in the willingness of firms to expensively hedge fuel costs through the use of long-term contracts and financial derivatives. Allowing PLN to pass on these generation costs rather than having them absorbed by the Ministry of Finance (at a total cost of 0.35% of GDP in 2013; see page 28) would significantly change incentives at the project level. And, environmental charges on fossil generation would force polluters to pay for the hidden costs of fossil fuel combustion, and compensate for the failure in the international carbon markets (recall that Korindo is already a UNFCCC CDMregistered project, and should be receiving a carbon incentive already; however, presumably due to a historically depressed CER price of EUR 0.16/tCO2, no carbon credits have been issued to date). The savings to the public purse could yield a double dividend if recycled in the form of lowcost finance (through guarantees of domestic bank debt) for such projects, making marginal projects commercially viable. There would also be a strong positive investor confidence effort from tariff reform; the current discrepancy between relatively high FiT levels and low end-user tariffs leaves many pondering whether the FiT levels are sustainable and therefore hinders uptake. 89

This is a common assumption for hurdle rates in the absence of specific project/technology assumptions. See, for example, Millennium Challenge Account Indonesia http://www.mcc.gov/documents/data/ME_Plan_-_IDN_-_V1__Aug13.pdf, or http://www.climateadvisers.com/wp-content/uploads/2014/02/2014-01-Measuring-Green-Prosperity-inIndonesia.pdf 90 http://blogs.terrapinn.com/total-electricity/2012/10/19/joint-international-venture-pln-ge-biomass-power-plant-builtindonesia/ 91

See Table 3 for the PLN data behind this calculation

DRAFT FOR DISCUSSION

DRAFT FOR DISCUSSION Operational and enabling policies Operational or practical barriers are a significant problem for some technologies; especially for rural mini-grids. Off-grid projects There are substantial practical challenges around technical planning for rural mini-grids, especially for micro-hydro. Poorly sited hydro projects (i.e. with insufficient head depth or water flow speed) or designs with inappropriate capacity, which lead to high per-unit costs or suboptimal connection wattages are not uncommon. One evaluation of 47 MHP sites found an average of 8% difference between installed and designed capacity. A subset of this group had an average capacity factor of only 11.2%. For example, it is hard to see how a population of 400-500 justifies a capacity of 130 kW at Tumbang Kunyi, given connections are likely to be limited to 100-200W per household92. Given changes in capacity factor have been demonstrated (by project evaluations) to have a significant impact on capital costs93 and therefore the number of projects that a fixed government budget can support, this is a serious issue. Practical challenges abound in the operational phase, too. A combination of a lack of skilled engineers, a lack of spare parts, and a failure by staff to follow appropriate maintenance routines means that equipment failure rates are high and lifetimes shorter than necessary94. This can be exacerbated in the case of higher-tech systems, which while nominally more efficient, are dependent on skills from major urban areas. Failures in these systems can therefore lead to power outages for weeks or even months. Another noted issue in project success was poor book-keeping and record keeping leading to under-billing. Government representatives in Central Kalimantan spoken to as part of this project did not dispute these suggestions. Indeed, they also highlighted the poor quality of technical proposals, inappropriate siting decisions and equipment failure rates. Together, these issues fatally undermine project economics by raising capital costs per kWh, and undermining social support and therefore collection rates. There is already evidence of this in Central Kalimantan; communities in Murung Raya cited examples of failed MHP projects as a reason for preferring Solar PV, despite their much higher capital costs. The required policy intervention to issues both in the construction and post-construction phase is heavy investment in training, capacity building and strong community participation. One of the leading MHP installers, IBEKA, claims that their higher rates of success are due to spending 70% of their time in community preparation and stakeholder outreach, compared to 30% in the construction and technical phases. Communities empowered to perform necessary maintenance and run business operations are independent communities - and thus the projects are sustainable. They could be supported by local banks â&#x20AC;&#x201C; if risk aversion were overcome and portfolios of small projects built up (see page 75). It is also important for national or regional government (and donor partners) to continue investing to equip trained engineers with specific MHP skills. Training the trainers and ensuring rigorous qualification standards for feasibility studies and site selection is crucial. It was suggested by local government that ESDM or another credible, independent institution produces clear, consistent guidelines for feasibility studies and certifies consultants to implement them. 92

400 households * 220W = 88kW or a 68% peak load. World Bank (2012) Micro Hydro Power (MHP) Return of Investment and Cost Effectiveness Analysis 94 Ibid. 93

DRAFT FOR DISCUSSION Larger industrial projects such as POME also face practical issues with fragile equipment and regular maintenance requirements. For example, heavy rainfall is prone to disrupting biogas installations and causing methane leakage95. Again, proper training and project technical design is crucial to ensuring project success. It is also noted that in practice, palm oil biomass is often used for power generation rather than diesel, and in these cases, the economic and environmental benefits of POME will be significantly reduced (or even eliminated). On-grid project A major barrier to investors locating promising generation opportunities is the paucity of data on natural resources. Although province-specific estimates for biomass generation exist96, they are 10 years old, not disaggregated by the type of biomass, and need to be linked to individual sites or agricultural operations. Good data exists in places where individual studies have been commissioned (e.g. biomass potential is known with some accuracy in Central Kalimantan97), but more systematic mapping is needed to set credible and realistic energy targets. Although this is not as important as, for example, for geothermal where exploration costs to obtain reliable data are high, the more efficient the site selection process the lower the overall capital costs and risk. Uncertainty over resource quantities and location is compounded by uncertainty of the security of supply. This will be increasingly important if demand for biomass ramps up nationally; lack of resource supply may choke the sector before it has emerged at scale. However, measures exist to mitigate this risk. Spreading investment across different feedstocks such as coconut, risk husk, palm oil waste as well as timber value chain waste will help diversify supply risk. Reducing counterparty risk helps too; if the same company that generates the waste owns the generation asset, this makes it significantly less likely that supply will unexpectedly dry up (or be sold to a rival bidder). This is especially important where long-term contracts are difficult to enforce. The Korindo project is a good example of co-located production; both biomass generation and combustion take place in the same company and so feedstock availability risk is minimised. Physical access to the grid in remote locations is often cited as a reason for under-investment. However, this is an opportunity for distributed generation as much as it is a â&#x20AC;&#x153;problemâ&#x20AC;? for the conventional model of centralized generation with extensive transmission infrastructure.

