l c ocal urrency-denominated tariffs for ......dalberg; elsie mbugua, nandu hirani and anthony ngugi...

Energy Regulatory Commission

LOCAL CURRENCY-DENOMINATED

TARIFFS FOR KENYAN POWER PURCHASE

AGREEMENTS

FEASIBILITY STUDY

JUNE 2018

Feasibility of Local Currency-Denominated Power Purchase Agreements for Kenya

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Table of Contents

Executive summary .................................................................................................................... 8 1. Introduction ..................................................................................................................... 14

The importance of local currency financing in Kenya’s power sector ............................................14

Objectives of the study ...................................................................................................................15

2. What role do independent power producers (IPPs) play in Kenya and how are they being financed today? ....................................................................................................................... 16

Power sector in Kenya and the role of IPPs ....................................................................................16

PPAs and tariff structure for renewables ........................................................................................17

Financing of power projects ............................................................................................................18

Role of IPPs going forward ..............................................................................................................20

3. What are the benefits of a LCY -denominated PPA? ........................................................... 21 Objectives of chapter ......................................................................................................................21

Retrospective analysis of the impact of LCY versus HCY dollar tariffs ............................................21

FERFA analysis .................................................................................................................................32

Wider benefits associated with local currency financing ...............................................................34

Conclusion .......................................................................................................................................36

4. What is the availability of LCY financing and how would LCY-denominated PPAs impact investors? ................................................................................................................................ 37

Objectives of chapter ......................................................................................................................37

Supply of LCY financing across financiers ........................................................................................37

Demand for local currency financing ..............................................................................................50

Conclusion .......................................................................................................................................52

5. How have benchmark countries approached LCY-denominated PPAs? ............................... 53 Methodology ...................................................................................................................................53

Context across benchmarked countries ..........................................................................................55

Lessons learned and implications for Kenya ...................................................................................58

6. How should LCY tariffs be structured and implemented in Kenya? ..................................... 61 Options and recommendations for LCY tariff structure ..................................................................61

Actions to increase LCY financing in Kenya .....................................................................................63

Implementation roadmap ...............................................................................................................68

Annexes................................................................................................................................... 70 Annex 1: Retrospective analysis ......................................................................................................70

Annex 2: FERFA background calculation .........................................................................................74

Annex 3: Market sizing methodology .............................................................................................75

Annex 4: Detailed country benchmarking information ..................................................................76

Annex 5: Interviews conducted for this study ................................................................................91

Annex 6: Sample classroom training schedule ................................................................................93

Annex 7: Assumptions used for tariff indexing ...............................................................................94


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Figures and tables

Figure 1: Sensitivity of cost savings to changes in variables (Percent) ................................................ 9 Figure 2: Estimated LCY financing available for power projects over 2018-2027, KES billion ............10 Figure 3: Tariff structure recommendation by renewable energy technology ...................................12 Figure 4: Current market structure of the power sector in Kenya ......................................................14 Figure 5: Total electricity installed capacity (2016, MW)....................................................................17 Figure 6: PPA negotiations – Inputs and outputs ................................................................................17 Figure 7: Stages of project development, and financing required......................................................18 Figure 8: Comparison of hard currency and local currency financing ................................................21 Figure 9: Total installed capacity by technology (MW) .......................................................................22 Figure 10: Annual purchase of energy from power plants installed post-2002 (GWh) ......................23 Figure 11: Aggregated debt repayments for power projects, KES billion ...........................................25 Figure 12: Increase in financing cost and revenue required to keep IPP returns constant, KES billion .............................................................................................................................................................25 Figure 13: Increased cost per customer per year (KES) ......................................................................27 Figure 14: Hypothetical power plant debt repayments with USD and KES financing .........................28 Figure 15: Costs increase / savings of transition to KES tariffs under different assumptions (KES billions) ................................................................................................................................................30 Figure 16: Sensitivity of cost savings to changes in variables (Percent) .............................................31 Figure 17: Financing cost and revenue required to keep IPP returns constant, KES billion ...............32 Figure 18: Use of base rates to determine gains / losses due to forex changes .................................33 Figure 19: Limitation of FERFA analysis ...............................................................................................33 Figure 20: FERFA values, 2002-2016, KES billions ...............................................................................34 Figure 21: Estimated LCY financing available for power projects over 2018-2027, KES billion ..........38 Figure 22: Historical values of gross loans by sector (KES billions) .....................................................40 Figure 23: Estimation of LCY financing available for power from the banking sector in 2016, KES billion .............................................................................................................................................................41 Figure 24: Estimation of financing available for power projects from 2018 to 2027 (KES billions) ....41 Figure 25: Historical values of assets by investment type (KES billions) .............................................43 Figure 26: Estimation of pension fund assets available to the power sector (KES billions) ...............44 Figure 27: Historical values of assets by investment type (KES billions) .............................................47 Figure 28: Estimation of insurance sector assets available for power projects in 2015 .....................47 Figure 29: Projection of insurance assets available to the power sector, KES billions .......................48 Figure 31: Demand for financing – 2018-2027, KES billion .................................................................51 Figure 32: Transfer of currency risk ....................................................................................................51 Figure 33: Split in costs incurred in LCY versus HCY by technology, and indexing of tariffs ...............62 Figure 34: Credit enhancement options .............................................................................................65 Figure 35: Roadmap to implement LCY tariffs and financing ..............................................................69 Figure 36: Last five years’ analysis, KES billion ....................................................................................70 Figure 37: Last ten years’ analysis, KES billion ....................................................................................71 Figure 38: Breakdown of financing cost increase ...............................................................................71 Figure 39: Increase in financing cost over the three five-year periods...............................................72 Figure 40: Distribution of investment between domestic and foreign investors ...............................86 Table 1: Illustrative IPP transactions (equity and debt) in Kenya (not exhaustive) ............................19 Table 2: USD and KES interest rate differential vs. KES depreciation .................................................24 Table 3: Weighted average price under KES and USD tariffs (KES per kWh) ......................................26 Table 4: Costs increase split by customer segments ...........................................................................27 Table 5: Single project view - Financing terms used ...........................................................................27 Table 6: Assumptions and data sources ..............................................................................................28 Table 7: FERFA per customer per year ................................................................................................34 Table 8: Financing terms from commercial banks in HCY and LCY .....................................................42


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Table 9: Regulatory limits set by the RBA on various asset classes ....................................................44 Table 10: Examples of investments into IPPs in Kenya by DFIs ..........................................................49 Table 11: Selection of benchmark countries .......................................................................................53 Table 12: Key figures on benchmarked countries ...............................................................................55 Table 13: Table on tariffs in each benchmarked country ...................................................................56 Table 14: Tariff structure in the Philippines ........................................................................................59 Table 15: LCY tariff structure options .................................................................................................61 Table 16: Tariff indexing considering the currency of project costs ...................................................62 Table 17: List of power plants, by commission year ...........................................................................72 Table 18: Annual FERFA figures ...........................................................................................................74 Table 19: Top 10 banks by gross loans in 2016 ...................................................................................75 Table 20: Percentage of assets and loans of selected banks in LCY vs. HCY in 2015 ..........................75 Table 21: Key indicators of Indonesia and Kenya (2017) ....................................................................76 Table 22: IPP and Feed-in-tariff introduction ......................................................................................77 Table 23: Current energy market ........................................................................................................77 Table 24: Key indicators of the Philippines and Kenya (2017) ............................................................78 Table 25: IPP and Feed-in-tariff introduction ......................................................................................79 Table 26: Current energy market ........................................................................................................80 Table 27: Key indicators of India and Kenya (2017) ............................................................................81 Table 28: IPPs and Feed-in-tariff introduction ....................................................................................82 Table 29: Current energy market ........................................................................................................83 Table 30: Key indicators of the South Africa and Kenya (2017) ..........................................................84 Table 31: Current energy market ........................................................................................................84 Table 32: South Africa – Key dates and milestones in power tariffs...................................................85 Table 33: Pricing trends .......................................................................................................................88 Table 34: Key indicators of Tanzania and Kenya (2017) ......................................................................88 Table 37: Current energy market ........................................................................................................89 Table 36: List of interviewees ..............................................................................................................91


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Ministry of Energy, Government of Kenya

The Ministry of Energy (MoE) oversees policies to create an enabling environment for efficient operation and growth of the energy sector in Kenya. It sets the strategic direction for the growth of the sector and provides a long-term vision for all sector players. MoE’s vision is to provide affordable, quality energy for all Kenyans; and a mission to facilitate provision of clean, sustainable, affordable, reliable, and secure energy services for national development while protecting the environment.

Energy Regulatory Commission, Kenya

The Energy Regulatory Commissions (ERC) regulates the electrical energy, petroleum and related products, renewable energy and other forms of energy. It protects the interests of consumer, investor and other stakeholder interests. The ERC monitors, ensures implementation of, and the observance of the principles of fair competition in the energy sector, in coordination with other statutory authorities. The ERC provides information and statistics to the MoE as well as collects and maintains energy data. It also prepares indicative national energy plan and performs any other function that is incidental or consequential to its functions under the Energy Act or any other written law.

Kenya Power

Kenya Power owns and operates most of the electricity transmission and distribution system in Kenya and sells electricity to over 6.2 million customers (as at July 2017). The Company’s key mandate is to plan for sufficient electricity generation and transmission capacity to meet demand; to build and maintain the power distribution and transmission network and retailing of electricity to its customers. The Government of Kenya (GoK) has a controlling stake at 50.1% of shareholding in Kenya Power, and it is listed on the Nairobi Securities Exchange.

GuarantCo

GuarantCo is part-of the Private Infrastructure Development Group (PIDG) and provides local currency solutions to local or regional financial institutions and bond investors, to help infrastructure projects raise debt finance. Primarily, this is through guarantees denominated in local currency, although GuarantCo can provide dollar-denominated guarantees in fragile and conflict-affected states and provided the business case supports such financing. GuarantCo is one-of-a-kind – the only local currency guarantee facility in the world targeting infrastructure in frontier markets. GuarantCo is funded by the UK (DFID), Switzerland (SECO), Sweden (Sida), the Netherlands (DGIS through FMO) and Australia (DFAT).

Dalberg Advisors

Dalberg Advisors (“Dalberg”) is part of the Dalberg Group of businesses and is a strategy and policy advisory firm focused on global development. Dalberg was established in 2001 with the mission of bringing the best of private sector strategy to address global development challenges. We do so by combining rigorous analytical capabilities with deep knowledge and networks across emerging and frontier markets. Our clients span the public, private and philanthropic sectors, and we work collaboratively with them to address pressing global problems and generate positive social impact from programs, investments and initiatives. Dalberg brings global perspectives firmly rooted in local realities. We have 21 offices located across the globe, which have completed over 1300 engagements for 500+ clients across more than 90 countries.

Leadwood Energy

Leadwood Energy is a specialist energy advisory company with a focus on renewable energy. The Firm brings together top Kenyan talent to drive results in East Africa's power sector. Leadwood Energy is uniquely positioned to deliver practical solutions and identify specific deal flow for Kenya's power investments due to its deep knowledge that extends from generation to transmission and distribution. The company's primary focus is i) Financial Advisory where they provide value addition services to project developers, financiers and equity investors in the renewable energy sector and ii)


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Project Development where they ensure power projects are well coordinated from the project concept stage, structuring, development and execution.

Acknowledgments

The authors of this report would like to thank the individuals and organizations which have shared their time, experiences and knowledge with us for this report. This report would not have been possible without the generous contributions of the individuals who participated in interviews and shared their knowledge and feedback to improve the report.

This report was written by Marcus Watson, Mudit Sharma, Sandra Kimokoti and Daniel Stokley of Dalberg; Elsie Mbugua, Nandu Hirani and Anthony Ngugi of Leadwood Energy. We would like to specifically thank Eric Mwangi of the MoE; Dr. John Mutua of the ERC; John Ihuthia and Batistar Mwangi of Kenya Power; Janice Kotut and Samuel Chasia of GuarantCo, for their extensive feedback and support during the research and the drafting of the report.


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ACRONYMS

ADB Asian Development Bank AfDB African Development Bank AFD Agence Française de Développement ATI Africa Trade Insurance Agency CAGR Compound Annual Growth Rate CBK Central Bank of Kenya CDC Commonwealth Development Corporation CE Credit Enhancement CMA Capital Markets Authority COD Commercial Operation Date CPI Consumer Price Index DFI Development Financial Institution EAPP East Africa Power Pool ECA Export Credit Agency EKF Eksport Kredit Fonden EPC Engineering, Procurement and Construction ERC Energy Regulatory Commission FERFA Foreign Exchange Rate Fluctuation Adjustment FiT Feed in Tariff FX Foreign Exchange GDP Gross Domestic Product GoK Government of Kenya GW Giga Watt HCY Hard currency ICBC Industrial and Commercial Bank of China IEA International Energy Agency IFC International Finance Corporation IMF International Monetary Fund IPP Independent Power Producer IRA Insurance Regulatory Authority IRR Internal Rate of Return JICA Japan International Cooperation Agency KES Kenyan Shilling KfW Kreditanstalt für Wiederaufbau KPPF Kenya Power Pension Fund KWh KiloWatt Hour LIBOR London Interbank Offered Rate LCPDP Least Cost Power Development Plan LCY Local currency MoE Ministry of Energy MW Megawatt NERSA National Energy Regulator of South Africa NSSF National Social Security Fund O&M Operations & Maintenance OPIC Overseas Private Investment Corporation PCG Partial Credit Guarantee PIDG Private Infrastructure Development Group PRG Partial Risk Guarantee PPA Power Purchase Agreement PV Photovoltaic RBA Retirement Benefits Authority


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RE Renewable Energy REIT Real Estate Investment Trust REIPPPP Renewable Energy IPP Procurement Program SPV Special Purposes Vehicle UK United Kingdom USA United States of America USD United States Dollar VAT Value Added Tax


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EXECUTIVE SUMMARY

OBJECTIVES OF THIS REPORT

This report assesses the feasibility of Kenya transitioning to Power Purchase Agreements (PPAs) denominated in local currency (LCY) by addressing four key questions:

1. What are the benefits of a LCY-denominated PPA?

2. What is the availability of LCY financing and how would LCY-denominated PPAs impact investors?

3. How have benchmark countries approached LCY-denominated PPAs?

4. How should LCY tariffs be structured and implemented in Kenya?

CONTEXT

In Kenya today, the vast majority of financing into the power sector is in hard currency (HCY), primarily in US Dollars (USD)1 reflecting the denomination of the tariffs paid to IPPs. HCY tariffs place the foreign exchange (FX) risk in the hands of Kenya Power, who receives revenues in Kenyan Shillings (KES). This risk is passed on to the Kenyan consumer by way of an FX adjustment (FERFA) on their monthly electricity bills (though the pass-through is never 100% due to a loss factor in the formula).

While HCY regimes are currently the norm across Sub-Saharan Africa, it is important to note that the majority of power in advanced economies is financed in LCY. HCY-denominated PPAs made sense in the past for Kenya. However, the depth and sophistication of the debt capital markets and the growth of the local banking sector has changed significantly since the first independent power producers (IPP) began generating power over twenty years ago. It is now time to re-evaluate the feasibility of a LCY regime, given the developments to date and the expected trajectory in the future.

WHAT ARE THE BENEFITS OF A LCY-DENOMINATED PPA?

The authors of this report find that the economic benefits of LCY-denominated PPAs outweigh the costs and recommend that the Government of Kenya (GoK) should move forward with plans for gradual transition to a hybrid LCY tariff regime.

We applied a retrospective economic analysis, and also considered a forward-looking view. In the retrospective assessment, we compared the relative costs of financing in KES versus USD for all projects commissioned in Kenya in the last 15 years (2002-2016) and considered what the costs or benefits might have been had the tariffs been denominated in KES. Over the period of analysis, the results showed that in nominal terms, if the tariffs had been denominated in KES, they would have been 5.1% higher on average (KES 12.5/kWh vs. KES 11.9/kWh) as the impact of higher interest rates in KES versus USD outweighed the effects of KES depreciation. The increase in tariffs under a KES regime would have resulted in an average increase of KES ~250 per Kenyan household per year. It is worth noting that there would have been significantly less tariff volatility, as the FERFA charge would have been eliminated. In real (inflation-adjusted) terms, the analysis showed a saving of 1.8% in tariffs. The primary reason for savings here are lower KES real interest rates (5.5%) compared to USD real interest rates (7.0%), which is due to the relatively high inflation experienced in Kenya compared to the US over the 15-year period.