http://www.rcminternationalllc.com/RCM_Forms/RCM_Digester_Types.pdf

National Electricity Plan (RUKN) 2004 Energy and Environmental Partnership with Indonesia (2012) Baseline Study in Riau and Central Kalimantan

DRAFT FOR DISCUSSION Legal and regulatory policies Off-grid projects As discussed above, IPPs can only operate in areas outside PLN’s planned scope of electrification or with its consent. In the short-term, it would be advantageous if PLN were to provide firmer and clearer commitments to electrification; not necessarily expanding the pace of electrification but making it unambiguous which areas will and won’t be electrified in the next 10 years. This is important because where mini-grids are constructed and PLN subsequently electrifies the area, say 5 years later, the asset is effectively stranded as demand migrates. In some cases, it might be possible to sell onto the grid, to compensate for power losses at the edge-of-grid in remote areas. But, the regulatory system is generally geared towards selling larger quantities of power than micro-hydro can generate98. Not only does negotiating with PLN require commercial experience beyond the capacity of rural communities, but also standardized PPAs for these types of projects are not available. Designing standard templates for small-scale power sales would help overcome this barrier. In other cases, it will not be possible to sell, and therefore construction should not have happened at that location in the first place. Certain predictive indicators are available (such as the highway plans, which PLN transmission lines often follow), but better advance planning in terms of PLN prioritizing available electrification budgets to clearly specified locations, and better coordination between local PLN staff and local government, would be more straightforward. Consideration also needs to be given to land acquisition in remote areas. Government representatives lamented the difficulty of this for small projects during our stakeholder workshop. For areas above one hectare located in certain land classifications, senior approval (Governor, Minister) is required to build. The land conversion process is burdensome and adds significantly to project transaction costs, where in one example the feasibility study alone swallowed 10% of the community’s infrastructure budget for the year. Government was, however, of the view that the situation would imminently improve with historical and ongoing reforms. Lastly, local government has been criticized for not running transparent tender processes (poorly worded tenders or post-announcement amendments)99. Further capacity building as well as review by other regulatory agencies may be required in some cases. As mentioned in the previous section, standardized guidelines and templates would be helpful. On-grid project Selling power onto the grid in Indonesia has been made significantly easier since the 2009 reforms (See Section 2 and Introduction to this Section). PLN now has an obligation to purchase power produced by installations sized between 1 and 10MW. However, PLN still holds a monopoly in transmission, distribution and is the functioning systems operator. It has the “right of first refusal” and IPPs can only operate in areas outside PLN’s planned scope of electrification or with its consent. Increasing levels of competition in the market and increasing IPP investment incentives would likely support electrification and renewables targets. Since this would need to be carefully planned and due consideration given to subsidy reform and universal access obligations at the 98

Millennium Challenge Corporation (2012) Ex Ante Economic Analysis for Micro Hydro Electric Systems in Remote Communities in Indonesia (unpublished) 99 US Department of Commerce (2010) Renewable Energy Market Assessment Report: Indonesia

DRAFT FOR DISCUSSION same time, further unbundling of the electricity market is not currently on the cards. At the same time, it is unclear how much further the market can be liberalized within the confines of the Constitution of Indonesia given the striking down of the ambitious Electricity Law 20/2002 in December 2004. However, opening up the transmission system, for example, would be on option to increased competition in the sector (if legally possible). There are also other regulatory changes that could be made to support investors. The April 2014 changes to the Negative Investment List that restricted foreign participation in projects smaller than 10MW have been a blow. PLNâ&#x20AC;&#x2122;s bid round for solar earlier in the year had attracted foreign bidders, but the involvement of foreign investors (from a direct equity perspective) is now prevented100. Market commentators have suggested that mini-hydro investors as a result will struggle, especially as they were already finding it hard to access domestic finance101. Although investors are welcome to hold majority stakes in larger and PPP projects, it is clear that depriving the market of expertise and capital will slow project development in the short-term. Furthermore, simple practical measures like standardized PPAs (containing legally mandated FiTs as standard) would help to streamline negotiations with PLN.

100

PricewaterhouseCoopers Tax Flash #51, May 2014

101

Ibid.

DRAFT FOR DISCUSSION Table 13: Summary of key policy suggestions Off-grid rural minigrid

Macroeconomic and market policies

Potential barrier to investment

Low financial viability

Potential Policy Intervention

On-grid PPU

Off-grid PPU

Outcome MHP

Solar

Biomass: Woodchip

Biogas: POME

Feed In Tariffs

Higher revenues and better financial viability

  

CO2 Incentive

Higher revenues and better financial viability

  

Reform diesel and electricity subsidies

Stronger incentive to electrify / switch to clean technology

Low-cost funding

Lower capital costs and better financial viability

  

Capital Grants

Lower capital costs and better financial viability

  

   

Financial investment c policies

Low financial viability

Debt guarantee for domestic lenders

Lower hurdle rates and higher financial viability

Relax foreign ownership limits < 10MW

Risktolerating investors

Mandatory inclusion of fossil fuel hedging costs in calculating costs of generation

Higher costs for fuels with volatile prices

Access to capital; unwillingness to lend to emerging technologies

Stability of costs not recognized in appraisals

        

Operational and enabling policies

DRAFT FOR DISCUSSION

Availability of feedstock and immature supply chains for biomass

Transport infrastructure and standardized fuel specifications

Available, reliable biomass fuel

Failure to maintain equipment; availability of spare parts and engineers

Capacity building including train-thetrainers approach

Skilled, local, technicians maintain projects

     

Welldesigned and maintained projects

  

Lack of technical expertise including design failures at feasibility stage, lack of data on costs, bookkeeping abilities in operational phase

High transaction costs

Greater involvement of foreign technical expertise Domestic banks commit to renewables portfolios and build financing/sector expertise under government guarantee Programmatic approach and standardization of tender process

Reduced transaction costs

   

Government investment in basic research Poor quality data on physical resource levels

Sufficiently diverse fuel supply in Sufficiently diverse fuel supply in Energy

Less cost and risk during project development phase

  

Legal and regulatory policies

Development plans (RUEDs)

102

Low physical access to grid

Distributed generation (minigrid, home systems)

No need for grid access

  

PLN monopoly on transmission/distribution, and functioning systems operator

Consideration of areas for more competition (e.g. transmission)

Increased competition for power generated

  

Foreign ownership limits <10MW limit market participation102

Reverse foreign ownership limits

Involvement of foreign expertise and equity

Note: excludes PPP projects

  

DRAFT FOR DISCUSSION

Capacity of local government to run systematic and transparent tendering process

Standardized tender process with guidelines and template made available by national government or independent organization

Increased investor confidence Reduced processing time for government

  

Use of predictive indicators Lack of transparency in grid expansion plans; leads to potentially stranded assets if community subsequently electrified

Diverse Power Purchase Agreements (PPAs)

Clearer earmarking of PLN electrification budget to certain areas and better coordination between local PLN staff and local government

Avoiding stranded assets and reduced risk for investments

  

Standardized PPA terms for all project types

Reduced transaction costs

  



Rarely relevant



Sometimes/often relevant



Frequently relevant

DRAFT FOR DISCUSSION

Appendix A Model Architecture Below, we have provided an overview of the structure of the eCBA model accompanying this report. Figure 21: Architecture of eCBA model Crucial valuation and biophysical assumptions Most important and uncertain assumptions

Output calculations

Outcome calculations

Cash flow and discounting calculations

Dashboard

Quantifying number of units (m3, kWh, people etc.)

Monetising value of outputs ($)

Allocating costs and benefits over time and expressing in NPV

Other assumptions and data inputs

CBA>>>

Summary of Results

NPV, ERR, CBR ratios Split across time and 5 dimensions Dashboard

Supporting data and assumptions

Output data (nonmonetary)

Key: Step

Outcome data (monetary)

Explanation

Assumptions and Values

MS Excel tab name

DRAFT FOR DISCUSSION

Appendix B Stakeholder comments On 20 November 2014 the GGGI project team attended a 1-day workshop in Palangkaraya, Central Kalimantan. This workshop was hosted by Bappeda and one of the objectives included the validation of draft assumptions and results included in a previous version of this report. To provide the reader with a history of key changes made to the analysis in response to stakeholder feedback we have included in Table 14 below the main technical comments made during this workshop, and how each has been addressed in the final version of this report. Table 14: Stakeholder comments

Stakeholder comment Action taken General Comments Current issues on land acquisition for Noted renewables. For <1ha, Bupati can make and approve the purchase. For >1ha and located in Production Forest (Hutan Produksi), approval from Governor/Minister is needed. No one is likely to go through the forest conversion process for 1ha of land. Technical steps are not standardized and can be Noted onerous for small projects (e.g. AMDAL). There is a trade-off between a robust process to optimize public funds’ allocation and an onerous process which deters investment. Stakeholders suggest that some independent Noted organization or perhaps ESDM should be creating and disseminating nationally standardized guidelines for technical studies (Feasibility, financial analysis, CBA etc.) and certifying consultants. Stakeholders believe that existing/historical Noted reforms will mean the current licensing issues will be “much better in future” Note that villages in MR have some preference Noted with a focus on getting the design for Solar PV due to examples of failed MHP correct projects (badly designed or wrong location) and the perceived attractiveness of Solar PV from public sources. Also annual flooding can damage/render useless MHP plants in Northern Central Kalimantan Note that there are other interesting sources of Biomass (woodchip) and biogas (POME) are renewable energy including livestock methane included in the analysis in the report capture, wind and other biogas (POME) Comments on Micro Hydro project in Tumbang Kunyi Village Stakeholder commented that water flow on the Noted river of chosen micro hydro project is unknown so risk averse community prefers solar PV 88

DRAFT FOR DISCUSSION Fuel shortages drive up prices and availability is often more of an inconvenience than price