Despite the marginal increase with LCY tariffs over the past 15 years in nominal terms, in other macroeconomic environments (with higher KES depreciation, and / or lower LCY interest rates, and / or higher HCY interest rates) this would have been a different story. For example, in the past 4 years (2013-16), the KES has depreciated at an average rate of 4.8% per year against the USD, which is

1 A notable exception is the 310 MW Lake Turkana Wind Power Limited, which is denominated in Euros


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significantly higher than the 10 years prior to that2. Furthermore, Kenya’s public debt has risen sharply in the last few years, from 44% of GDP in 2013 to 53.1% of GDP in 20163, putting greater pressure on the KES. If depreciation of the KES were to sharply increase, a LCY regime would result in a significant cost savings to the Kenyan consumer. USD interest rates are unlikely to remain at the historically low levels they have been in the past 10 years and KES interest rates are also expected to trend downwards. If the differential between USD and KES interest rates continues to reduce, then a LCY regime could result in significant cost savings to the Kenyan consumer in the coming years. We conducted sensitivity analysis to assess the impact of change in one variable, while holding all others as average throughout the period. It showed KES depreciation as having the largest cost savings to consumers in KES financing. This highlights the large risk if KES depreciates in the current system of USD financing and tariffs.

Figure 1: Sensitivity of cost savings to changes in variables (Percent)

In summary, a HCY regime leaves Kenyan consumers, and the economy at large, vulnerable to external shocks and fluctuations in the value of the KES. These risks to consumers would be reduced or eliminated under a LCY tariff structure.

In addition to this, there are other broader economic benefits to support a LCY setting:

• Increase of domestic investor participation / repatriation of returns: A LCY regime would allow for more domestic investor participation (from banks, pension funds and insurance companies), who would in turn benefit from sector returns and a more diversified portfolio.

• Facilitate capital markets development: Increased use of LCY financing would contribute to deepening of the domestic capital markets, strengthening of the banking sector, and improvement of financing terms over time. In turn, this would reduce the need to borrow offshore and contribute to reducing currency mismatches, benefitting the economy at large.

• Promote growth of local developers: Increased LCY financing in the sector would favor local developers, who are on average more open to LCY. International investors typically seek guarantees and letters of credit to protect against risks local developers can more easily absorb.

• Promote domestic manufacturing industry: Borrowing in LCY would incentivize developers to find new ways to source materials and labor locally, helping in industry growth and job creation.

WHAT IS THE AVAILABILITY OF LCY FINANCING AND HOW WOULD LCY PPAS IMPACT INVESTORS?

The authors predict that over the next decade, capital flows in LCY from domestic capital markets will increase significantly. While most industry actors are positive about a shift to LCY, some have

2 Source: Central Bank of Kenya 3 Source: National Treasury, GoK; IMF

Shift to KES regime leading to higher tariffs

Base case

Shift to KES regime leading to lower tariffs

Interest rate KES

16.4% 13.7% 9.4%

Interest rate USD

7.6% 9.1% 12.3%

KES Depreciation

0% 2% 12.1%

-15 -10 -5 0 5 10

Percent

Interest rate KES

Interest rate USD

KES depreciation

ParityBase case

Shift to KES regime leading to higher tariffs

Shift to KES regime leading to lower tariffs


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valid concerns about the change. These concerns will need to be addressed and managed carefully with any transition to a LCY regime.

Today, the majority of financing into the power sector is denominated in HCY (mainly from DFIs and foreign investors), and there has been limited LCY capital invested by the domestic capital markets. Our market sizing analysis estimates the maximum pool of available LCY financing for power projects over the next 10 years (2018 – 2027) to be KES ~4,450 billion:

Figure 2: Estimated LCY financing available for power projects over 2018-2027, KES billion

Although this pool of capital is unlikely to be invested in the power sector alone (due to competition with other sectors e.g. transport and water), it is sufficient on its own to finance the GoK’s ambitious electrification growth targets.

Based on interviews with 40+ stakeholders, there is broad market support for a LCY regime:

• Local commercial banks: are mostly positive. They recognize that switching to LCY tariffs would reduce the currency mismatch and allow them to manage risk appropriately thereby reducing risk aversion from lending in KES. While they have the appetite to participate more, capacity and experience in project finance is limited which creates a high hurdle for any investment – so this needs to be built up.

• Local institutional investors: are positive about a LCY regime, though there are broader factors constraining their participation that must be addressed. In order to diversify their portfolios and assets /liability management, pension fund managers and Life insurers are becoming more open to alternative asset classes and specifically long dated assets such as power project investments. Understanding of the power projects as an asset class is somehow limited among some decision makers (e.g. trustees), and awareness building is required.

• Development Finance Institutions (DFIs): due to their capital markets and banking sector development agenda, most support a LCY regime, even though historically they have been the dominant HCY investor. In general, the sector can expect to see a decrease in concessional HCY capital from DFIs, as they already hold high exposure in the Kenyan power sector. Further, in the future Kenya’s is likely to achieve Lower Middle-Income Country4 status meaning that DFIs will be less able to provide concessional finance to projects in the country.

• Independent Power Producers (IPPs): Local developers are on the whole more open to the prospect of LCY PPAs than foreign developers, however they raise concerns over currency risk and being compensated with fair returns in LCY. Some local developers also consider USD tariffs a key element in attracting investors to Kenya, and believe that it may be harder to raise capital with LCY tariffs. However, this perception can be changed over time as the market sees some LCY-financed projects reach financial close.

• Policymakers: Through its monetary policy, GoK and the Central Bank of Kenya (CBK) seek to enhance stability of the economy and sustain the value of the KES; one mechanism to achieve this is to reduce national exposure to HCY. Furthermore, the Ministry of Energy (MoE) is

4 Kenya was graduated to Lower-Middle Income Country (LMIC) status by the World Bank in 2015; its status as LMIC under the Development Assistance Committee of the OECD is also expected to change in the near term


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exploring ways to reduce cost of energy to the consumers and eliminating FERFA can play a role in tariff reduction over the long term.

HOW HAVE BENCHMARK COUNTRIES APPROACHED LOCAL CURRENCY-DENOMINATED PPAS?

The authors benchmarked five Asian and African markets that have introduced LCY-denominated PPAs. Most of these markets have had a positive experience making this policy shift, and there are some important lessons to be learned for Kenya.

We selected the benchmarked countries based on comparability with Kenya, varying length of experience with LCY tariffs, and geographic diversity. While some of these markets experienced challenges in transition, most of them saw greater participation by local investors and reduced exposure to HCY risk:

• India: India has had a LCY regime (with tariffs fully in LCY) since the early 1990s. Similar to Kenya, a significant portion (up to 60%) of renewable energy IPPs’ costs remain in HCY; despite this, IPPs’ contribution to India’s power generation has risen rapidly in the last 15 years, reaching 44% of the overall capacity – showing that the LCY regime has been effective.

• Indonesia: The country suffered under a HCY regime during the Asian financial crisis of the late 1990s, when the Indonesian rupiah depreciated significantly. PPAs in the country have been denominated in LCY since 2015; however most remain fully indexed to the USD. Indexing is seen as a transitional step before moving to unindexed LCY tariffs.

• Philippines: The Philippines also suffered during the Asian financial crisis of the late 1990s, when PPAs were denominated in HCY and the peso depreciated significantly. The government was forced to sell its generation assets, which resulted in 100% private sector ownership of power generation. The privatization effort came with a transition to LCY tariffs; under the regime, IPPs’ capacity charges are adjusted to account for FX movements, while operations and maintenance (O&M) costs or operational expenditure (opex) remain un-indexed to HCY. This transition has been successful and has reduced exposure of the offtaker to FX risks.

• South Africa: South Africa has successfully implemented a LCY regime for renewable energy IPPs under its competitive tender REIPPP5 program, which is indexed to inflation. IPPs have added 3,052 MW capacity to the grid in the past seven years, with 86% of debt raised locally from 2012-20146. Tariffs offered under REIPPPP have dropped from an average US cents/kWh of 14.3 (wind), 34.5 (PV), 33.6 (CSP) in 2012 to 7.5 (wind), 10 (PV), 16.6 (CSP) in 2014, due to competitive bidding and decreasing cost of LCY financing costs.

• Tanzania: The transition to LCY-denominated PPAs in 2008 was unsuccessful primarily due to market perceptions around off-taker creditworthiness, as well as lack of depth in the domestic capital markets. After a period of limited investment in IPPs, Tanzania transitioned back to USD-denominated PPAs in 2014.

From these markets, we identified several lessons for transitioning to a LCY regime that are relevant for Kenya:

• Follow a progressive step-by-step process to transition to LCY tariffs, avoiding wholesale change that may make the market anxious.

• Design a fair tariff structure that continues to attract investors, reflecting denomination of costs incurred by IPPs and risks they bear.

5 Renewable Energy IPP Procurement Program https://www.ipp-renewables.co.za/ 6 Presentation: http://www.irena.org/EventDocs/RECC/30.%20REIPPPP%20South%20Africa.pdf


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• Promote investment from domestic institutional investors. This has been achieved through tax exemptions, asset allocation requirements, and promotion of new investment structures.

• Build local market understanding of project finance and the power sector. This was done successfully in the Philippines, with the IFC providing local banks with technical assistance.

• Encourage credit enhancements and financial instruments during transition, to mitigate perceived credit risks associated with LCY financing.

• Consider fiscal incentives to encourage local sourcing and build industry. In Indonesia, the IPP regime includes requirements to source a percentage of construction materials locally.

HOW SHOULD LCY TARIFFS BE STRUCTURED AND IMPLEMENTED IN KENYA?

The authors recommend that the transition to a LCY regime should be gradual and take a hybrid approach. For projects under 10MW, tariffs should be fully denominated in LCY. For projects above 10MW, tariffs should be partially indexed to HCY according to technology.

Based on our market sounding and benchmark analysis, we recommend in the near-to-medium term:

• For projects of 10MW and below, PPAs should be denominated fully in LCY. Given their size, these projects can comfortably be financed in LCY by local banks and institutional investors.

• For projects above 10MW, a hybrid tariff with partial indexing to HCY is the most viable option. This is to minimize risk for IPPs where project opex costs are partially incurred in HCY, and to allow for a gradual approach to adopting LCY tariffs and mobilizing increasing volumes of LCY financing into the sector from the domestic capital markets. Construction costs incurred in HCY can be financed in LCY if the financed amount is converted into HCY at spot FX market rates. Hence, only the opex costs incurred in HCY need to be indexed to HCY. To determine the indexable component (i.e. the percentage of tariff that should be indexed to HCY), we recommend taking the proportion of opex costs incurred in LCY versus HCY by technology. The figure below shows the indexing and the table shows tariffs in KES, for illustrative purpose only, assuming a fixed FX rate of 103 (USD/KES) at the time of writing this report, and a base tariff of 0.10 USD cents:

Figure 3: Tariff structure recommendation by renewable energy technology7

A consideration can be given to large power projects, which cannot be completely financed by LCY and therefore take HCY financing. Tariff indexing for such projects can be discussed on a case-by-case basis. We recommend that parallel initiatives be taken to support a successful transition to a LCY regime:

7 Based on market interviews and assumptions

Technology Total tariff amount

(KES)

Amount indexed to USD (KES)

Amount un-indexed

(KES)

Hydro 10.3 1.6 8.7

Geothermal 10.3 1.8 8.5

Wind 10.3 2.7 7.6

Solar 10.3 1.2 9.1

Biomass 10.3 4.0 6.3 16% 17%26%

39%

84% 83%74%

88%

61%

12%

SolarGeothermal BiomassWindHydro

Proportion of LCY tariff Proportion of HCY tariff


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• Fiscal and other policy incentives:

o To ensure a smooth transition and demonstration effect, a higher LCY tariff could be offered to early adaptors to encourage uptake of LCY tariffs in the market.

o Enhance tax incentives for LCY investments into the infrastructure sector, e.g. making portion of interest earned on loans to IPPs as tax deductible.

o Introduce tax breaks on locally sourced materials, e.g. equipment and services sourced locally for power projects can be made tax free (no VAT).

o Create power & infrastructure as a distinct asset class for institutional investors, which could further help to promote investments into the power sector.

• Credit enhancements: Credit enhancements can facilitate access to LCY funds by mitigating the perceived credit risk of financing power projects and thus, create conditions that attract LCY financing. Companies such as GuarantCo have already established their readiness to provide partial credit guarantees pre-construction as well as tenor extension. Local investors require awareness building and training in how to use these products effectively, and public-sector actors can play a role in endorsing these products to increase uptake.

• Capacity building: One of the biggest challenges in mobilizing LCY financing for power projects has been limited capacity within the sector to evaluate the projects, specifically with respect to structuring and evaluating project finance deals. This has resulted in most of the participation in the sector being from foreign players, who mostly invest in HCY. Targeted capacity building programs – for local banks, institutional investors, and local developers – is needed to build capacity and awareness within the sector.

In summary, we recommend that MoE initiate a policy process to introduce a LCY regime in the near term. Development of the policy should be undertaken in close consultation with the industry, as well as in parallel with market building activities to increase awareness and capacity. In addition to this, MoE should provide incentives for early adopters by prioritizing PPA signing for IPP developers willing to take a LCY tariff.


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1. INTRODUCTION

THE IMPORTANCE OF LOCAL CURRENCY FINANCING IN KENYA’S POWER SECTOR

Up to the present day, power purchase agreements (PPAs) in Kenya have been denominated in hard currency (HCY), meaning payments by Kenya Power to independent power producers (IPPs) are in HCY. While HCY regimes are currently the norm across Sub-Saharan Africa, it is important to note that the majority of power in advanced economies is financed in local currency (LCY). In Kenya, KenGen tariffs are in LCY with a provision for forex adjustment pass-through. This pass-through is never 100% since there is a loss factor in the formula and its value has so far been less than actual losses. HCY-denominated PPAs made sense in the past for Kenya. However, the depth and sophistication of the debt capital markets and the growth of the local banking sector has changed significantly since the first IPP in Kenya more than twenty years ago.

HCY-denominated PPAs transfer the foreign exchange (FX) risk from IPPs to Kenya Power, who receives revenues from its customers in Kenyan Shillings (KES). Kenya Power transfers this risk to consumers by adding a “Foreign Exchange Rate Fluctuation Adjustment” (FERFA) to the electricity prices charged to consumers. The figure below illustrates the market structure and allocation of FX risk:

Figure 4: Current market structure of the power sector in Kenya

While this has been the status quo, Kenya’s domestic capital markets have deepened substantially in the past few decades and are well positioned to contribute to financing of the power sector. Among commercial banks in the country, the value of gross loans grew at a rate of 14% per annum from 2011 to 2016, reaching KES 2,293 billion in 20168. Similarly, overall investments from pension funds and insurance companies have grown at a rate of 17% and 19% respectively during the period from 2011 to 20159. Moreover, the use of credit enhancements and other financial instruments in the country has increased. Several organizations, such as GuarantCo, The Currency Exchange Fund (TCX), and the African Trade Insurance Agency (ATI), provide financial products that support investments in the power sector in LCY and reduce risk exposure. Hence, it is now an appropriate time to assess the feasibility and options for LCY-denominated PPAs in Kenya.

While many African countries have tariffs in HCY, the leading economies on the continent, including South Africa, Egypt, and Tunisia, have transitioned to LCY tariffs, either partially-indexed or non-indexed to HCY. Some other African countries, such as Zambia, Mozambique, and Namibia, have made early steps towards LCY tariffs, by denominating them in LCY, but indexing them fully to HCY (usually 8 Source: Central Bank of Kenya 9 Source: Retirements Benefit Authority (RBA) for Pension Funds (latest official data available – 2015); Insurance Regulatory Authority (IRA) for Insurance industry (latest official data available – 2015)

Kenya Power CustomersIPPs

Investors

USD

USD

USD

Energy

KES

Energy

RepaymentDebt/ equity financing Tariffs

No forex riskNo forex risk

(transferred to consumers)

Consumers holding forex

risk and paying FERFA


15

USD). Some of these countries have experienced challenges with their adoption of LCY tariffs. However, despite these challenges the trend toward the adoption of LCY tariffs on the continent is likely to gather pace as domestic capital markets across Africa deepen and national governments seek to prudently manage their foreign debt exposure.

OBJECTIVES OF THE STUDY

The objectives of this study are to assess the feasibility of LCY-denominated PPAs in Kenya, and to make recommendations for how this could be implemented in practice. The report aims to do so by presenting findings across multiple streams of analysis, described in the report structure below:

• Chapter 2 – What role do IPPs play in Kenya and how are they being financed? This chapter sets the context for the report by (i) summarizing the history of independent power producers (IPPs) in Kenya and their contribution to the country’s energy mix, (ii) examining how IPPs have been financed – the players and typical terms of financing, and (iii) detailing the current regulatory regime, including Power Purchase Agreements (PPAs) and existing tariff structures.

• Chapter 3 – What are the benefits of a LCY PPA? This chapter examines the question – does a LCY tariff regime make sense for Kenya? The chapter presents the methodology and results of a retrospective analysis of the impact of KES versus USD denominated tariffs over the past 15 years in Kenya. It also assesses the wider benefits a LCY financing environment for the Kenyan consumer, industry actors, and the wider economy.