In Murung Raya, diesel price (before subsidy reform on 18 November 2014) can be 15,00020,000 IDR/liter

In Murung Raya, kerosene price (before subsidy reform in 18th of November 2014) ranges between 12,000 and 14,000 IDR/liter Villages, including Tumbang Kunyi Village, are allocated 1bn IDR for roads, bridges (priority) and electricity. Feasibility study was commissioned for 100m (10%) and community is expecting results soon Villagers are (perhaps surprisingly) highly demanding of their power connections and often want more than typical city connection of 450-700W

We believe that the high price of fuel in rural Central Kalimantan reflects scarcity as well as transport costs so this point is already well captured within the quantitative analysis The previous assumption of diesel price â&#x20AC;&#x201C; in both micro hydro and solar PV model- is now changed based on this input, the price use in the model now is 15,000 IDR/liter + 2,000 IDR (increased price after subsidy reform) = 17,000 IDR/liter The diesel price used in the Solar PV and MHP calculation is 12,000 IDR/liter + 2,000 IDR (price increase from the subsidy reform) = 14,000 IDR/liter Noted

Noted in the narrative of the report, and the caveats to the corridor-wide results.

DRAFT FOR DISCUSSION

Appendix C Discounted Cost Benefit Analysis Renewable Energy Project - Micro Hydro NPV @ 10.0% p.a.

2014

2015

2016

2017

2018

2019

2020

2021

2022

Year 3

Year 4

Year 5

Year 6

Year 7

Year 8

Year 9

TITLE: Renewable Energy Project - Micro Hydro Year 1

Year 2

CAPITAL COSTS : Capital Investment

425,880

Cost of Repairs

16,380

16,380 $

Scrap Value A. Total Capital Costs (Annual)

425,880 $

B. Total Capital Costs (Cumulative)

425,880 $

6,388 $

425,880 $

442,260 $

6,388

7,639

442,260

OPERATION AND MAINTENANCE COSTS : Operational cost Maintenance cost C. Total Operational Costs (Annual)

D. Total Operational Costs (Cumulative) $

6,388

7,639 $

7,639

14,027 $

14,027

14,027 $

28,054 $

42,081 $

56,107 $

70,134 $

84,161 $

98,188 $

112,215

E. Total Costs (Annual) (=A+C)

425,880 $

14,027 $

30,407 $

14,027 $

14,027

F. Total Costs (Cumulative) (=E+F)

425,880 $

439,907 $

453,934 $

467,961 $

481,988 $

496,015 $

526,421 $

540,448 $

554,475

28,645

G. Total Benefits (Annual)

28,645 $

H. Total Benefits (Cumulative)

28,645 $

425,880 $

-14,618 $

BENEFITS : Electricity Sales

NET UNDISCOUNTED COST* (=E-G) $ DISCOUNT FACTOR @ 5% p.a.

0.9

28,645

28,645 $

28,645

28,645 $

28,645

57,290 $

85,935 $

114,580 $

143,224 $

171,869 $

200,514 $

229,159

-14,618 $

1,762 $

-14,618 $

-14,618

28,645 $

28,645

0.8

0.7

0.6

NET PRESENT COST* (Annual)

387,164 $

-12,081 $

-10,983 $

-9,984 $

-9,077 $

-8,252 $

904 $

-6,819 $

-6,199

NET PRESENT COST* (Cumulative)

375,083 $

364,100 $

354,116 $

345,039 $

336,788 $

337,692 $

330,873 $

324,673

14,618 $

-1,762 $

14,618 $

14,618

387,164 $

TOTAL NET PRESENT COST* =

290,054

TOTAL NET PRESENT VALUE =

-290,054

-425,880 $

RATE OF RETURN

0.5

0.4

-5.3%

* A minus sign in these rows denotes a Net Present Value rather than a Net Present Cost.

DRAFT FOR DISCUSSION 2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

Year 10

Year 11

Year 12

Year 13

Year 14

Year 15

Year 16

Year 17

Year 18

Year 19

Year 20

Year 21

TOTAL $

16,380

16,380 $

442,260 $

458,640 $

6,388

7,639

458,640 $

6,388 $

458,640 $ 6,388

7,639

7,639 $

14,027 $

126,242 $

140,268 $

154,295 $

168,322 $

182,349 $

196,376 $

210,403 $

224,429 $

238,456 $

252,483 $

14,027 $

30,407 $

14,027 $

568,502 $

582,529 $

596,556 $

626,963 $

640,989 $

655,016 $

669,043 $

683,070 $

697,097 $

711,124 $

28,645

21,294 $

21,294

21,294 $

479,934

458,640 $ 479,934 6,388

6,388 $

127,764

7,639 $

152,773

14,027 $

7,639

14,027 $

280,537

266,510 $ 280,537 14,027 $

35,321 $

760,471

725,150 $ 760,471

28,645 $

28,645

28,645 $

28,645

28,645 $

28,645

28,645 $

572,898

257,804 $

286,449 $

315,094 $

343,739 $

372,383 $

401,028 $

429,673 $

458,318 $

486,963 $

515,608 $

544,253 $ 572,898 $

6,015,424

-14,618 $

1,762 $

-14,618 $

0.4

0.3

0.2

0.1

-5,636 $

-5,124 $

-4,658 $

510 $

-3,849 $

-3,499 $

-3,181 $

-2,892 $

-2,629 $

-2,390 $

-2,173 $

319,037 $

313,914 $

309,256 $

309,766 $

305,917 $

302,417 $

299,236 $

296,344 $

293,715 $

291,325 $

14,618 $

-1,762 $

14,618 $

425,880

6,676 0.1 902 $

289,152 $ 290,054

14,618 $

572,898

-6,676

290,054

DRAFT FOR DISCUSSION

Renewable Energy Project - Solar PV NPV @ 10.0% p.a.