• Chapter 4 – What is the availability of LCY financing and how would LCY-denominated PPAs impact investors? This chapter assesses the availability of LCY financing for the power sector, and the bankability of LCY denominated PPAs, from a supply (financiers of power projects) and demand (IPP / developers) perspective. It draws on market sizing analysis and extensive interviews with market actors.

• Chapter 5 – How have benchmark countries approached LCY-denominated PPAs? This chapter analyzes the experience of other developing economies that either have LCY-denominated PPAs, or are under transition. Five countries were selected – India, Indonesia, Philippines, South Africa and Tanzania. The chapter analyzes results of the transition in each country, and synthesizes the lessons learned across all countries.

• Chapter 6 – How should LCY tariffs be structured and implemented in Kenya? This chapter synthesizes findings from the retrospective analysis, country benchmarking and market sounding to provide recommendations on the design of local currency tariffs, the actions required to introduce LCY-denominated PPAs successfully, and the roadmap for implementation.


16

2. WHAT ROLE DO INDEPENDENT POWER PRODUCERS (IPPS) PLAY IN KENYA AND

HOW ARE THEY BEING FINANCED TODAY?

This chapter aims to place the Kenyan power sector in context. The chapter: (i) summarizes the history of independent power producers (IPPs) in Kenya and their contribution to the country’s energy mix, (ii) examines how IPPs have been financed – the players and typical terms of financing, and (iii) details the current regulatory regime, including power purchase agreements (PPAs) and tariff structures.

POWER SECTOR IN KENYA AND THE ROLE OF IPPS

As of 2017, Kenya has an installed capacity of 2,366 MW, with the primary sources being geothermal and hydro which account for ~62%. The Ministry of Energy (MoE has made substantial progress in development of the power sector in recent years – across generation, transmission, and distribution. Installed capacity has more than doubled in the past 15 years. The electrification rate increasing from 27% in 2013 to 70% in 201710, with a stated ambition to reach universal access by 202011. Still, consumption per capita in Kenya remains relatively low at 167 kWh, while the global average stands at 3,128 kWh, with leading regional consumers in South Africa and Egypt at 4,229 and 1,658 respectively12.

Since generation opened to the private sector in 1996, IPPs have contributed significantly. KenGen remains the largest power producer contributing ~70% of total installed capacity13; however, IPPs are increasingly playing a critical role to help MoE meet its ambitious power generation targets. IPPs now contribute around one-third of total installed capacity in Kenya, with several projects (notably, Lake Turkana Wind Project) poised to increase IPPs’ contribution in the near future.

MoE manages medium- to long-term planning of the power sector through its Least Cost Power Development Plan (LCPDP), which is revised regularly. The LCPDP identifies least cost generation potential and forecasts future demand for power. Given Kenya today has a relatively high cost of power at ~0.15 USD per kWh (compared to 0.10 - 0.11 USD in South Africa), the LCPDP puts a strong emphasis on increasing the share of renewables in the country’s energy mix due to its lower levelized cost compared to thermal sources. Recent developments include: Lake Turkana Wind Project, which is nearly complete and will add 310 MW of capacity; four PPAs in solar, each with 40 MW capacity and Rural Electrification Authority’s 55MW solar PV in Garissa, have recently been signed by Kenya Power and will soon break ground; KenGen and the Geothermal Development Company (GDC) continue to advance exploration of Kenya’s geothermal resources at Olkaria and Menengai. Contribution of renewable energy in the overall energy mix is shown in the figure below:

10 Source: Energy Regulatory Commission 11 Source: Kenya Power 12 Source: World Development Indicators, 2014 (latest available data) 13 Source: 2015 ERC Annual Report


17

Figure 5: Total electricity installed capacity (2016, MW)

Tariff competitiveness is becoming increasingly critical in Kenya, given the different resource options available and the future potential of cross-border power transmission under the Eastern African Power Pool (EAPP)14. In this context, currency denomination is a key factor that can drive competitiveness.

PPAS AND TARIFF STRUCTURE FOR RENEWABLES

As of today, PPAs in Kenya are denominated in USD with an inflation-pegged escalable portion that varies according to technology (e.g. 8% escalable in hydro, 12% in wind). Lake Turkana Wind Power PPA is the exception in Euro. PPAs are typically 20-year agreements or 25-years for Geothermal plants, which provide long-term revenue streams to IPPs and their investors.

Policy-wise, there is a two-pronged approach for IPPs to secure PPAs: (1) Direct negotiations for large projects, both renewable energy and fossil-fuel based, and (2) Standardized PPAs, under Feed-in-Tariffs (FiTs) for small renewable energy projects (accepting that there are some large projects that have been procured under the FiT policy, eg. 100 MW Kipeto wind power plant):

1. Direct negotiations: All power projects with capacity larger than the limits in FiTs undergo direct negotiations to determine the tariff structure. The negotiations are based on cost-plus-return terms, which considers project cost, financing terms and a reasonable equity IRR, as shown in the figure below. Overall, Kenya Power’s strong track record of meeting its PPA obligations has created an attractive environment for IPPs in the Kenyan market.

Figure 6: PPA negotiations – Inputs and outputs

14 EAPP is a framework for pooling energy resources, promoting power exchanges between utilities in Eastern Africa and reducing power supply costs

Inputs to negotiations

Equity IRR expectation

Financial terms, e.g. Debt/equity split, interest rate, tenor

Project Cost

Technology-specific fundamentals, e.g. cost per MW, load factor

Project-specific fundamentals, e.g. capacity, proximity to grid

Outputs of negotiations

Tariff structure(usually with a scalable component, e.g. % of tariff indexed to inflation)

Capacity charge –compensates for fixed O&M and financing cost

Energy charge -compensates for variable O&M, fuel costs

652

826

803

2,3361 2

ThermalTotal HydroGeothermalCo-generation

26

Wind

26

BiogasSolar


18

2. FiTs: apply to smaller renewable projects: <40 MW in biomass and solar; <20 MW in hydro; <50 MW in wind; and, <70 MW in geothermal. FiTs in Kenya are denominated in USD, and their values are dependent on technology – wind, biomass, hydro, geothermal, biogas or solar. The last FiT schedule was set in 2012, and since then the costs of some renewable technologies have reduced considerably. Hence, many projects falling under the FiT category currently also go through direct negotiations to determine the tariff values. No other FiT revision is envisaged, as Government is considering transitioning from FiT to Renewable Energy Auctions.

FINANCING OF POWER PROJECTS

Financing for IPPs in Kenya has to date been sourced from a combination of: Development Financial Institutions (DFIs) (debt and equity), foreign and local sponsors (equity), and commercial banks (debt). Most of the DFI capital has been in HCY (although some DFIs do have the ability to lend in local currency, they have done so rarely in the past); commercial banks have also invested mostly in HCY, to avoid currency mismatches and with the support of credit guarantees to extend tenors. KenGen too has raised substantial capital from DFIs; though it has also tapped local capital markets using corporate bonds and has obtained debt financing from local commercial banks.

The figure below shows an overview of the stages of development of a power project, activities in those stages and the role of financing in each stage:

Figure 7: Stages of project development, and financing required

Capital injection into a power project occurs along different stages of the project development cycle. On average, the debt/equity split in power projects is 70%/30%. Typically, at the start of the project, IPPs use their own capital as well as seek equity investors (development risk capital) to finance feasibility studies, acquire land, etc. Local sponsors sometimes provide equity in LCY; however, DFIs (e.g. IFC, Norfund, FMO, IFU) have been more prominent and they typically invest in HCY (noting that some DFIs can and do invest in LCY also). Certain pension funds and asset managers have invested equity in power projects (e.g. Kenya Power Pension Fund), however they are few. The expected equity return (IRR) in HCY is usually 14-18%, and can be as low as 12% for larger renewable power projects.

Pre-financial close Construction phase Operations phase (ongoing until the life of the project)

Activity Acquire licenses, conduct feasibility and environmental studies, acquire land, obtain legal, technical and financial advisory

Hire an EPC contractor (design the plant, procure equipment, construct the plant)

Run the power plant, conduct regular maintenance, replace components with spare parts wherever required

Financing Mainly equity capital from developers and sponsors invested in the project

Mainly debt capital used to construct the project

Revenue from power sales used to service debt and provide equity returns

Actors in Kenya (examples)

• Developers: Frontier Energy, Ormat Technologies, Globeleq, Gulf Energy, Tembo Power, Tsavo Power

• DFIs active on equity side (Sponsors): Norfund, Netherlands Development Finance Company (FMO), The Investment Fund for Developing Countries (IFU), responsibility

• DFIs active on debt side: International Finance Corporation(IFC), Overseas Private Investment Corporation (OPIC),Proparco, DEG, KfW, African Development Bank (AfDB)

• Commercial banks (debt): CfCStanbic Kenya, Standard Bank South Africa, Absa Capital South Africa, Industrial and Commercial Bank of China (ICBC), Nedbank South Africa

Developers run the power plant during the operations phase.

Financial closeCommencement of

operations


19

Debt capital is typically sought during the construction phase of the project. Debt financing is used to fund the costs of hiring the engineering, procurement and construction (EPC) contractor, who (today) are mostly foreign companies with a few smaller local players. DFIs again are the prominent players on the debt side, and mostly provide HCY debt with tenors of 10 years or more. Several local and regional commercial banks (e.g. CfC Stanbic, Equity Bank, etc.) have also provided debt to IPPs in Kenya, primarily in HCY so far to avoid currency mismatch with the underlying PPAs. Sometimes these banks have financed projects using facilities with DFIs e.g. Agence Française de Développement (AfD)’s SUNREF program, or with the benefit of partial risk guarantees from the likes of African Development Bank. A couple of pension funds and insurance firms have invested debt into power projects, however this has been minimal to date. Details of illustrative IPP transactions are provided in the table below.

KenGen has access to concessionary loans through the Government of Kenya (GoK), with a weighted average cost of debt at 3.87% and weighted average maturity of ~15 years in 201615. The World Bank, JICA and KfW are among its major funders, all providing HCY financing. KenGen has also raised debt in LCY from the local debt capital market (notably, a KES 25 billion corporate bond in 2009/10 at 12.5% coupon) as well as from local commercial banks who have provided a mix of HCY and LCY16.

Table 1: Illustrative IPP transactions (equity and debt) in Kenya (not exhaustive)17

Project (technology)

Equity partners (Country, % equity held) Debt providers (value of debt)

Iberafrica (Thermal)

Union Fenosa (Spain, 80%), Kenya Power Pension Fund (Kenya, 20%)

Union Fenosa ($12.7 million in direct loans and guaranteed $20 million); Kenya Power Pension Fund ($9.4 million in direct loans and guaranteed $5 million through a local Kenyan bank)

OrPower4 (Geothermal)

Ormat (USA, 100%) European DFIs ($105 million), OPIC ($310 million)

Tsavo (Thermal)

Cinergy (USA) and IPS (Industrial Promotion Services) jointly owned 49.9%; Cinergy sold to Duke Energy (USA) in 2005, CDC/Globeleq (UK, 30%), Wartsila (Finland, 15%), and IFC (Int’l, 5%)

IFC ($16.5 million), IFC syndicated ($23.5 million), CDC ($13 million), DEG (€11 million), DEG syndicated (€2 million)

Rabai (Thermal)

Aldwych International (Netherlands, 34.5%), BWSC (owned by Mitsui, 25.5%), FMO (Netherlands, 20%), IFU (Denmark, 20%)

FMO ($126 million), Proparco and EAIF (25% each), DEG (15%), European Financing Partners (10%)

Thika (Thermal)

Melec PowerGen (part of Matelec Group) (Lebanon, 90%)

AfDB (€28 million), IFC (€28 million), Absa Capital (€28 million)

Triumph (Thermal)

Broad Holding (Kenya), Interpel Investments (Kenya), Tecaflex (Kenya), Southern Inter-trade (Kenya)

Industrial and Commercial Bank of China ($80 million), CFC Stanbic Bank Kenya ($28 million)

Gulf (Thermal)

Gulf Energy Ltd., Noora Power Ltd IFC A Loan ($76 million) in long-term debt, commercial lending through IFC B Loan, and OPEC Fund for International Development

15 Source: KenGen Annual Report, 2015-2016 16 Source: KenGen Annual Report, 2015-2016 17 Eberhard, Anton, Katharine Gratwick, Elvira Morella, and Pedro Antmann. 2016. Independent Power Projects in Sub-Saharan Africa: Lessons from Five Key Countries. Directions in Development, World Bank, Washington, DC; European Commission


20

Kinangop - in receivership (Wind)

Aeolus Kenya, African Infrastructure Investment Fund 2, Norfund

CFC Stanbic Kenya ($90 million)

Lake Turkana Wind Project (Wind)

KP&P Africa BV (Netherlands), Aldwych International (Netherlands), Finnfund, IFU, Norfund, Vestas Wind Systems

AfDB (KES 15 billion), European Investment Bank (KES 23 billion), the Standard Bank of South Africa, Nedbank, Proparco, East African Development Bank (EADB), The Eastern and Southern African Trade and Development Bank, Eksport Kredit Fonden (EKF), FMO, Proparco, DEG.

IPPs and investors can use a variety of mechanisms to enhance credit and mitigate project risks, including partial credit guarantees and insurance products. To date, these instruments have been used in Kenya for HCY transactions but not yet for LCY transactions (due to there being few such transactions). There are now LCY credit enhancement and currency swaps in the market (e.g. GuarantCo, TCX), which can serve to facilitate greater LCY debt flows into the power sector.

ROLE OF IPPS GOING FORWARD

Based on the Development of a Power Generation and Transmission Master Plan18, Kenya aims to reach 6,171 MW of installed capacity by 2027, which would require ~3,500 MW in additional capacity coming online in the next 7 years19. IPPs will continue to have an important role to play in powering Kenya’s growth.

18 Long Term Plan 2015 – 2035 (October 2016), Firm Capacity – Peak Load plus Reserve Margin, Vision Scenario 19 ibid (2,648 MW expected to be online by the end of 2018)


21

3. WHAT ARE THE BENEFITS OF A LCY -DENOMINATED PPA?

OBJECTIVES OF CHAPTER

This chapter examines the benefits of local currency (LCY) financing for power projects in Kenya. Specifically, the chapter:

• Presents the methodology and results of a retrospective analysis of the impact of KES versus hard currency (HCY) denominated tariffs over the past 15 years in Kenya. This retrospective analysis is intended to form a picture of what the overall cost savings / increase to the Kenyan consumer would have been in the past 15 years if tariffs and financing of power projects had been denominated in KES instead of USD.

• Conducts sensitivity analysis to show sensitivity of cost savings / increase to key variables – notably foreign exchange rates and interest rates.

• Analyzes the total amount charged to Kenyan consumers under the foreign exchange rate fluctuation adjustment (FERFA) calculations over the past 15 years.

• Assesses the wider benefits of a LCY financing environment for the Kenyan consumer, industry actors, and the wider economy.

RETROSPECTIVE ANALYSIS OF THE IMPACT OF LCY VERSUS HCY DOLLAR TARIFFS

THE METHODOLOGY

In Kenya, tariffs payable to IPPs have been denominated in USD and the cost of currency depreciation has been borne by the Kenyan consumer (and partly by KPLC due to the company’s inability to pass-through 100% as the actual energy losses are higher than the loss factor in the FERFA formula). The retrospective analysis assesses whether the costs to the Kenyan consumer would have increased or decreased if tariffs had been denominated in KES. To do this, the analysis assumes that under a KES tariff regime all debt financing for projects would have been denominated in KES. It then compares the relative costs of financing in both HCY and LCY for all projects commissioned in Kenya in the last 15 years (2002-2016). Further analysis is found in Annex 1: Retrospective analysis of the last 5 years (2012-2016) and 10 years (2007-2016). In order to isolate the impact of currency denomination, it keeps the equity returns to IPPs (IRR) constant across both currency scenarios and increases / decreases revenues to IPPs proportionately to result in the same returns achieved. The analysis uses nominal and real values (inflation-adjusted) and shows the results in the two scenarios.

Figure 8: Comparison of hard currency and local currency financing

The effect of two counteracting forces – currency depreciation and interest rates – ultimately determine the retrospective impact of KES versus USD tariffs on costs to the Kenyan consumer:

1. Under a USD tariff (with USD financing), depreciation of KES in this period leads to increasing costs to consumers over time: Under a flat USD tariff structure, Kenya Power (and therefore the

Due to any depreciation in KES

Due to any differential in interest rates in KES

financing over hard currency


22

Kenyan consumer’s) obligation to IPPs increases as the KES depreciates. In other words, Kenyan consumers have to pay more in KES, to support the same USD tariff. Switching to KES tariffs would eliminate this depreciation expense, reducing cost to consumers.

2. Under a KES tariff (with KES financing), higher cost of KES financing in this period leads to IPPs’ increased debt costs, due to higher interest rates in KES than USD. Kenya Power (and therefore the Kenyan consumer) would have paid higher tariffs to IPPs, assuming the same return expectations.

The analysis compares the differential in USD and KES interest rates with the effects of KES depreciation, and models the impact on IPPs’ payments from Kenya Power required to maintain constant returns to IPPs. Same return (equity IRR) expectations were used for both USD and KES tariff scenarios to isolate the effect of the different financing costs. Further, it analyzed these aspects for power projects installed over the past 15 years (2002 – 2016), which represents more than half of total installed capacity and half of all power purchased by Kenya Power in the last decade. A detailed list of power stations included in the analysis is provided in the Annex.

Figure 9: Total installed capacity by technology (MW)20

20 Source: Energy Regulatory Commission

664796

265

805

582

93

2,20926

20162002

1,0220

Geothermal

Wind

Thermal

Hydro


23

Figure 10: Annual purchase of energy from power plants installed post-2002 (GWh)21

The analysis models out IPPs’ revenues from power sales for all power plants commissioned over the period of analysis (2002-2016). To keep IPPs’ returns constant, any change in IPP revenues must be matched by Kenya Power, and ultimately the Kenyan consumer. IPP revenues were calculated using actual historic Kenya Power payment data.

METHODOLOGY USED FOR ANALYSIS WITH REAL VALUES

Below is the explanation of the steps taken to convert the nominal retrospective analysis into real (inflation-adjusted) values.

• Used real interest rates: Calculated real interest rates for each year using inflation in Kenya and in the US for the respective currencies, with 2002 as the base year.

• Used real (inflation adjusted) capex values: Projects’ capex adjusted as per US inflation, with 2002 as the base year.

• Used real (inflation adjusted) revenue, return and opex values: Values adjusted as per inflation, with 2002 as the base year.

o For KenGen projects, used Kenya inflation as PPAs are denominated in KES. o For IPP projects, used the US inflation as PPAs are denominated in USD.

• Real exchange rates: Replaced nominal exchange rates by real exchange rates, with 2002 as the base year.

RESULTS WITH NOMINAL VALUES

Over the period of analysis, the impact of higher interest rates in KES versus USD marginally outweighed the effects of KES depreciation – resulting in an overall required tariff increase of 5% under a local currency regime. Despite a few shocks, the KES was relatively stable between 2002 and 2016, depreciating against the USD at an average of 2% per annum. For our analysis on USD financing costs, we have assumed USD interest rates to be at LIBOR + 7%, a reasonable rate offered by commercial banks. Although we recognize that DFIs offer lower interest rates than those offered by commercial players and acknowledge their participation in financing power projects in Kenya, the analysis focuses on the USD interest rates offered by commercial players to ensure a commensurable comparison with the KES interest rates. For KES financing, we have used hypothetical KES interest rates of 10-year Treasury Bond + 2% for the year in which each plant was commissioned. The hypothetical rates were necessary in the analysis given that most of the debt financing of these

21 Source: Kenya Power Financial Statements

13%

9%

7%

2007

1,641

14%

9%5%

11%

44%

9%

1%

2015

6,039

16%

40%

8%

20142010

3,076

31%

9%

7%

2009

2,318

20%

8%

8%

2008

6,300

4,827

26%

20%

8%

2013

3,752

21%

15%

11%

2012 2016

1,840

3,834

26%

16%

9%

2011

3,020

23%

11%

9%

Geothermal ThermalHydropowerWind

Energy sales from projects installed in the last 15 years has been growing, and accounts for half of the total sales in the last decade.

50%50%

2002-2016Pre-2001


24

projects was in USD and there were few equivalent KES deals to benchmark against. The interest rates in USD and KES, their differential and the comparison with KES depreciation is shown in Table 2 below:

Table 2: USD and KES interest rate differential vs. KES depreciation22

LIBOR + 7% 10-year T-Bond + 2%

Interest rate differential

KES/USD average Fx rate

KES depreciation

KES depreciation -Interest rate differential

2002 9.2% 14.5% 5.3% 78.9 0.4% -4.9%

2003 8.4% 9.4% 1.0% 75.8 -3.9% -5.0%

2004 9.1% 11.7% 2.6% 78.4 3.5% 0.9%

2005 11.0% 13.9% 2.8% 75.6 -3.7% -6.5%

2006 12.3% 14.7% 2.4% 72.1 -4.5% -6.9%

2007 12.1% 14.0% 1.9% 67.5 -6.5% -8.4%

2008 10.1% 13.6% 3.5% 69.0 2.3% -1.2%

2009 8.6% 13.5% 4.9% 77.3 12.1% 7.2%

2010 7.9% 9.8% 1.9% 79.3 2.5% 0.6%

2011 7.8% 14.9% 7.1% 88.9 12.1% 5.0%

2012 8.0% 15.0% 7.0% 84.5 -4.9% -11.9%

2013 7.7% 14.4% 6.7% 86.1 1.9% -4.8%

2014 7.6% 13.9% 6.3% 87.9 2.1% -4.2%

2015 7.8% 15.4% 7.6% 98.6 12.1% 4.5%

2016 8.4% 16.4% 8.0% 101.5 2.9% -5.1%

The analysis shows that IPPs’ financing costs for projects would have been in aggregate 18% higher (KES 20 billion) in a LCY tariff regime with LCY financing, as shown in Figure 11 below. The costs of compensating IPPs for higher KES interest rates (instead of USD interest rates) under a KES tariff would be KES 28 billion, and the cost of KES depreciation under a USD tariff would be KES 8 billion. The difference in the two figures leads to the KES 20 billion higher financing costs incurred in KES financing. This is perhaps unsurprising during the time period under analysis, given the relatively stable KES, historically low USD interest rates, and at times high KES interest rates.

The figure below shows aggregated debt service coverage for all operating power plants in Kenya installed between 2002 and 2016. The two lines represent KES financing and USD financing costs respectively, which both increase over time by the estimated amount of debt (see assumptions) taken on by new power projects as they are commissioned, in addition to the effects of depreciation and KES interest rates, respectively:

22 Source: Central Bank of Kenya; World Bank Indicators


25

Figure 11: Aggregated debt repayments for power projects, KES billion

With the increased cost of financing, an aggregate increase of 5% in revenues to IPPs (KES 20 billion out of KES 406 billion total revenues) would be required, holding returns to IPPs constant. This increase is the same absolute amount as the increase in financing cost, but represents a smaller percentage when compared to total project revenues. The increase in revenues to IPPs would require an equally higher tariff paid by Kenya Power to IPPs, and in turn charged by Kenya Power to the Kenyan consumer.

Therefore, it is estimated that the KES tariff regime would have resulted in an overall estimated tariff increase of 5% on average over the past 15 years, holding everything else (opex, IPP returns, etc.) constant, as shown in the figure below:

Figure 12: Increase in financing cost and revenue required to keep IPP returns constant, KES billion

108 128

217217

6161

+5%

406

+18%

KES financingUSD financing

386

O&M, Depreciation, Fuel

Financing CostReturns

35

30

25

20

0

15

5

10

2014 20162010 201220082002 2004 2006

KES financing USD financing

Olkaria 2, Iberafrica Sondu, Rabai Kipevu, Orpower 4 Olkaria, Thika, TriumphMajor additions to

generating capacity

18% (20 billion)


26

Based on a weighted average cost of power purchased by technology, providing this additional revenue to IPPs would require an increase of 0.6 KES per kWh on average. Over the period of analysis, Kenya Power paid a weighted average rate of 11.9 KES per kWh to power producers. This would have increased to 12.5 KES per kWh under KES tariffs.

For renewables, Kenya Power paid a weighted average rate of 6.2 KES per kWh, which would have increased to 6.8 KES per kWh under KES tariffs. Power sales from geothermal and hydro power plants have increased in recent years, and KenGen accounts for the majority of the power sales in those technologies. KenGen’s tariffs average around KES 7 per kWh and KES 3 per kWh for geothermal and hydro respectively. This contributes to low price of renewables in the table below:

Table 3: Weighted average price under KES and USD tariffs (KES per kWh)

USD Financing KES Financing

Year Total Renewable Non-renewable Total Renewable Non-renewable

2004 6.1 4.9 10.3 6.2 5.0 10.3

2005 6.5 4.9 11.4 6.7 5.1 11.9

2006 6.7 4.9 11.5 7.2 5.2 12.5

2007 9.5 4.9 13.3 10.0 5.4 13.7

2008 9.2 4.4 14.1 9.5 4.8 14.6

2009 10.8 5.2 15.3 11.0 5.4 15.5

2010 11.9 5.9 14.9 12.1 6.0 15.1

2011 12.1 4.7 18.7 12.1 4.5 18.8

2012 16.3 5.5 24.4 16.7 5.4 25.2

2013 13.6 4.5 22.9 14.6 5.7 23.7

2014 15.0 8.8 20.8 15.8 9.6 21.6

2015 11.2 7.1 22.0 12.1 8.0 22.9

2016 10.5 7.2 24.4 11.4 7.9 26.1

Weighted average 11.9 6.2 20.0 12.5 6.8 20.8

COST PER CUSTOMER

Taking a Kenyan customer-centric view, the analysis means that the increase in tariffs under a KES regime would have resulted in an average increase of KES 250 per Kenyan household per year. Based on Kenya Power’s relative historical sales and number of accounts for the three main customer categories, each household would pay an additional KES 250 per year, each small business would pay an additional KES 1,400 per year, and each large commercial and industrial customer would pay an additional KES 238,000 per year:


27

Figure 13: Increased cost per customer per year (KES)23

Table 4: Costs increase split by customer segments

Additional cost per customer per year

Total customers 2016 (%)

Percent of total power purchased (2016)

Residential KES 254 3.7 million (94.9%) 27%

Small commercial KES 1,433 200,000 (5.0%) 16%

Large commercial KES 238,232 3,500 (0.1%) 56%

SINGLE PROJECT VIEW

To illustrate the analysis in a different way, below is the debt repayment picture for a single power project over the investment lifecycle (generic example used to protect confidentiality). It is assumed that the plant was commissioned in 2004 with a project cost of $90 million (KES 7.1 billion at 2004’s exchange rate) with a 70% debt / 30% equity split on the below terms:

Table 5: Single project view - Financing terms used

Value of debt Interest rate, Tenor

USD 63 million Average interest rate 9.1% (annual values used as per Table 2Table 2), Tenor = 15

years

KES 4.8 billion Average interest rate 13.6% (annual values used as per Table 2), Tenor = 15 years

This shows the debt repayment under USD financing and KES financing, with the interest rates fixed over the lifetime of the loan. The value of those loan payments in KES fluctuates in line with the KES-USD exchange rate. As shown in the figure below, the annual debt payment in terms of KES value increases from KES ~660 million in 2005 to KES ~885 million in 2016 – a roughly 34% increase. The majority of this increase occurs over the period 2011- 2016. However, the higher interest rates on KES financing would have resulted in annual payments of KES ~804 million, which would remain the same throughout the loan repayment period given the fixed interest rate.

23 Kenya Power Financial Reports; Dalberg and Leadwood analysis

27,890

4,950

29,323

5,204

~+238,000

~+1,400

~+250

Commercial and Industrial

4,637,816

4,876,049

Residential Small Commercial

KES FinancingUSD Financing


28

Figure 14: Hypothetical power plant debt repayments with USD and KES financing

ASSUMPTIONS AND DATA USED

The table below summarizes the assumptions and data sources for the retrospective analysis.

Table 6: Assumptions and data sources

Input Assumption Data source/rationale

Project cost

Range from USD 2-3.8 million per MW installed depending on technology and size of the plant

Based on 2012 ERC estimates, with a 15% discount added to account for larger scale projects and falling technology costs (to be updated with actual project costs, when data received from ERC and KenGen)

Return expectations

Same returns in both USD and KES tariff scenarios

To isolate the impact of currency of tariff denomination, we have held IPPs’ equity IRR same in both scenarios.

Financing structure

15-year loan tenor for both USD and KES financing

Typical loan tenor for power projects, although it is sometimes shorter

70/30 debt/equity split Industry benchmarks and market sounding with developers

Loan grace period: during construction estimated at average of 12 months (for solar and wind, however longer for geothermal and hydro)

Market sounding with developers and DFIs

Hedging costs excluded from analysis

It is unclear to what degree of local currency hedging would be ‘market’, given there have not been many local currency deals in the power sector yet. Market sounding suggests that under KES regime hedging could be required during the construction period

Interest rates

USD benchmark: fixed rate LIBOR 2002-2016 + risk premium (7%)

Market sounding with commercial financiers

KES benchmark: 10-year T-bond yield + risk premium (2%). Variable rate

Market sounding with commercial financiers

2005 2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016

750

650

6

1

900

700 5

4

0

2

800

850

0

7

3

600

8

13

11

12

10

9

KES millions USD millions

USD financing debt payment (value in KES million)

KES financing with fixed interest rate (KES million)

USD financing debt payment (USD million)


29

KES exchange rates

KES/USD average annual rate Central Bank of Kenya

LIMITATIONS OF THE ANALYSIS

While the retrospective analysis is informative, its limitations should be noted:

• USD financing has experienced lower than usual interest rates in the last 15 years, with LIBOR averaging ~2%. LIBOR averaged 4.2% from 1986-2017, and averaged 5.8% throughout the 1990s. The low interest rate environment since 2002 resulted in lower than average cost of USD financing. However, USD interest rates are expected to rise steadily as has already been experienced in the last couple of years.

• This is coupled with a period of lower than historical average KES depreciation in the last 15 years. KES has undergone periods of more rapid depreciation, e.g. 16% on average depreciation of the KES against the USD per year in the 1990s, with a high of 94% in 1993. In the past 4 years (2013-16), the KES has depreciated at an average rate of 4.8% per year against the USD, significantly higher than the 10 years prior to that. During the period of analysis, depreciation of KES versus USD averaged only 2% per year from 2002-2016.

• The analysis is largely a function of power project commission timing. As the aggregated amount of project debt increases over time, fluctuations in key inputs in later years of the analysis (e.g. 12.1% KES depreciation in 2015) have an outsized effect on the values.

• Results are highly sensitive to variations in inputs for USD and KES interest rates, for which market rates may vary at a given time. As project finance for IPPs in LCY has limited historical data in Kenya, the cost of that financing is uncertain. Small changes in assumptions for interest rates on KES debt result in different cost savings / expense scenarios. Considering the recent experience of greater control by the Central Bank of Kenya (CBK), the KES interest rates are expected to trend downwards.

• Assumptions have been used to estimate values wherever data was missing. We have estimated overall project investment, debt financing cost and revenues realized for projects and years, where the data was not available.

• The past is not an accurate predictor of the future. This retrospective analysis considers what the impact of local currency tariffs would have been if in place in the past 15 years, which is largely a factor of movements in interest and foreign exchange rates over that period. The position going forward may look different, given changing macroeconomic conditions.

SENSITIVITY ANALYSIS

We conducted sensitivity analysis against key variables – interest rates and foreign exchange rates – to assess what the net costs position would have been had the macroeconomic environment been different. The sensitivity analysis shows a range of possible costs savings / increase positions, from the shift to KES regime leading to higher tariffs of KES 62 billion (-16%) to a shift leading to lower tariffs of KES 200 billion (52%). Ranges below represent the maximum and minimum values of financing terms in the last 15 years24. These numbers were extended across over the entire period, demonstrating what could have happened over the period 2002-2016 and also serving as an indication of possible scenarios in the future. The base case scenario in the figure below takes average values of KES depreciation, and interest rates in USD and KES, for the 15-year period.

24 Depreciation for increased expense scenario capped at 0%


30

Figure 15: Costs increase / savings of transition to KES tariffs under different assumptions (KES billions)

We have shown two scenarios that have parity, i.e. neither higher tariffs nor lower tariffs in a transition to KES regime. The two parity scenarios show the combination of different variables to achieve equal cost of USD and KES financing.

In parity scenario 1, all variables are held at the base case scenario, with KES interest rate reduced from 13.7% to 10.3% per year. KES financing becomes more viable as local financing costs decrease. Actions such as credit enhancements, government support, etc., should bring down the cost of KES financing cost and help achieve parity.

In parity scenario 2, base case estimates are maintained for all variables other than KES annual depreciation, which is increased to 8.4% throughout the analysis period. As depreciation spiked above this threshold in three distinct years throughout the period (2009, 2011, 2015) and has been far higher at times in Kenya’s history, this highlights a key risk of USD financing. Even moderate depreciation can quickly erode savings from low interest rates on USD financing, thereby making KES tariffs look more attractive.