2014

2015

2016

2017

2018

2019

2020

2021

2022

Year 3

Year 4

Year 5

Year 6

Year 7

Year 8

Year 9

TITLE: Renewable Energy Project - Solar PV Year 1

Year 2

CAPITAL COSTS : Capital Investment

3,102,088

A. Total Capital Costs (Annual)

3,102,088 $

B. Total Capital Costs (Cumulative)

3,102,088 $

9,374

3,102,088 $

3,102,088 $ 3,102,088 $

3,102,088 $ 3,102,088 $ 3,102,088

OPERATION AND MAINTENANCE COSTS : Operation and maintenance cost

9,374 $

9,374

9,374 $

9,374

C. Total Operational Costs (Annual)

9,374 $

9,374

D. Total Operational Costs (Cumulative)

9,374 $

18,748 $

28,122 $

37,496 $

46,870 $

56,244 $

65,619 $

74,993

E. Total Costs (Annual) (=A+C)

3,102,088 $

9,374 $

9,374

F. Total Costs (Cumulative) (=E+F)

3,102,088 $

3,111,463 $

3,120,837 $

3,130,211 $

12,546

12,546 $

12,546

G. Total Benefits (Annual)

12,546 $

12,546

H. Total Benefits (Cumulative)

12,546 $

25,093 $

37,639 $

50,186 $

62,732 $

75,279 $

87,825 $

100,372

NET UNDISCOUNTED COST* (=E-G)

3,102,088 $

-3,172 $

-3,172

0.8

0.7

0.6

0.5

-1,970 $

-1,791 $

-1,628 $

-1,480 $

BENEFITS : Electricity Sales

DISCOUNT FACTOR @ 5% p.a.

0.9

NET PRESENT COST* (Annual)

2,820,080 $

-2,622 $

-2,383 $

-2,167 $

NET PRESENT COST* (Cumulative)

2,820,080 $

2,817,459 $

2,815,075 $

2,812,908 $

3,172 $

TOTAL NET PRESENT COST* =

2,795,528

TOTAL NET PRESENT VALUE =

-2,795,528

RATE OF RETURN

3,139,585 $ 3,148,959 $ 12,546

2,810,939 $ 2,809,148 $

3,158,333 $ 3,167,707 $ 3,177,081 $

12,546

0.4 -1,345

2,807,520 $ 2,806,040 $ 2,804,695

n/a $

-3,102,088 $

* A minus sign in these rows denotes a Net Present Value rather than a Net Present Cost.

3,172 $

3,172

DRAFT FOR DISCUSSION 2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

Year 10

Year 11

Year 12

Year 13

Year 14

Year 15

Year 16

Year 17

Year 18

Year 19

Year 20

Year 21

TOTAL $ 3,102,088

$ 3,102,088 $ 3,102,088 $ $

9,374

3,102,088 $ 3,102,088 $ 3,102,088 $ 3,102,088 $ $

9,374

3,102,088 $ 3,102,088 $ 3,102,088 $

$ 3,102,088

3,102,088 $ 3,102,088 $ 3,102,088

9,374 $

9,374

9,374 $

187,481

9,374 $

187,481

84,367 $

93,741 $

103,115 $

112,489 $

121,863 $

131,237 $

140,611 $

149,985 $

159,359 $

168,733 $

178,107 $

9,374 $

12,546 $

12,546

12,546 $

250,929

12,546 $

250,929

112,918 $

125,464 $

138,011 $

150,557 $

163,104 $

175,650 $

188,197 $

200,743 $

213,290 $

225,836 $

238,382 $

-3,172 $

0.4

0.3

0.2

0.1

-1,223 $

-1,112 $

-1,011 $

3,172 $

-759 $

2,801,349 $ 2,800,430 $ 2,799,595 $ 2,798,835 $

3,172 $

-690 $

12,546

-628 $

12,546

9,374 $ 3,289,570

3,270,822 $ 3,280,196 $ 3,289,570

12,546

187,481

12,546 $

$ 2,803,472 $ 2,802,360 $

9,374

12,546

-835 $

12,546

-919 $

3,242,700 $ 3,252,074 $ 3,261,448 $

9,374

12,546

9,374 $

9,374

9,374 $

12,546

9,374

3,205,203 $ 3,214,577 $ 3,223,951 $ 3,233,325 $

$ 3,186,455 $ 3,195,829 $

9,374

-571 $

2,798,145 $ 2,797,517 $ 2,796,946 $

3,172 $

12,546

-519 $

12,546

-472 $

250,929 $ 2,634,753 -3,172 0.1 -429 $ 2,795,528

2,796,428 $ 2,795,956 $ 2,795,528

3,172 $

3,172

DRAFT FOR DISCUSSION

Renewable Energy Project - Biomass Wood Chip NPV @ 10.0% p.a.