Figure 16 below shows the impact of change in one variable between the maximum and minimum values experienced over the period25, while holding all others at the base case scenario. We find that:

• Local currency interest rate has the greatest effect considering the two sides of the base case scenario, underscoring the large range experienced in the analysis period, as well as the potential benefit of lower interest rates.

• Depreciation shows largest swing with the highest cost saving scenario, highlighting risk of depreciation with USD financing.

25 Depreciation capped at 0%, reflecting the low likelihood that the KES will appreciate against the USD over a 15-year period.

-62

-20

0

200

KES Depreciation

Interest Rate USD

Interest Rate KES

KES transition savings

12.1% 12.3% 9.4%

Parity2.0%

8.4%

9.1%

9.1%

10.3%

13.7%

Base case scenario

2.0% 9.1% 13.7%

KES transition expense

0% 7.6% 16.4%

1

2


31

Figure 16: Sensitivity of cost savings to changes in variables (Percent)

RESULTS WITH REAL VALUES

The table below shows the results of converting interest rates and exchange rates to real values from nominal values.

Year

Kenya US Annual Fx Rate KES/USD

Kenya inflation KES real

(base 2002) US inflation USD real

(base 2002) Nominal Real

(base 2002)

2002 Base year 100.00 Base year 100.00 78.93 78.93

2003 9.82% 109.82 2.27% 102.27 75.82 70.61

2004 11.62% 122.58 2.68% 105.01 78.44 67.20

2005 10.12% 134.98 3.39% 108.57 75.57 60.78

2006 6.42% 143.64 3.23% 112.07 72.15 56.29

2007 4.27% 149.77 2.85% 115.27 67.47 51.93

2008 16.23% 174.08 3.84% 119.70 69.00 47.45

2009 9.39% 190.42 -0.36% 119.27 77.34 48.44

2010 3.97% 197.98 1.64% 121.23 79.26 48.53

2011 13.98% 225.65 3.16% 125.05 88.87 49.25

2012 9.64% 247.40 2.07% 127.64 84.52 43.61

2013 5.72% 261.54 1.46% 129.51 86.13 42.65

2014 6.88% 279.55 1.62% 131.61 87.92 41.39

2015 6.58% 297.93 0.12% 131.77 98.59 43.61

2016 6.30% 316.71 1.26% 133.43 101.50 42.76

Using real values in the analysis shows 10.8% lower financing cost in KES financing compared to USD financing, which translates into a saving of 1.8% of revenue, as shown in the figure below. Please note that the overall reduction in revenue is due to inflation-adjustment on the revenue. Capex is adjusted similarly.


32

Figure 17: Financing cost and revenue required to keep IPP returns constant, KES billion

The primary reason for savings are lower KES real interest rates compared to USD real interest rates. In KES, the average real interest rate over the period was 5.5%, whereas in USD, the average real interest rate was 7.0%. This is because of the high inflation experienced in Kenya, at 8.2% over the 15-year period, and comparatively much lower inflation in the US, at 2.1% over the same period.

FERFA ANALYSIS

Foreign Exchange Rate Fluctuation Adjustment (FERFA) is the monthly adjustment that Kenya Power adds to consumers’ power bill. It reflects the pass-through of costs incurred by Kenya Power due to fluctuations in the foreign exchange rate. In this section, we calculate the relevant FERFA charges billed to Kenyan consumers between 2002 and 2016. This calculation is separate from the retrospective analysis provided in the previous section.

THE METHODOLOGY

Kenya Power uses the FERFA adjustment to account for the following foreign currency expenditures (components):

• Foreign currency costs paid by Kenya Power to IPPs (except KenGen) due to sale of power

• Foreign currency costs incurred internally by Kenya Power

• Foreign currency costs incurred internally by KenGen, excluding sale of power

In order to calculate the costs associated with Kenya Power’s foreign currency payments due to sale of power, the calculation in this report is restricted to IPPs. In other words, we have not included FERFA amounts apportioned to Kenya Power’s and KenGen’s internal costs as they are not related to the sale of power.

Kenya Power internally sets an exchange rate known as the base rate to determine gains or losses due to forex changes. For each foreign currency transaction, Kenya Power calculates FERFA by comparing the value of the transaction at the base rate to the actual rate at the time of payment. In

USD financing

245

1919

40

185

-1.8%

240

-10.8%

KES financing

36

185

Returns Financing Cost



33

the period between 2004 (data available is from 2004) and 2016, Kenya Power had two base rates; KES 65 (= 1 USD) from 2004 to 2013, and KES 85 (= 1 USD) from 2013 to 201726.

The FERFA calculation using the base rate is illustrated in the figure below.

Figure 18: Use of base rates to determine gains / losses due to forex changes27

WHY FERFA ONLY DISPLAYS PART OF THE PICTURE

It is critical to note that FERFA considers only one aspect of HCY financing, i.e. the effects of depreciation of KES against USD, as shown in the figure below. FERFA does not consider potential savings of a USD tariff due to IPPs’ lower financing costs in USD as opposed to KES over the same period. On the other hand, the retrospective analysis considers both the counteracting forces of KES depreciation and interest rate differential. This is a limitation of FERFA in the context of this report. However, understanding and analyzing FERFA is useful for the study due to its visibility in the monthly power bills of consumers.

Figure 19: Limitation of FERFA analysis

26 There is a base rate for each foreign currency that Kenya Power incurs costs in, but the dollar is used here as it is the most commonly used foreign currency in Kenya Power’s operations 27 Source: Kenya Power

Base rate: KES 85

50

55

60

65

70

75

80

85

90

95

100

105

2002 2004 2006 2008 2010 2012 2014 2016

Actual Forexrate

Base rate

Base rate: KES 65

FERFA (amount above the base rate) between

2002 and 2013

FERFA (amount above the base rate) 2013

onwards

KES to USD rate

Due to any depreciation in KES

Due to any differential in interest rates in KES

financing over hard currency

Factor included in FERFA calculation

Factor excluded in FERFA calculation


34

THE RESULTS

Between 2002 and 2016, Kenyan consumers paid KES 20.5 billion under FERFA, as shown in the figure below. The value of FERFA increased over time because: (i) power purchases have increased, and (ii) the KES depreciated, i.e. the amount paid above the base rate increased within the same period. While fluctuations have occurred due to the variation of forex rate, the low FERFA value in 2014 is due to upward revision of the base rate in 2013.

Figure 20: FERFA values, 2002-2016, KES billions

28

Table 7: FERFA per customer per year

Customer segment FERFA per customer per year

Domestic KES 264

Small Commercial KES 1,486

Commercial and Industrial KES 247,169

ASSUMPTIONS AND DATA USED

• Monthly FERFA data from Kenya Power

• FERFA data is available from 2004 onwards. We estimated FERFA values in 2002 and 2003 using the compound annual growth rate (CAGR) of the values in subsequent years

WIDER BENEFITS ASSOCIATED WITH LOCAL CURRENCY FINANCING

As can be seen, depending on interest rate and currency exchange rate movements in a given period, KES tariffs may be more or less expensive than USD tariffs. In the past 15 years, we estimate that KES tariffs would have been marginally more expensive (5%) to the Kenyan consumer. However, there are wider benefits that should be considered alongside this perspective.

BENEFITS OF LOCAL CURRENCY FINANCING

INCREASE DOMESTIC INVESTOR PARTICIPATION / REPATRIATION OF RETURNS

LCY tariffs, which would require sourcing capital in KES for projects, would allow for more domestic investor participation (e.g. through pension funds and insurance companies), who will in turn benefit from sector returns and a more diversified portfolio. As of today, few domestic investors are

28 Source: Kenya Power

0.3

20162007 2015

1.0

2002

2.9

3.2

2.3

20122011 20132009

1.0

1.5

2014

2.6

20102008

3.0

0.6 0.7

2006

0.5

2005

0.30.5

2004

0.1

2003

Base rate: KES 85Base rate: KES 65


35

participating in and benefiting from returns in the power sector through the domestic capital markets – see chapter 4 for further details. This is due to limited channels for participation (and a tariff regime that leads to USD financing over KES financing), rather than a lack of appetite on the part of domestic investors. Apart from corporate bonds issued by KenGen and private equity investment into single projects, there are currently no other ways for domestic institutional investors to invest into the power sector. As a result, most returns to the sector accrue to foreign investors. A local currency regime would promote greater domestic investor participation and repatriate power sector returns onshore. This ultimately facilitates productive recycling of savings locally, increasing liquidity in financial markets while contributing positively to economic growth.

PROVIDE AN ALTERNATE AND LONG-TERM SOURCE OF FINANCING

As previously mentioned, historically DFIs have dominated power project financing in Kenya. However, as Kenya transitions into a lower-middle income country, DFIs’ are likely to reduce their investments in the country over the coming years. In addition to this, some DFIs willing to fund in LCY would play a critical support role for commercial financiers in Kenya. The DFIs’ support towards local commercial financing of power projects would be helpful for long-term sustainability of the sector and eventual withdrawal of development financing.

REDUCE RISK EXPOSURE TO SUDDEN SHOCKS

HCY financing exposes Kenya Power and the Kenyan consumer to external shocks and fluctuations in the value of the KES. Kenya has experienced fluctuations in the value of KES, e.g. devaluing up to 12% three times in the last 15 years, even though the average depreciation has been low. As a result, there is significant downside risk if the KES does come under pressure in a USD tariff regime, which would be avoided under a KES tariff regime. To illustrate the severity of the potential downside risk, one can point to the Asian financial crisis in the late 1990’s. Several of the ‘tiger economies’ experienced sharp currency depreciation, which led to a rise in public liabilities in USD29, with national utility debt reaching as much as one-third of GDP in the Philippines. In Africa, Nigeria and Egypt have experienced similar shocks in recent years. Therefore, switching to KES tariffs eliminates such risks, avoids price increases that must be absorbed by the Kenyan consumer in tough macroeconomic times, and makes the Kenyan power sector and economy at large more resilient to external shocks. It also reduces fluctuations in the power bills, allowing consumers to better plan their budgets.

FACILITATE CAPITAL MARKETS DEVELOPMENT

Increased use of LCY financing will contribute to deepening of domestic capital markets, and improve financing terms for the sector. Studies have shown that capital market deepening has a positive effect on GDP growth in Kenya30. The oversubscription of KenGen’s bond in 2009 demonstrates the high appetite for LCY investment into the power sector. Increasing use of such LCY products will establish benchmarks in the capital markets and encourage financial institutions to launch other LCY products. Pension and insurance regulators could allow investments in new asset classes for their industries, which could lead market actors to build expertise in these asset classes, diversify their investments and potentially earn higher yields.

PROMOTE LOCAL INDUSTRY AND LABOR

Borrowing in local currency will incentivize developers to find new ways to source locally, helping in economic diversification and job creation. Considering the equipment required in power projects, while constituent parts of those equipment may still be imported in the coming years, it is easier to assemble them locally. Such efforts could help build domestic capacity to serve the power sector.

29 The crisis was caused by Thailand’s decision to float their currency, which was pegged to the USD. Thailand had lack of foreign currency to support the peg. The crisis eventually spread to other countries in the region. 30 Effect of Capital Market Deepening on Economic Growth in Kenya, University of Nairobi, 2013


36

SUPPORT THE WIDER ECONOMY

Development of capital markets benefits wider economy. Strengthening of the local financial sector will help reduce the need to borrow offshore and thus contribute to reducing the currency mismatches benefitting the overall economy. Moreover, reducing hard currency liabilities of the Kenyan government will lead to low currency risk exposure for the Treasury. Kenya’s public debt has risen sharply in the last few years, from 44% of GDP in 2013 to 53.1% of GDP in 201631, putting greater pressure on the KES. If depreciation of the KES were to sharply increase, a LCY regime would result in a significant cost savings to the Kenyan consumer. Thus, efforts to introduce local currency financing using domestic capital markets should start now and develop over time.

CONCLUSION

Although the retrospective analysis shows KES tariffs resulting in a marginal cost increase to the Kenyan consumer over the past 15 years, we believe it is a proposal worth pursuing further because (i) the costs increase could have conceivably been a costs savings under different macroeconomic circumstances and (ii) there are several wider benefits of a LCY regime in the long run.

31 Source: National Treasury, GoK; IMF


37

4. WHAT IS THE AVAILABILITY OF LCY FINANCING AND HOW WOULD LCY-DENOMINATED PPAS IMPACT INVESTORS?

OBJECTIVES OF CHAPTER

This chapter confirms the viability of local currency (LCY) financing, and the bankability of LCY-denominated PPAs, from a supply side (financiers) and demand side (developers) perspective. It draws on market sizing analysis and interviews with over 40 market actors, including: (i) financiers – banks, pension funds, insurance companies, fund managers, DFIs; (ii) developers – both local and international; and, (iii) public sector actors. The full interviewee list is provided in the Annex.

Specifically, this chapter presents findings on:

• The supply side:

o The estimated amount of available domestic capital – primarily from commercial banks, pension funds and insurance companies – that could in principle be allocated to power projects in the 10-year period 2018-2027.

o The opportunities, challenges, and constraints for different types of financiers – commercial banks, pension funds, insurance companies, fund managers and DFIs - to finance power projects in LCY.

• The demand side:

o The estimated amount of financing required by IPPs to finance additional installed capacity planned in Kenya up to 2027.

o The opportunities, challenges, and constraints for IPPs to enter into a LCY-denominated PPA, and secure and service LCY financing to finance their projects.

• Bridging supply and demand: How the supply of LCY finance matches up to the demand for financing, and the main drivers that will facilitate or constrain LCY deals in the sector.

SUPPLY OF LCY FINANCING ACROSS FINANCIERS

OVERVIEW

Based on our market sizing, the maximum LCY financing available for power projects over the next 10 years (2018-2027) is estimated at KES ~4,450 billion. This figure includes both debt and equity financing. Whilst this capital could all be made available for power projects, in reality there are other sectors (e.g. transport) that will compete for it. The high-level approach used for each investor type is listed below (the detailed methodology is described in subsequent sections).

• Banking sector: The estimate is based on assets held in LCY and the limits on exposure to the power and infrastructure sector by the top 10 banks in the country by assets.

• Pensions sector: The current regulatory limits were used to estimate the available financing for power projects, comprising: listed bonds (20%), unlisted bonds (10%), unlisted shares (5%), private equity and venture capital (10%), and any other asset classes (10%).

• Insurance sector: The current allocation to unquoted equities (10%), corporate bonds (10%), and secured loans (10%) was used to estimate available financing for power projects, with an adjustment made based on the proportion of assets managed by life insurance (long-term investments) over general insurance (short-term investments).


38

For all sectors, growth was estimated based on average growth rates of the last five years32.

Figure 21: Estimated LCY financing available for power projects over 2018-2027, KES billion

FACTORS SUPPORTING LCY FINANCING ACROSS INVESTOR TYPES

There are numerous factors that support LCY financing, many of which are common across different investor types, with some being specific to certain types.

• Substantial availability of LCY financing: The banking, pensions, and insurance industry have the capacity to provide KES 4,450 billion to the power sector over the next 10 years, considering existing regulatory requirements that govern how they can invest.

• Increasing allowance for alternative asset classes by regulators: In recent years, regulators have increased the allocations for alternative asset classes to allow for diversification of investments. For instance, in 2015 private equity and venture capital was listed as a new asset class by the Retirement Benefits Authority (RBA), with an allowance of up to 10% of total investment. Real Estate Investment Trusts (REITs) have also been added, with an allowance of up to 30% of total investments. While there is no specific allocation for power and infrastructure assets yet, it is under consideration. Currently, power investments can fall under a range of asset classes including listed corporate bonds, unlisted bonds, unlisted shares, private equity and venture capital, and any other assets.

• Latent demand for alternative assets among institutional investors in Kenya: Banks, pension funds, insurance companies, and asset managers are seeking to diversify their investments, and express a desire to invest in power projects. There are a few pension funds, such as Kenya Power Pension Fund, which have already invested in IPPs (via direct equity investment). Also, several pension funds invested in the KenGen bond issue in 2009 and recently, a South African fund bought KenGen shares on the Nairobi Securities Exchange.

• Increasing understanding of the power sector, even though it can still improve: While knowledge of the power sector among local financiers is currently low, it continues to increase as more transactions are executed. Local financiers are learning to evaluate and structure investments in the sector more effectively and efficiently.

• Openness to currency matching: Local financiers are more willing to provide LCY financing when it matches the currency of IPPs’ revenues.

32 For commercial banks, the latest data available is until 2016, hence the period 2012-2016 was used for the estimate. For pension funds and insurance companies, the latest data available is until 2015, hence the period 2011-2015

4,450650

3,000

800

Pension funds

TotalCommercial banks

Insurance companies


39

FACTORS CONSTRAINING LCY FINANCING ACROSS INVESTOR TYPES

While there is interest in LCY financing, there are also constraints affecting the willingness and ability of financiers to lend into the power sector:

Factors specific to LCY financing:

• Opportunity cost of investing in power projects: Local financiers can invest in government bonds for attractive absolute returns, e.g. the five-year government bond yield has been 12.4% on average over the last 5 years, while that of the 10-year bond has been 12.9%. This sets a high return expectation for financiers looking to divert funds from risk-free investments to the power sector, as pricing expectations will be based on treasury bonds as the benchmark, with 200-300 basis points added as a proposed premium.

• Risk pricing challenges due to recent market events: Fund managers are facing challenges pricing the risk of power projects; this is driven by uncertainty in the banking sector due to the interest rate cap introduced in 2016. Additionally, a few banks were placed in receivership in the country, and had outstanding corporate bonds, which fund managers were holding in their portfolios. This has resulted in increased risk aversion among fund managers.

• Conservative nature of institutional investors: Pension funds, insurance companies and their trustees often have investment policies that limit investments into non-traditional asset classes. For example, whereas pension funds are permitted invest up to 10% of assets in private equity, current allocations are lower than 1%.

Factors affecting financing regardless of currency denomination:

• Limited project finance capability among local financiers: Apart from certain banks and fund managers, local investors have limited experience executing project finance deals, making it time-consuming and difficult to complete transactions.

• Technical capacity and execution skills of inexperienced IPPs: Lenders indicate developers’ lack of experience as a constraint, citing bad experiences with developers committing errors relating to land issues, environmental and social risks, and technical failures. This has resulted in some reservations around financing projects, and a higher bar to making investments.

• Concern / ambiguity over policy: In particular, there is wariness surrounding land issues, as some risks have materialized in recent projects. Financiers are concerned about potential conflict between local communities and IPPs, with some expecting the government to play a stronger role in streamlining land issues for IPPs to encourage investment.

• Tenor of loans: Local banks primarily source their funding from deposits which are short-term in nature; It is usually a challenge to source long-term capital in both LCY and HCY; hence, it is difficult for them to provide a tenor of more than e.g. 7 years, unless they can access a credit guarantee to extend the tenor. DFIs are not constrained in this way and offer longer tenors than local banks, one of the reasons why they have been the major providers of debt into the power sector in Kenya. More recently, they are also providing finance and credit enhancements to local banks in order to allow them to provide longer tenors. For example, Agence Française de Développement (AFD) is working with 4 local banks to make long-term financing available through its SUNREF program.

COMMERCIAL BANKS IN FOCUS

At the end of 2016, the Kenyan banking sector had assets of KES 3.7 trillion and gross loans of KES 2.3 trillion33, driven by the growing demand for credit. The value of gross loans increased at a

33 Source: Central Bank of Kenya


40

compound annual growth rate of 15% per annum between 2012 and 2016, as shown in the figure below:

Figure 22: Historical values of gross loans by sector (KES billions)34

For our analysis, data of the top 10 banks by assets was used based on the assumption that these banks are the mostly likely to invest in power projects (accepting that smaller banks may also invest). On average, 76% of the assets of commercial banks are held in LCY, indicating sizeable capacity for LCY lending. The financing available to the power sector was estimated by taking this split between LCY and HCY loans, and the average sector exposure limit set by banks for the power sector of 15%. Between 2012 and 2016, banks lent 10% of total loans into sectors that typically absorb long-term debt – energy, water, building, construction and mining – with 3-5% of these going specifically to energy and water.

34 Central Bank of Kenya Bank Supervision Annual Reports and Financial Stability Reports

236(10%)

294(14%)

551(25%)

585(25%)

358(16%)

202(9%)

222(10%)

2,293

2016

2,165

1,972

266(12%)

267(12%)

+15%

439(19%)

208(9%)

424(20%)

223(10%)

185(9%)

241(12%)

408(26%)

155(10%)

264(20%)

177(13%)

154(8%)

522(26%)

180(14%)

197(10%)

1,579

204(13%)

109(7%)

327(25%)

149(11%)

99(7%)

190(10%)

223(14%)

317(20%)

287(15%)

381(19%)

163(10%)

1,330135

(10%)

2013 20142012 2015

Agriculture, tourism and financial services

Energy, water, building, construction, & mining

Transport & communication

Trade

Real Estate

Manufacturing

Personal/Household


41

Figure 23: Estimation of LCY financing available for power from the banking sector in 2016, KES billion

Gross loans of the banking sector grew on average at 15% year on year from 2012 to 2016. This growth rate was used to forecast the availability of LCY financing during the period 2018 to 2027. We estimate that KES ~800 billion in LCY financing is available for power projects over the next 10 years (2018-2027), as shown in the figure below. While this financing could go to the power sector, other sectors will compete for it, especially other infrastructure projects in roads, rail, water, etc.

Figure 24: Estimation of financing available for power projects from 2018 to 2027 (KES billions)

COMMERCIAL BANKS’ PERSPECTIVES ON LCY FINANCING OF POWER PROJECTS

Banks express interest in providing LCY financing, with several banks having already provided finance to the power sector either to government affiliated entities like KenGen and Kenya Power, or to IPPs – majority in HCY, with some LCY tranches. Several banks indicate that they both have the capacity and the willingness to fund deals in LCY, depending on their bankability. Each of the top three

Top 10 banks by gross loans

1,605

Other banks

Distribution of loans between top 10 banks and others

24%

76%

Exposure limit to power sector

Other sectors

Power sectorexposure limit

85%

1,204

15% KES 181 billion

KES 1027 billion

HCY

2,293

LCY

Distribution of loans by currency

30%

70%

202720192018 2023 2025 20262024202220212020

90

Total

103

811

60

69

238

79

3540

46

52

Growth of gross loans


42

commercial banks in the country have a Single Obligor Limit of up to USD 200 million in LCY equivalent, indicating that most power projects can be financed, with syndication required only for very large projects. In the last 15 years, nearly all projects would have received debt financing with that limit. Many banks have their own internal limits on exposure to a sector, which ranges from 8% to 25% of total assets. However internal approvals to exceed the limits can be obtained if an attractive deal exists. In particular, the larger foreign-owned and leading Kenyan banks noted that they prefer larger deals, given scale efficiencies in project execution and that these deals tend to be higher priority for GoK with accelerated pathway to PPA signing.

While there is appetite for LCY lending from banks, the terms they seek differ from what is available in HCY financing. In LCY, banks will charge interest at the capped rate of 14% per annum, and likely higher if the interest cap was removed. While this may come down with de-risking measures such as guarantees, interest rates in LCY financing will be higher than HCY financing. Tenors also vary, with longer maturity periods available in HCY. If the deal is structured attractively, the larger banks are willing to offer up to 10-year tenors in LCY. The financing terms are shown in the table below:

Table 8: Financing terms from commercial banks in HCY and LCY

Currency Interest rate Tenor

HCY DFIs typically charge LIBOR+5%, with commercial banks charging roughly LIBOR+7%.

Up to 10 years is available, while there is appetite to go up to 15 years among DFIs and larger banks.

LCY Currently capped at 14%, as per the regulation. Without the cap, the rate would be 200-300 bps above the 10-year Treasury bond rate.

Usually 3-7 years, though up to 10 years is available from some banks. Any further increase (between 10 and 15 years) is possible with a tenor extension guarantee.

FACTORS RAISED BY COMMERCIAL BANKS IN SUPPORT OF LCY FINANCING OF POWER PROJECTS

There are certain factors that commercial banks cite in favor of an increase in LCY financing:

• Local banks have significant deposits in LCY: Majority of local banks’ assets are in LCY, therefore lending in the same currency would reduce the risk of currency mismatch.

• Funds sitting in government bonds can be redirected elsewhere: After the rate cap was introduced, banks have reduced lending and directed funds instead to government bonds. This is available to redirect into the power sector where an attractive deal can be structured.

• USD financing is becoming gradually more expensive: Certain banks mentioned that their cost of sourcing USD financing is steadily going up, as LIBOR has more than doubled in the last two years, which makes the prospect of LCY financing increasingly attractive. At the same time, as the Kenyan financial sector matures further over the coming years, KES interest rates may trend downwards.

FACTORS RAISED BY COMMERCIAL BANKS AS CONSTRAINING LCY FINANCING OF POWER PROJECTS

Despite the overall interest, there are varying levels of risk perception of the power sector.

• Tenor mismatch: Power projects typically require longer dated funding (preferably 15 years) given their lifecycle; however, LCY financing is preferred by commercial banks in shorter tenor (3-7 years). Some banks have expressed interest in refinancing the debt as a solution to the tenor mismatch. While tenor mismatch can also be an issue for HCY financing, it has not been an issue in Kenya due to historic dominance of DFIs (who are able to offer longer tenors). As mentioned


43

already, this status quo is likely to change as (concessional) finance from DFIs into Kenya’s power sector diminishes over time.

• Limited capacity in project finance: Banks have varying levels of comfort with project finance, as their experience is primarily in traditional corporate finance.

WHAT IT WOULD TAKE TO MOBILIZE MORE COMMERCIAL BANK FINANCING IN LCY

Considering these perceived risks, banks would like to see certain de-risking measures in place to incentivize lending. Some examples below (provided in detail in Chapter 6):

• Guarantees or tenor extension, e.g. a full risk guarantee between the 10th and 15th year of a loan.

• Credibility of sponsors and partners – Having credible and experienced sponsors is important to make a project more bankable. Additionally, having reliable partners (in terms of EPC and O&M capabilities), as well as government support, increases investor confidence.

• Loan structure: Syndicating loans, to other banks or to DFIs, reduces commercial bank risk exposure. For instance, a bank with limited project finance capacity may participate in a club deal of a syndicated loan with other institutions, that have demonstrated stronger risk analysis and due diligence skills when valuing a potential transaction or asset. Another risk reducing measure is by structuring an amortizing loan.

PENSION FUNDS IN FOCUS

By the end of 201535, the Kenyan pension fund sector had assets of KES 814 billion, with the industry’s assets growing at a compound annual rate of 17% between 2011 and 2015. This growth was driven by several factors, including a growing workforce, and increased uptake of corporate and personal pension plans. The new National Social Security Fund (NSSF) Act has also widened pension coverage by mandating all Kenyan employers and employees to make stipulated contributions.

Figure 25: Historical values of assets by investment type (KES billions)36

35 RBA Annual Report 2015, the latest official data available. 36 Source: RBA Annual Reports

788

242(31%)

208(26%)

130(17%)

94(12%)

181(26%)

120(17%)

71(10%)

65(9%)

24(3%)

2012

190(23%)

151(19%)

99(12%)

104(13%)

28(3%)

2014

97(22%)

88(20%)

48(11%)

43(10%)

12(3%)

+17%

2015

814

242(30%)

54(10%)

21(4%)

2011

433

146(34%)

549

190(35%)

134(24%)

102(19%)

48(9%)

88(11%)

25(3%)

2013

697

235(34%)

Government Securities

Quoted and unquoted Equities

Immovable Property

Guaranteed Funds

Fixed income and fixed deposits

Other

“Other” includes: cash, offshore investments, unclassified

investments, and private equity


44

Investments into IPPs could fall under the following categories: corporate bonds, unlisted bonds, unlisted shares, private equity, and any other assets. For pension funds, RBA has prescribed limits under each asset class, as shown in the table below. Rows highlighted in grey indicate the asset classes under which power sector investments can feasibly fall, which totals to 55% of overall pension assets.

Table 9: Regulatory limits set by the RBA on various asset classes37

Asset class Regulatory limit (%)

Cash and demand deposits 5

Fixed deposits, time deposits 30

Listed corporate bonds, mortgage bonds 20

Commercial paper, non-listed bonds 10

Government securities and infrastructure bonds 90-100

Preference shares and ordinary shares 70

Unlisted shares 5

Offshore investments 15

Immovable property in Kenya 30

Guaranteed Funds 100

Approved exchange traded derivatives 5

Listed REITs 30

Private equity and venture capital 10

Any other assets 10

The pension industry grew at a compound annual growth rate of 17% between 2011 and 201538, which was used to project the likely growth over the next ten years. This leads to a figure of KES ~3,000 billion available to the power sector over the next 10 years between 2018 and 2027. Other sectors will compete for these funds, especially roads, water, railways, etc.

Figure 26: Estimation of pension fund assets available to the power sector (KES billions)

PENSION FUNDS’ PERSPECTIVES ON LCY FINANCING OF POWER PROJECTS

As discussed above, pension funds can use several channels to invest in power projects and are looking for ways to diversify their investments while preserving capital. They are interested in pursuing power deals if returns are attractive, and risk is appropriately mitigated. Pension funds

37 Source: RBA 38 The most recent data on the pension industry’s assets is for 2015

197

231

271

317

371

435

2,977

719

2020

144

2019 2022

123

2018 2021

169

Total20272023 2024 20262025

Growth of capital (at growth rate)


45

particularly highlighted the need / desire for investment vehicles that would allow them to invest in the power sector.

FACTORS RAISED BY PENSION FUND AS SUPPORTING LCY FINANCING OF POWER PROJECTS

• Need to diversify investments away from government bonds and listed equities: Fund managers are keen on finding higher yield investments, which is driven by the underlying issue of listed equities underperforming during the last few years. In addition, they want to diversify risk and achieve long-term steady returns. Pension funds can invest in listed bonds of IPPs, as there are no regulatory restrictions, and several funds have had experience investing in the KenGen bond.

• The long investment period of power projects aligns with pension fund objectives of matching assets and liabilities: Pension funds are required to pay out pensions in the long-term and are therefore better suited to participate in power deals that require financing on 10 years or longer.

• Enhancing risk-adjusted returns: Although conservative in their investments, pension funds have expressed interest in participating in power projects post-construction and capitalizing on the risk premium that such an investment could offer in comparison to e.g. a government bond.

FACTORS RAISED BY PENSION FUND AS CONSTRAINING LCY FINANCING OF POWER PROJECTS

• Perception of high risk in power projects: The construction risks inherent in power projects can deter long-term investors whose mandate is to preserve wealth. Thus, their risk appetite remains low. Pension funds consider pre-construction risk to be high, and more acceptable once the project is operational and generating revenues.

• Expectation of higher returns: Given the risk perception and preservation of wealth mindset, pension funds expect investments to provide an attractive premium above government bonds, which are considered risk-free. The average yield for the five-year government bond over the last five years was 12.4%. For pension funds to divert funding from a risk-free investment, without any credit enhancement, they would need to receive a premium, e.g. 200-300 basis points above the yield of a long-term government bond.

• Limited understanding of power sector: High upfront costs, lack of liquidity, and a long investment period for power projects requires substantial resources and advanced power sector experience to understand the risks as well as how to manage them. We found that these resources and experience was limited among pension funds as well as with some fund managers.

• Power is a long-term investment, which is in principle aligned with pension fund investment horizon; however, pension fund management may not be aligned to long-term. Trustees and fund managers are not particularly incentivized for long term or alternative investments. The regulatory requirement for regular pricing / rebalancing of pension fund portfolios discourages investment in unquoted instruments. Additionally, trustees are elected at regular intervals (e.g. 3 years) and therefore need to show performance over shorter periods of time. Fund managers are appointed for 3-5 year contracts, and alternative assets are sometimes not included in their fee arrangements. In such cases, fund managers have low incentive to invest in alternative assets, and they continue to pursue standard investment channels i.e. listed bonds and equities.

• Pension funds lack appropriate vehicles for power sector investments: While there is appetite among pension funds to diversify their portfolio, currently only corporate and government bonds and direct equity investments are available to them. The process of issuing a corporate bond places more costs on an IPP than traditional sources of debt, and only few pension funds have executed private equity investments. If the capital markets were to develop new products, such as asset-backed securities (e.g. those backed by future cash flow generating assets, such as power projects) that can be listed on the Nairobi Securities Exchange, more pension funds may be attracted into the sector. If designed appropriately, such a product would provide both a steady yield and a liquidity option in the secondary market. The Capital Markets Authority (CMA) has


46

recently developed an asset backed securities framework, which should help facilitate these products into the market.

WHAT WOULD IT TAKE TO MOBILIZE MORE PENSION FUND ASSETS INTO THE POWER SECTOR?

Pension funds indicate that certain factors would increase their ability to invest more actively in power projects.

• Investing in project bonds: Pension funds are permitted to invest in project bonds, which are either publicly listed or unlisted; the issuer could also have the bonds credit rated. Pension funds were one of the biggest investors of the KenGen bond issue, reflecting their interest in the power sector if structured appropriately. For credit rated bonds, CMA guidelines require rating by an approved credit rating agency, with the IPP having minimum three years in operation, with minimum two years of profits. Investors could discuss workarounds to these requirements with the CMA, who may grant exemptions on a case by case basis.

• Trustee sensitization: While fund managers may be open to alternative asset investments in the power sector, they need the buy-in of trustees to effect this. For this reason, it is necessary to sensitize trustees on the nature of power projects; risk and return profile and project finance to increase confidence in power investments.