2014

2015

TITLE: Renewable Energy Project - Biomass Wood Chip Year 1 Year 2

2016

2017

2018

2019

2020

2021

2022

Year 3

Year 4

Year 5

Year 6

Year 7

Year 8

Year 9

CAPITAL COSTS : Total Capex for start up Capital investment Refurbishment cost (in the 11th year) A. Total Capital Costs (Annual) B. Total Capital Costs (Cumulative) OPERATIONAL COSTS : Total Operating Expense Maintenance cost Chemical cost Emergency diesel generator Labour cost General management, admin, welfare, housing & food cost Insurance cost Corporation Tax C. Total Operational Costs (Annual) D. Total Operational Costs (Cumulative) E. Total Costs (Annual) (=A+C) F. Total Costs (Cumulative) (=E+F) BENEFITS : Carbon credit revenues Avoided electricity consumption Sales of excess electricity G. Total Benefits (Annual) H. Total Benefits (Cumulative) NET UNDISCOUNTED COST* (=E-G) DISCOUNT FACTOR @ 5% p.a. NET PRESENT COST* (Annual) NET PRESENT COST* (Cumulative) TOTAL NET PRESENT COST* = TOTAL NET PRESENT VALUE = RATE OF RETURN

$ $ $ $

$ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $ $

$ * A minus sign in these rows denotes a Net Present

Accounting Costs for Tax Depreciation for initial capex (only for tax calculation) Depreciation for refurbishment (only for tax calculation) Loan Interest Payment Accounting Profit

24,075,586 24,075,586 24,075,586

24,075,586 24,075,586

$ $ $ $

$ $ $ $ $ $ $ $ $ $ $

24,075,586

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $ 408,804 72,226 2,622,215 2,622,215 2,622,215 26,697,801

$ 6,501 $ 1,981,513 $ 4,238,271 $ 6,226,285 $ 6,226,285 24,075,586 $ -3,604,070 0.9 0.8 21,886,897 $ -2,978,570 21,886,897 $ 18,908,326 -2,859,766 2,859,766 12.05% -24,075,586 $ 3,604,070 Value rather than a Net Present Cost.

24,075,586

$ $ $ $

24,075,586

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

24,075,586

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

24,075,586

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

24,075,586

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

24,075,586

$ $ $ $

24,075,586

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

1,203,780 44,826 74,970 817,609

$ $ $ $ $ $ $

408,804 72,226 2,622,215 5,244,430 2,622,215 29,320,016

$ $ $ $ $ $ $

408,804 72,226 2,622,215 7,866,644 2,622,215 31,942,231

$ $ $ $ $ $ $

408,804 72,226 2,622,215 10,488,859 2,622,215 34,564,446

$ $ $ $ $ $ $

408,804 72,226 2,622,215 13,111,074 2,622,215 37,186,660

$ $ $ $ $ $ $

408,804 72,226 2,622,215 15,733,289 2,622,215 39,808,875

$ $ $ $ $ $ $

408,804 72,226 2,622,215 18,355,503 2,622,215 42,431,090

$ $ $ $ $ $ $

408,804 72,226 2,622,215 20,977,718 2,622,215 45,053,305

$ $ $ $ $ $

6,501 1,981,513 4,238,271 6,226,285 12,452,570 -3,604,070 0.8 -2,707,791 16,200,535

$ $ $ $ $ $

6,501 1,981,513 4,238,271 6,226,285 18,678,854 -3,604,070 0.7 -2,461,628 13,738,907

$ $ $ $ $ $

6,501 1,981,513 4,238,271 6,226,285 24,905,139 -3,604,070 0.6 -2,237,844 11,501,063

$ $ $ $ $ $

6,501 1,981,513 4,238,271 6,226,285 31,131,424 -3,604,070 0.6 -2,034,404 9,466,659

$ $ $ $ $ $

6,501 1,981,513 4,238,271 6,226,285 37,357,709 -3,604,070 0.5 -1,849,458 7,617,202

$ $ $ $ $ $

6,501 1,981,513 4,238,271 6,226,285 43,583,994 -3,604,070 0.5 -1,681,325 5,935,876

$ $ $ $ $ $ $ $

6,501 1,981,513 4,238,271 6,226,285 49,810,279 -3,604,070 0.4 -1,528,478 4,407,399

$ $

3,604,070 $

3,604,070

2,416,826 $

2,416,826

$ $ $

$ 3,009,449 $ -1,822,204.61 $

$ 2,808,819 $ -1,621,574.58 $

$ 2,608,189 $ -1,420,944.55 $

$ 2,407,559 $ -1,220,314.52 $

$ 2,206,929 $ -1,019,684.50 $

$ 2,006,299 $ -819,054.47 $

$ 1,805,669 $ -618,424.44 $

1,605,039 -417,794.41

DRAFT FOR DISCUSSION 2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

Year 10

Year 11

Year 12

Year 13

Year 14

Year 15

Year 16

Year 17

Year 18

Year 19

Year 20

Year 21

TOTAL $

$ $ $ $

24,075,586

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

4,735,185 4,735,185 28,810,771

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

28,810,771

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

28,810,771

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

28,810,771

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

28,810,771

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

28,810,771

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

28,810,771

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

28,810,771

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

28,810,771

$ $ $ $

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

28,810,771

$ $ $ $ $ $

24,075,586 4,735,185 28,810,771 557,674,347 -

1,203,780 $ 44,826 $ 74,970 $ 817,609 $

1,203,780 44,826 74,970 817,609

$ $ $ $

24,075,594 896,528 1,499,391 16,352,171

$ $ $ $ $ $ $ $ $ 1,981,513 $ 4,238,271 $ 6,219,784 $ 124,454,188 -2,816,557 $ 0.1 -380,603 $ -2,859,766