• Incentivize fund managers to advise on power sector investments. Most contracts with fund managers currently incentivize fund managers to invest in the traditional asset classes (e.g. listed equities, bonds), even after increase in regulatory limits for alternative assets. Fund managers’ incentives should be optimally structured to align with inclusion and performance of alternative assets. RBA can issue guidelines on contract structures to ensure such incentives are included.

INSURANCE COMPANIES IN FOCUS

The Kenyan insurance market is small but growing rapidly. While Kenya is the largest insurance market in East Africa, accounting for 68% of total premiums in the region, insurance density remains low at USD 38 per capita, with insurance penetration at 3% of GDP39. However, growth prospects remain positive. Kenyan investment in infrastructure projects will create more demand for insurance coverage, and rising foreign investor interest has increased industry capitalization.

By the end of 2015, the Kenyan insurance sector had assets of KES 430 billion, KES 390 billion of which were held in income-generating assets. Of these, life insurers held 64% (KES 249 billion). Industry assets have increased at a compound annual rate of 19% per annum between 2011 and 2015, as shown in the figure below:

39 Insurance density: Premiums per capita; Insurance penetration: Total premiums as % of GDP


47

Figure 27: Historical values of assets by investment type (KES billions)40

For insurers, the asset classes under which investments into IPPs could fall are unquoted shares, corporate bonds, and secured loans. Given regulatory constraints and long-term nature of power sector investments, it is assumed that only life insurers are able to invest. As of 2015, we estimate that the sector has KES 75 billion available for power sector investments, as shown in the figure below.

Figure 28: Estimation of insurance sector assets available for power projects in 2015

Projecting out at the current industry average growth rate of 19%, we estimate that KES ~650 billion will be available to the power sector over the next 10 years (2018-2027). Other sectors will compete for this capital, especially infrastructure projects planned for roads, water, railways, etc.

40 Source: Insurance Regulatory Authority Annual Reports; Latest data available for 2015

63(18%)

37(10%)

2013

296

122(41%)

43(14%)

50(17%)

54(18%)

28(9%)

28(15%)

19(10%)

169(43%)

60(15%)

35(18%)

69(18%)

41(11%)

2014

390

51(13%)

+19%

2015

139(39%)

57(16%)

60(17%)

2012

240

95(40%)

44(18%)

41(17%)

39(16%)

20(9%)

2011

192

77(40%)

33(17%)

355

SharesOther

DepositsInvestment property

Government and other Securities

Shares category includes both quoted and

unquoted shares

70%

10%

10%

10%Unquoted equities

Listedcorporate bonds

Secured loans

Maximum allowances

for applicable asset classes

249

Sum of otherasset classesLife insurance 64%

390

36%

Distribution between long term and

general insurance investments

General insuranceKES 75 billion

KES 174 billion


48

Figure 29: Projection of insurance assets available to the power sector, KES billions

INSURANCE COMPANIES’ PERSPECTIVES ON LCY FINANCING OF POWER PROJECTS

Considering that insurance companies take risk on the insurance side, they usually minimize it on the investment side. Managers of Kenyan insurance companies point out two major objectives of their investments: (1) ensuring sufficient cash flow to pay claims as they become due; and, (2) protecting value of assets. Insurance companies in the country have followed these objectives and pursued a low-risk, low-return investment strategy, which has led to investments in safe asset classes. Hence, their investments are generally more risk-averse than those of pension funds.

Given the above dynamics, Kenyan insurers have few investments in alternative assets, other than real estate. Fixed income instruments, primarily government securities, deposits and real-estate make up most of the assets under management.

FACTORS RAISED BY INSURANCE COMPANIES AS SUPPORTING LCY FINANCING OF POWER PROJECTS

At the same time, Kenyan insurance companies are seeking ways to diversify their investments within the regulatory parameters. Expanding into power sector investments, which are largely unaffected by short-term market fluctuations, can provide the much-needed diversification.

FACTORS RAISED BY INSURANCE COMPANIES AS CONSTRAINING LCY FINANCING OF POWER PROJECTS

The relatively long tenor and lack of liquidity in power sector financing (with the exception of listed bonds) may constrain widespread insurance sector participation. Insurers emphasize the importance of matching asset maturity with liabilities. While life insurance companies have longer-term liabilities, shorter term general insurers find a mismatch with longer investment periods in the power sector. Life insurance premiums are growing at a faster rate than those of general insurance, however they are still only one-third of total premiums in the sector.

WHAT IT WOULD TAKE TO MOBILIZE MORE INSURANCE ASSETS INTO THE POWER SECTOR?

Most of the actions required to increase assets mobilization from pension funds apply to insurance assets as well, i.e. sensitization and capacity building of fund managers, specific allocation for power & infrastructure by the regulator, etc. In addition, interviews revealed that insurance companies require a structured, de-risked investment product to channel their interest in power sector exposure. Other options include purchase of IPP equity after a few years of successful operation, purchase of bonds used to refinance existing IPP debt, etc.

25

2026 Total

106

74

89

2024 2025

62

647

20272020

52

2021

36

2023

43

2022

30

2018

128

2019

Growth of capital (at growth rate)


49

DEVELOPMENT FINANCIAL INSTITUTIONS IN KENYA

Development finance institutions (DFIs) are key players in Kenya’s power sector, providing both equity and debt. DFIs have been well suited to provide equity as it has been perceived as high risk for local institutional investors, and the market has relatively fewer large local equity investors. The expected equity return (IRR) in HCY is flexible, with the norm being 14%-18% for developer returns and 8%-12% for financial investors once the asset is operational. Many DFIs also provide debt to IPPs, including KfW, Proparco, IFC, DEG, FMO and AfDB. Debt from DFIs is generally cheaper than debt from local banks (LIBOR + 5%, or as low as 3% in concessional financing). In addition, DFIs lend for longer tenors than banks, with tenors of up to 15 years, which matches IPP requirements.

DFIs also provide HCY debt to local banks to on-lend to IPPs. This reduces DFIs’ due diligence / transaction costs and utilizes the better reach of banks. In such cases, banks add a premium over their cost of borrowing to cater for the administration costs.

Table 10: Examples of investments into IPPs in Kenya by DFIs

IPP DFI investor Type of investment

OrPower4 OPIC Debt

Tsavo IFC Equity and debt

CDC, DEG Debt

Rabai FMO, IFU Equity

FMO, Proparco, DEG Debt

Thika AfDB, IFC Debt

Gulf IFC, OPEC Debt

Turkana AfDB, FMO, DEG, TDG Debt

DFIS’ PERSPECTIVES ON LCY FINANCING OF POWER PROJECTS

Some DFIs have exposure to LCY financing in Kenya and other countries in Sub-Saharan Africa, however it has been limited and mostly outside the power sector. These DFIs include AfDB, IFC, Proparco and Norfund. IFC and AfDB can raise LCY by issuing bonds in the domestic capital markets. They can also provide LCY financing by using hedging instruments such as currency swaps, although this often makes their debt unattractive in the market unless they absorb the cost of the hedge.

While DFIs have historically been the major financier of Kenya’s power sector, their contribution is expected to decrease in the near to medium term. Several factors will drive this trend, primarily: (1) DFIs already have considerable exposure to the country’s power sector and need to diversify; (2) Kenya’s status as a Lower Middle-Income Country41 means that DFIs will be less able to provide concessional finance to projects in the country; and, (3) DFIs perceive the power deficit (and overall need) in Kenya to be lower than many other sub-Saharan African countries, leaving a case to focus their investment elsewhere.

While DFIs support LCY financing overall, they expressed a few concerns.

• HCY accounts for the major portion of a project cost, which is unlikely to change: With HCY accounting for more than 50% of project costs in most technologies (project cost includes land, licensing, equipment, services), largely due to import of equipment, the mismatch

41 Kenya was graduated to Low-Middle Income Country (LMIC) status by the World Bank in 2015; its status as LMIC under the Development Assistance Committee of the OECD is also expected to change in the near term


50

between project costs and financing currency could put IPPs in a weak position. Currency forward contracts or hedges during construction period can mitigate the risk at a nominal cost.

• Interest rate risk, especially with commercial banks: LCY financing would leave IPPs and their investors susceptible to sudden changes in interest rates in the Kenyan market, i.e. a sudden change in the banking law which would cause the availability of financing in the market to decrease. The risk applies mainly to commercial banks, as pension funds can do fixed rate financing. HCY is susceptible to such changes as well, however is more agreeable to fixed interest rate for longer tenors.

POTENTIAL ROLE OF DFIS IN A LCY ENVIRONMENT

Most DFIs have an institutional mandate to deepen capital markets in their countries of focus, including Kenya. As such, they have an important role to play in facilitating LCY lending:

• As co-investors with local financiers: Local financiers expressed willingness and comfort to invest alongside DFIs in financing projects, as they would benefit from DFIs’ thorough due diligence processes.

• In blended structures: DFIs could provide concessional finance for LCY-financed projects (either alongside or through local financiers) to blend the LCY interest rate down at or close to the HCY interest rate the developer would have accessed if the project were financed in HCY.

• Through credit enhancements – DFIs could (and do, in some cases) provide credit enhancements to LCY financing through guarantees, which can help to stretch out tenor and / or bring down cost of financing. There has historically been more guarantee support available for HCY financing, with GuarantCo being an exception on the LCY side.

DEMAND FOR LOCAL CURRENCY FINANCING

Electricity consumption per capita in Kenya currently stands at 167 kWh per annum, well below the world average of 3,12842 kWh per annum. With an installed generation capacity of 2,336 MW, Kenya’s electricity demand is expected to grow along with increased grid access and sustained economic development. According to the Development of a Power Generation and Transmission Master Plan, Long Term Plan 2015 – 2035, electricity demand growth will require a peak load of 6,171 MW by 202743.

Taking out the expected generation capacity of 2,648 MW by 2018, this will require an additional capacity of 3,523 MW. Using as an assumption an investment cost of USD 2 million per MW44, this results in an estimated investment need of KES ~725 billion45 between 2018 and 2027. Assuming a capital structure of 70/30 split between debt and equity, power projects in Kenya could potentially absorb KES 510 billion in debt and KES 215 billion in equity over the next decade:

42 World Bank Data 2014 43 Firm Capacity – Peak Load plus Reserve Margin, Vision Scenario 44 Based on industry averages 45 USD-KES forex rate: 103 (year 2017)


51

Figure 30: Demand for financing – 2018-2027, KES billion

IPPS’ PERSPECTIVE ON LCY FINANCING OF POWER PROJECTS

IPPs expressed varying views on the feasibility of LCY tariffs. Where concerns exist, they are primarily focused on whether LCY tariffs would diminish their project returns and / or make Kenya a less attractive market to investors. In particular, developers emphasized that:

• A large proportion of project costs will remain in HCY for the foreseeable future, particularly in the case of renewable energy, which requires imported equipment. If IPPs are required to take LCY tariffs and HCY financing continues, this shifts the FX risk from consumers to IPPs. To manage this, most IPPs would require some form of hedging. Hedging would be required during a project’s construction period (typically 1-2 years).

Figure 31: Transfer of currency risk46

• Unfavorable financing terms: IPPs are concerned about financing terms in LCY. Most foreign IPPs have limited knowledge of LCY financing terms, as tariffs to date have been denominated in USD. Common concerns include:

o Higher interest rate: Interest rates for LCY debt exceed interest rates for HCY. In addition, HCY financing from DFIs is typically fixed interest over the life of the loan. While pension funds can offer fixed rates over the long term, commercial banks in Kenya most commonly offer variable rate loans, adjusted based on prevailing rates at the time. Local debt over an extended period of project financing (typically 12-18 years) places additional risk on the IPP.

o Shorter tenor: IPPs are also concerned about matching the tenor of LCY financing with the project lifecycle. PPAs in Kenya are normally valid for 20 years, and the market has historically been able to access 15-year tenors from DFIs (though this may not be the case into the future, if DFI financing diminishes). Tenors of more than 10 years on LCY financing from local banks are rare, though such tenors are more viable from pension funds. While it may be possible to refinance multiple times over the life of the PPA, there would be costs and risks associated with it.

• Fair equity IRRs: Despite challenges with LCY financing, IPPs say that if LCY tariffs reflect a fair and reasonable equity IRR, they would still be interested to develop projects.

46 Assumes full transition from USD to KES tariffs, options of blended tariffs explored in chapter 6

Power station

(IPP)

Transmission

(KetraCo)

Consumer

Currency Risk

Off-take / Distribution

(Kenya Power)

510 215

Debt

725

Equity


52

DIFFERENCES IN VIEWS OF LOCAL AND FOREIGN DEVELOPERS

Local developers are on the whole more open to the prospect of LCY denominated PPAs, given they are primarily focused on Kenya and have more exposure to the KES. Increasingly, local developers are driving IPPs in Kenya especially at the front end of project development, as they are well placed to identify opportunities, secure land rights, conduct feasibility studies, and navigate the regulatory regime. Local developers generally partner with local and foreign equity sponsors to complete further technical, legal and financial steps to bring the project to financial close. For debt financing, they primarily look to the DFIs, though many routinely engage the local commercial banks as well.

Still, local developers face challenges in attracting investors. Some local developers consider USD-denominated PPAs a key element in attracting investors to Kenya, and believe that it may be challenging to raise debt with LCY tariffs. While these developers see LCY financing as more viable than foreign developers, they still indicate difficulty in attracting local investors (both equity and debt) that are willing to take on development risk. Foreign equity investors have funded the majority of power development in Kenya, and if their dividends were in LCY this would expose their returns to FX risk.

Foreign developers, on the other hand, are unsurprisingly less open to the prospect of LCY-denominated PPAs. They have a greater preference for a HCY regime, as their return expectations are calculated in HCY.

CONCLUSION

In summary, it is estimated that the banking, pensions and insurance sectors could in principle provide up to KES 4,450 billion of LCY investment into the power sector over the next ten years. This could comfortably meet all the projected demand of KES 725 billion over the same period. As stated earlier, this availability of financing is the maximum limit, as financiers are unlikely to reallocate their investments radically. In addition, other sectors will compete for it, especially infrastructure projects planned for roads, water, railways, etc.

While there is appetite from local financiers to participate in power deals, consideration will need to be given to address the concerns raised by stakeholders. Specifically, there is a need to build capacity to evaluate and execute project finance investments, and to increase channels for local financiers to invest in power projects.


53

5. HOW HAVE BENCHMARK COUNTRIES APPROACHED LCY-DENOMINATED

PPAS?

This chapter summarizes our analysis of other emerging economies that either have local currency (LCY) denominated PPAs, or are under transition. We chose five countries based on comparability with Kenya, varying length of experience with LCY tariffs, and geographic diversity. We analyzed results of transition in each country, and synthesized lessons learned across all countries. In the Annex, for each of the benchmarked countries we outline the history of its power sector, history of IPPs, and transition to LCY denominated PPAs.

METHODOLOGY

Benchmarking information was obtained from a combination of desk research and expert interviews. The lessons learned were extracted from a combination of relevant third-party research, legislation introduced in each country, and interviews conducted with IPPs, investors, regulators, and research institutions. This section is not intended to be a comprehensive overview of the power sector in these markets. Rather, we have focused on synthesizing aspects that can inform transition to LCY tariffs in Kenya.

COUNTRY SELECTION

Benchmark countries were selected based on their utilization of LCY and comparability with Kenya:

Table 11: Selection of benchmark countries

Criteria Potential countries

Summary background Recommendation

African countries using LCY tariffs / financing

• South Africa

• Egypt

South Africa: Predominantly LCY financing, with 86% of debt raised locally between 2012 and 2014

Egypt: FiTs were established in 2014; tariff structure is partially LCY with a % pegged to USD

South Africa

Recent history of LCY regime, with success raising domestic capital for power projects

Other emerging markets with longstanding local currency tariffs / financing

• India

• Brazil

India: Project finance is dominated by LCY; debt represents 70% of financing for RE projects, and is primarily provided through LCY term loans by FIs

Brazil: Set up a FiT scheme in 2002 which has been superseded by auctions; all denominated in LCY

India

Shows potential for utilization of LCY tariffs over the long term

Countries with successful transition to LCY tariffs / financing

• Indonesia

• Philippines

• Malaysia

• Thailand

Indonesia and Philippines: both have relatively small domestic finance and manufacturing sectors relative to the investment need, but have continued to attract IPPs with local currency tariffs

All: Suffered sharp increase in liabilities under USD regime during

Philippines, Indonesia

Good examples of the downside risks of USD tariff structures, and ways to approach transition


54

Asian financial crisis, and have adopted LCY regime subsequently

Countries with unsuccessful transition from HCY to LCY

• Argentina

• Tanzania

Tanzania: LCY tariffs in Tanzania were not successful; this was primarily due to issues regarding credit worthiness of offtaker, which constrained IPPs regardless of whether HCY or LCY regime. However, the transition was also sudden and full

Argentina: abandoned LCY FiTs after low tariffs failed to promote investment in renewable energy

Tanzania

Example of unsuccessful transition in the region

OVERVIEW OF COUNTRIES

SOUTH AFRICA

South Africa has utilized LCY tariffs successfully on the continent. Under its Renewable Energy IPP Procurement Programme (REIPPPP), South Africa has been able to finance power projects through domestic investors, with 86% of debt raised locally from 2012-2014. The average rate of equity IRR for IPPs has been earmarked at 17% in LCY47. The tariff under the program is partially indexed to inflation. Eskom determines the tariff based on inflation, government policy and its own company strategy, which includes its recovery of costs to earn a fair return48. Any tariff change is subsequently approved by the National Energy Regulator (NERSA) to ensure that pricing level is reasonable and will promote development of power projects.