8,176,085 1,444,526 7,063,590 59,507,885 587,164,403 88,318,656 1,144,838,750 58,507 39,630,265 84,765,415 124,454,188

$ $ $ $ $ $ $

408,804 72,226 2,622,215 23,599,933 2,622,215 47,675,519

$ $ $ $ $ $ $

408,804 72,226 5,825 2,628,040 26,227,973 7,363,225 55,038,744

$ $ $ $ $ $ $

408,804 72,226 530,225 3,152,440 29,380,413 3,152,440 58,191,184

$ $ $ $ $ $ $

408,804 72,226 580,383 3,202,597 32,583,010 3,202,597 61,393,782

$ $ $ $ $ $ $

408,804 72,226 630,540 3,252,755 35,835,765 3,252,755 64,646,536

$ $ $ $ $ $ $

408,804 72,226 680,698 3,302,912 39,138,678 3,302,912 67,949,449

$ $ $ $ $ $ $

408,804 72,226 730,855 3,353,070 42,491,748 3,353,070 71,302,519

$ $ $ $ $ $ $

408,804 72,226 781,013 3,403,227 45,894,975 3,403,227 74,705,746

$ $ $ $ $ $ $

408,804 72,226 781,013 3,403,227 49,298,203 3,403,227 78,108,974

$ $ $ $ $ $ $

408,804 72,226 781,013 3,403,227 52,701,430 3,403,227 81,512,201

$ $ $ $ $ $ $

408,804 72,226 781,013 3,403,227 56,104,658 3,403,227 84,915,429

$ $ $ $ $ $ $

$ $ $ $ $ $

6,501 1,981,513 4,238,271 6,226,285 56,036,563 -3,604,070 0.4 -1,389,525 3,017,874

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 62,256,347 1,143,441 0.4 400,769 3,418,643

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 68,476,131 -3,067,344 0.3 -977,350 2,441,292

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 74,695,916 -3,017,187 0.3 -873,971 1,567,321

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 80,915,700 -2,967,029 0.3 -781,311 786,009

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 87,135,484 -2,916,872 0.2 -698,276 87,734

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 93,355,268 -2,866,714 0.2 -623,881 -536,147

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 99,575,052 -2,816,557 0.2 -557,241 -1,093,388

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 105,794,836 -2,816,557 0.2 -506,582 -1,599,970

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 112,014,620 -2,816,557 0.2 -460,530 -2,060,500

$ $ $ $ $ $

1,981,513 4,238,271 6,219,784 118,234,404 -2,816,557 0.1 -418,663 -2,479,163

$ $ $ $ $ $

$ $

3,604,070 $

-1,143,441 $

3,067,344 $

3,017,187 $

2,967,029 $

2,916,872 $

2,866,714 $

2,816,557 $

2,370,490 $

$ $ $

$ 1,404,409 $ -170,827.97 $

$ 1,203,778 $ 23,301.26 $

473,518 $ 1,003,150 $ 2,120,900.66 $

473,518 $ 802,520 $ 2,321,530.68 $

473,518 $ 601,890 $ 2,522,160.71 $

473,518 $ 401,260 $ 2,722,790.74 $

473,518 $ 200,630 $ 2,923,420.77 $

473,518 $ $ 3,124,050.80 $

$ $ $ $

473,518 $ $ 3,124,050.80 $

408,804 72,226 781,013 3,403,227 59,507,885 3,403,227 88,318,656

-36,135,532 -2,859,766

2,816,557

24,075,586

473,518 $ $ 3,124,050.80

4,735,185 24,075,586

DRAFT FOR DISCUSSION

Renewable Energy Project - POME NPV @ 10.0% p.a.

2014

2015

TITLE: Renewable Energy Project - Biomass POME Year 1 Year 2

2016

2017

2018

2019

2020

2021

2022

Year 3

Year 4

Year 5

Year 6

Year 7

Year 8

Year 9

CAPITAL COSTS : Total Capex for start up Capital investment Scrap Value A. Total Capital Costs (Annual) B. Total Capital Costs (Cumulative) OPERATIONAL COSTS :

4,407,525

$ $

4,407,525 $ 4,407,525 $

$ 4,407,525 $

4,407,525

$ $

214,413 $ 96,171 $

214,413 96,171

Total Operating Expense Maintenance cost Staff cost Government Fees Corporation Tax C. Total Operational Costs (Annual) D. Total Operational Costs (Cumulative) E. Total Costs (Annual) (=A+C) F. Total Costs (Cumulative) (=E+F) BENEFITS : Carbon credit revenues Avoided diesel consumption G. Total Benefits (Annual) H. Total Benefits (Cumulative) NET UNDISCOUNTED COST* (=E-G) DISCOUNT FACTOR @ 5% p.a. NET PRESENT COST* (Annual) NET PRESENT COST* (Cumulative) TOTAL NET PRESENT COST* = TOTAL NET PRESENT VALUE = RATE OF RETURN

$ $ $ $ $ $ $ $ $ $ $ $ $ $

$ * A minus sign in these rows denotes a Net Present

Accounting Costs for Tax Depreciation for initial capex (only for tax calculation) Accounting Profit

4,407,525 4,407,525

$ $ $ $ $

175,190 485,774 485,774 485,774 4,893,299

$ 7,656 $ 1,223,898 $ 1,231,555 $ 1,231,555 4,407,525 $ -745,781 0.9 0.8 4,006,841 $ -616,348 4,006,841 $ 3,390,493 -1,752,396 1,752,396 16.03% -4,407,525 $ 745,781 Value rather than a Net Present Cost.

$ $

$ $ $ $ $

175,190 485,774 971,547 485,774 5,379,072

$ $ $ $ $

175,190 485,774 1,457,321 485,774 5,864,846

$ $ $ $ $

175,190 485,774 1,943,094 485,774 6,350,619

$ $ $ $ $

175,190 485,774 2,428,868 485,774 6,836,393

$ $ $ $ $

175,190 485,774 2,914,641 485,774 7,322,166

$ $ $ $ $

175,190 485,774 3,400,415 485,774 7,807,940

$ $ $ $ $

175,190 485,774 3,886,188 485,774 8,293,713

$ $ $ $ $

7,656 1,223,898 1,231,555 2,463,109 -745,781 0.8 -560,316 2,830,177

$ $ $ $ $

7,656 1,223,898 1,231,555 3,694,664 -745,781 0.7 -509,378 2,320,798

$ $ $ $ $

7,656 1,223,898 1,231,555 4,926,218 -745,781 0.6 -463,071 1,857,727

$ $ $ $ $

7,656 1,223,898 1,231,555 6,157,773 -745,781 0.6 -420,974 1,436,753

$ $ $ $ $

7,656 1,223,898 1,231,555 7,389,327 -745,781 0.5 -382,704 1,054,050

$ $ $ $ $

7,656 1,223,898 1,231,555 8,620,882 -745,781 0.5 -347,912 706,137

$ $ $ $ $ $ $

7,656 1,223,898 1,231,555 9,852,436 -745,781 0.4 -316,284 389,853

$ $

745,781 $

745,781

220,211 $ 700,759.60 $

220,211 700,759.60

DRAFT FOR DISCUSSION 2023

2024

2025

2026

2027

2028

2029

2030

2031

2032

2033

2034

Year 10

Year 11

Year 12

Year 13

Year 14

Year 15

Year 16

Year 17

Year 18

Year 19

Year 20

Year 21

TOTAL $

$ $

$ 4,407,525 $

$ $ 4,407,525 $

$ $

214,413 $ 96,171 $

$ $ $ $ $

175,190 485,774 4,371,962 485,774 8,779,487

$ $ $ $ $

175,190 485,774 4,857,735 485,774 9,265,260

$ $ $ $ $

173,276 483,859 5,341,594 483,859 9,749,120

$ $ $ $ $

173,276 483,859 5,825,454 483,859 10,232,979

$ $ $ $ $

173,276 483,859 6,309,313 483,859 10,716,839

$ $ $ $ $

173,276 483,859 6,793,173 483,859 11,200,698

$ $ $ $ $

173,276 483,859 7,277,032 483,859 11,684,558

$ $ $ $ $

173,276 483,859 7,760,892 483,859 12,168,417

$ $ $ $ $

173,276 483,859 8,244,751 483,859 12,652,276

$ $ $ $ $

173,276 483,859 8,728,611 483,859 13,136,136

$ $ $ $ $

173,276 483,859 9,212,470 483,859 13,619,995

$ $ $ $ $

7,656 1,223,898 1,231,555 11,083,991 -745,781 0.4 -287,531 102,322

$ $ $ $ $

7,656 1,223,898 1,231,555 12,315,545 -745,781 0.4 -261,392 -159,069

$ $ $ $ $

1,223,898 1,223,898 13,539,444 -740,039 0.3 -235,799 -394,869

$ $ $ $ $

1,223,898 1,223,898 14,763,342 -740,039 0.3 -214,363 -609,231

$ $ $ $ $

1,223,898 1,223,898 15,987,240 -740,039 0.3 -194,875 -804,107

$ $ $ $ $

1,223,898 1,223,898 17,211,139 -740,039 0.2 -177,159 -981,266

$ $ $ $ $

1,223,898 1,223,898 18,435,037 -740,039 0.2 -161,054 -1,142,320

$ $ $ $ $

1,223,898 1,223,898 19,658,935 -740,039 0.2 -146,413 -1,288,733

$ $ $ $ $

1,223,898 1,223,898 20,882,834 -740,039 0.2 -133,102 -1,421,836

$ $ $ $ $

1,223,898 1,223,898 22,106,732 -740,039 0.2 -121,002 -1,542,838

$ $ $ $ $

1,223,898 1,223,898 23,330,630 -740,039 0.1 -110,002 -1,652,840

$ $ $ $ $

$ $

745,781 $

740,039 $

$ $

220,211 $ 700,759.60 $

220,211 $ 693,103.39 $

$ 3,299 $ 3,299 $ 4,410,824 $ $ $ $

4,407,525 3,299 4,410,824 92,561,330 -

214,413 $ 96,171 $ $ 173,276 $ 483,859 $ 9,696,330 $ 487,158 $ 14,107,154 $ $ $ 1,223,898 $ 1,223,898 $ 24,554,529 -736,740 $ 0.1 -99,556 $ -1,752,396

4,288,259 1,923,413 3,484,657 9,696,330 101,907,163 14,107,154 194,468,493 76,562 24,477,967 24,554,529 -10,447,375 -1,752,396

736,740

220,211 $ 693,103.39

4,404,227