INDIA

India has utilized LCY tariffs for an extended time period. Tariffs in India have been denominated in LCY since the early 1990s. While almost the entire power sector was state-owned through the 1990s and early 2000s, IPPs now comprise approximately half of India’s generating capacity. India has a more developed capital market and manufacturing sector than Kenya. India’s GDP per capita ($1,759) is similar to Kenya’s ($1,455)49. Although India uses LCY tariffs, similar to Kenya a significant portion (up to 60%) of renewable energy IPPs’ costs remain in HCY50. The equity IRR expectations for solar are ~14% in LCY.

INDONESIA AND THE PHILIPPINES

Indonesia and the Philippines were chosen based on a similar stage of economic development to Kenya, and having undergone recent transitions to LCY tariffs. Both economies experienced the downside of USD denominated tariffs during the Asian financial crisis in the late 1990s, when state utility liabilities ballooned during a period of severe currency depreciation. Both economies have now transitioned to LCY-denominated PPAs, and offer preferential FiT rates for renewable energy. They continue to update and modify their policies, with nuanced approaches including innovative financing and hedging structures, tariff indexing, local content requirements, and competitive bidding

47 Source: National Energy Regulator of South Africa (NERSA) 48 Source: Why do we experience electricity tariffs increase? by Powertime South Africa 49 Source: World Bank 50 Source: Stakeholder interviews


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processes. The equity IRR expectations for LCY are ~15% in Indonesia, while Philippines has lower at 10-12%.

TANZANIA

Tanzania is an example of an unsuccessful transition to LCY, which was recently abandoned. Tanzania’s transition to LCY-denominated PPAs in 2008 was unsuccessful primarily due to issues around creditworthiness of the off-taker, TANESCO, but the issue was exacerbated by lack of available LCY financing and high LCY interest rates. After a period of limited investment (and with pressure from IPPs), Tanzania transitioned back to USD-denominated PPAs in 201451. Although interest from IPPs has increased since the transition, issues regarding the off-taker persist and policy priorities are unclear.

CONTEXT ACROSS BENCHMARKED COUNTRIES

Benchmark countries share similarities in terms of economic development, creditworthiness, and energy mix. With the exception of South Africa, all are lower-middle income or low-income economies, reflecting similar stages of development to Kenya. Their sovereign credit ratings all range from highly speculative to lower-medium investment grade, and most underwent transition to LCY tariffs within the last decade. All remain dependent on fossil fuels for a significant portion of energy generation.

Key figures

Table 12: Key figures on benchmarked countries52

Figures Kenya Philippines Indonesia South Africa Tanzania India

Macro data

Population (millions)

48.6 103 261 55.91 56 1,300

GDP per capita (USD)

$1,455 $2,951 $3,570 $5,273 $879 $1,709

Financial sector

Domestic credit provided by financial sector (% of GDP)

42% 64% 48% 177% 22% 76%

Sovereign credit rating (S&P)

B+ BBB BBB- BB+ Not rated BBB-

Energy sector

Primary energy source

Hydro, Geothermal

Coal, Gas, Geothermal

Oil, Coal, Gas Coal, Oil, Biofuels

Hydro, Gas, Oil

Coal, Hydro, Wind

Electricity consumption per capita (kWh, 2014)

167 699 812 4,229 99 806

Transition to LCY tariffs

Beginning of IPPs

1997 1991 1993 2005 2003 1991

Transition year from HCY to LCY

N/A 2006-2009 2015 N/A 2008 1990s

Number of IPPs

1997: 1 2006: 0 (BOT)

1990: 0 1990:0

51 Source: Tanesco; Desk research 52 Source: World Bank Indicators; Desk research


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2016: 15 2016: ~30 2016: ~48 2005-2011: 3

2012-2016: 56

2016: N/A

IPP percent of GWh sold

1997: <1%

2016: 20%

2006: 0 (BOT)

2016: 100%

2005: < 1%

2016: 7%

1990:0

2016: 40%

The benchmark countries vary in terms of size, income level, and energy consumption. India has over 300GW of installed capacity, a robust manufacturing sector, and nearly 30 years of history negotiating LCY-denominated PPAs. South Africa has a higher GDP and electricity consumption per capita than other benchmark countries. Philippines, Indonesia and Tanzania all transitioned LCY-denominated tariffs in the last 10 years, and provide insight into the near-to-medium term implications for Kenya.

RATIONALE FOR TRANSITION TO LOCAL CURRENCY TARIFFS

Nearly all benchmarked countries transitioned to LCY tariffs to avoid foreign currency (FX) risk for consumers. Frequently, this transition occurred after a major external shock, such as the Asian financial crisis in 1997 (Indonesia and Philippines), or a negative experience with a large foreign IPP (Enron in India in the 1990s). While development of local capital markets and repatriation of power sector returns were cited as reasons, they were secondary to eliminating exposure to foreign currency fluctuations.

Table 13: Table on tariffs in each benchmarked country53

Country Technology Capacity (if applicable)

LCY Tariff per kWh (in country currency)

Tariff in USD (at current rate)

Escalable portion (on inflation)

HCY Indexing

India54

Solar PV Not specified 7.04 (2016) 0.11 There has been a shift from having an annual escalation (on average 3-5%) to adopting a levelized tariff over the life of the plant.

Tariffs not indexed to HCY Wind Not specified 4.11 – 6.58 (2016) 0.06 – 0.10

Hydro >5 MW 4.45 – 5.25 (2015) 0.07 – 0.08 Hydro 5-25 MW 3.8 – 4.46 (2015) 0.06 – 0.07 Biomass Not specified 5.41 (2014) 0.08 Biogas Not specified 6.44 (2013) 0.10

Indonesia55

Solar PV <20 MW N/A 0.14 – 0.25 (2016)

Tariffs are not escalable

Tariffs fully indexed to USD Wind <10 MW 2,143 – 4,000 (2015) 0.14 – 0.30 (IDR

FiTs proposed for small projects)

53 Source: “Feed-in-Tariffs for Biomass and Municipal Waste”, IEA, 2014 and 2015; 54 Geothermal tariffs are yet to be developed, as the potential has not been exploited yet. Tariffs vary based on location. Source: Stakeholder interviews; “Renewable Energy Generation Tariff Determination in Practice”, Regulatory Affairs SunEdison Energy India Limited, 2015; “Renewable Energy Tariffs Regulation and Design”, CERC 2012) 55 Tariffs are dependent on location and whether the plant is connected to a low or medium voltage network; Government is currently developing FiT for wind energy (the wind tariffs above are proposed by the ADB) Source: Stakeholder interviews; “Will New Feed-in Tariffs Allow Indonesian Solar Power to Shine?”, ASEAN Centre for Energy, 201; “Indonesian Feed-in-tariff”, ECN Policy Brief, 2015; “Solar Feed-In Tariff of Indonesia”, IEA, 2016; “Tariff Support for Wind Power and Rooftop Solar PV in Indonesia”, ADB, 2015; “World Energy Resources, Geothermal”, World Energy Council, 2016;


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Wind >10 MW N/A (USD FiTs proposed for large projects)

0.15 – 0.28* (2015)

Hydro <10MW 656 – 1506 (2012) 0.05 – 0.11 Biomass <10 MW 1150 – 1500 (2015) 0.08 – 0.10 Biogas (landfill gas)

<10 MW 1050 – 1400 (2015) 0.07 – 0.10

Geothermal MW not specified

135 – 2574 (2012)

0.01 – 0.19

Philippines56

Solar N/A 8.69 (2016) 0.17 Annually adjusted based on relevant CPI index (share of local and foreign capital). Degression of 6% p.a. for solar and 0.5% p.a. for all other technologies.

Capacity charges adjusted at end of construction period to account for FX movements. Fuel indexed to HCY. O&M costs are not indexed to HCY.

Wind N/A 7.4 (2015) 0.17 Hydro N/A 5.9 (2012) 0.12 Biomass N/A 6.63 (2012) 0.13

Tanzania57 Hydro 10 MW 108.72 (2010) 192.54 (2011) 173.55 (2012) 125.28 (2013) 115.33 (2014)

0.085 (2015) Tariffs Tz/kWh are based on dry season tariff. Dry season tariffs are adjusted to account for the reduced output of the hydro plant during the dry season.

Tariffs not indexed to HCY

Biomass 10 MW 90.98 (2014) 0.112 (2015)

South Africa58

Wind Not Specified

0.976 (2011-2014) 0.098 (2011-2014)

South Africa tariffs are in LCY and partially indexed to inflation

Tariffs not indexed to HCY Solar PV Not Specified 1.678 (2011-2014) 0.175 (2011-

2014)

CSP Not Specified

3.00 (2011-2014) 0.294 (2011-2014)

Currency conversion based on 1 Indian Rupee (INR) = USD 0.016, 1 Indonesian Rupiah (IDR) = USD 0000.7, 1 Philippine Peso (PHP) = USD 0.02 (December 2017), 1 Tanzanian Shilling (TZS) = USD 0.00045, 1 South African Rand = USD 0.078

56 **Tariffs are only categorized by the type of technology used, not by size; Biogas and geothermal technologies not included in the FiTs. Source: Stakeholder interviews: “Potential and challenges in implementing feed-in tariff policy in Indonesia and the Philippines”, Energy Policy, 2013; Philippines Energy Regulatory Commission, 2015 57 Tariffs are dependent on location and whether the plant is connected to a low or medium voltage network; Government is currently developing FiT for wind energy (the wind tariffs above are proposed by the ADB) Source: Stakeholder interviews; “Will New Feed-in Tariffs Allow Indonesian Solar Power to Shine?”, ASEAN Centre for Energy, 201; “Indonesian Feed-in-tariff”, ECN Policy Brief, 2015; “Solar Feed-In Tariff of Indonesia”, IEA, 2016; “Tariff Support for Wind Power and Rooftop Solar PV in Indonesia”, ADB, 2015; “World Energy Resources, Geothermal”, World Energy Council, 2016; 58 Tariffs are dependent on location and whether the plant is connected to a low or medium voltage network; Government is currently developing FiT for wind energy (the wind tariffs above are proposed by the ADB) Source: Stakeholder interviews; “Will New Feed-in Tariffs Allow Indonesian Solar Power to Shine?”, ASEAN Centre for Energy, 201; “Indonesian Feed-in-tariff”, ECN Policy Brief, 2015; “Solar Feed-In Tariff of Indonesia”, IEA, 2016; “Tariff Support for Wind Power and Rooftop Solar PV in Indonesia”, ADB, 2015; “World Energy Resources, Geothermal”, World Energy Council, 2016;


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RESULTS OF TRANSITION

While it is early to fully assess the exact results of transition in several of the benchmark countries, there are a few impacts which are cross-cutting:

• Reduced government and utility exposure to foreign currency fluctuations. While not fully eliminated in some cases (due to partial USD indexing), this is the primary rationale for transition to LCY tariffs. For instance, the Philippine Peso depreciated to a seven year low of PhP 48.5 to the dollar in 2016, and having LCY-denominated tariffs likely cushioned the government from additional exposure to currency risk through the power sector.

• Greater participation of local financiers in power sector finance. India, Indonesia, and the Philippines have seen financiers (particularly in the banking sector) support IPPs, especially small-scale. In India, more than 35% of public banks and 20% of commercial banks provide funding to the renewable energy sector, while 40% of insurance funds are involved in renewable energy finance59.

• Increased equity investment from local sponsors. With returns in LCY, local sponsors gain an advantage over foreign investors, as their returns are largely unaffected by currency depreciation. To utilize this situation, countries have developed LCY equity funds. E.g. in Indonesia, the Ministry of National Development Planning introduced an LCY infrastructure funding scheme in 2017, which makes use of long-term financing from pension funds and government-owned infrastructure financing companies. PT TASPEN, a major pension fund in the country, covers any shortfall in LCY equity funding in the pilot projects being supported by the scheme60. Such initiatives have increased equity investments from local financiers.

• Potential for reduced investment interest from foreign investors and IPPs. In the short term, the transition to LCY tariffs may deter foreign investors who are less comfortable with the perceived risks. This provides an opportunity for increased local investor participation and, in any event, foreign investors become more comfortable with LCY tariffs over time. For example, in South Africa developers and financiers were hesitant to participate in the first REIPPP bid window. Over time, they demonstrated an increased willingness to participate, driving tariffs down. This change in perceived risk was a result of a well-structured tariff that adequately compensated investors.

LESSONS LEARNED AND IMPLICATIONS FOR KENYA

An analysis of the countries studied for benchmarking provides multiple lessons for consideration in a potential transition to local currency tariffs for Kenya. These are described in detail below.

FOLLOW A PROGRESSIVE STEP-BY-STEP PROCESS TO TRANSITION TO LCY TARIFFS

• Consider gradual transition to LCY to minimize risk and increase likelihood of successful transition. Introducing LCY tariffs can disrupt the power sector in the short term due to uncertainty that comes with a new tariff regime. If set at the wrong level, LCY tariffs run the risk of either reducing interest of foreign investors and IPPs, or increasing the cost of power beyond a sustainable level for the off-taker and the consumer. This however, can be mitigated by putting in place a well-structured tariff. Full transition to LCY tariffs over a short period exacerbates the downside of those risks. To mitigate the unintended consequences, moving gradually, with LCY tariffs for certain technologies or below a specific project size (e.g. <10MW), provides an

59 “Renewable Energy Sector Funding”, Resurgent India, 2015 60 Getting the Deal Through: Market Intelligence, “Project Finance”, Volume 4, Issue 2, 2017


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opportunity to assess tariff attractiveness and feasibility on a small scale, allowing for adjustment before rolling out across the sector.

• Expect a mix of hard and local currency financing as some countries continue to rely on foreign debt financing (i.e. up to 30-70% of their financing is in hard currency). Countries with more developed markets (South Africa) have seen an increase in power sector finance participation by local banks and financial institutions. Local banks, while initially hesitant about power sector risk and longer tenors, have become active in the energy space. Still, even in more developed markets (India), IPPs utilize a mix of foreign and local debt.

• Recognize the quick-win opportunity offered by small power projects: While USD financing continues to play a role, commercial banks can finance smaller IPPs (<10MW), as the ticket sizes are often more manageable and can be supported by their Single Obligor Limits (SOLs); DFIs also prefer larger transactions. Interviewees mentioned about more openness from the off-taker to agree on partially-indexed tariffs for large power projects compared to small projects.

DESIGN FAIR TARIFF STRUCTURE TO ENSURE DEVELOPMENT OF THE SECTOR

• Sustain IPP return expectations: Regardless of tariff structure, HCY-denominated costs and financing remain to some extent. Therefore, IPPs and investors will likely need to hedge during the project construction period (1-2 years) and budget for USD-denominated opex. To ensure consistent returns, IPPs often pass these costs on to the off-taker during PPA negotiations (so that LCY tariffs reflect these costs).

• Match index level to costs in HCY: Certain benchmark countries, like Indonesia, apply a flat tariff structure, which remains unchanged over the contract period. This rate is meant to represent a leveled cost and return over the entire period. However, this is difficult for IPPs to manage. A better practice is to index a portion of the tariff to an objective metric such as inflation. Finally, if IPPs raise capital from local investors, such as commercial banks, they are likely to face an adjustable interest rate for the debt. In this case as well, indexing payments to interest rates significantly reduces risk for IPPs. Below is an example of the major indexing components covered in a typical PPA agreement in the Philippines:

Table 14: Tariff structure in the Philippines

Major cost components

Currency of costs incurred by IPP

Index FX Risk

Capacity Charge

Equipment Majority USD

Option 1: Assumption made on cost of hedging FX exposure

Option 2: One-time adjustment at end of construction period that adjust for FX movements over the period

Moderate. After construction period, IPPs can negotiate further adjustments, but typically flat over life of contract, exposing IPP to FX risk.

Fixed opex

Equipment Mixed USD and Peso

Both components usually indexed to relevant CPI index

Moderate. Not indexed to FX movements, exposing IPP to FX risk on USD component.

Variable opex

Labor Majority Peso Indexed to local CPI None


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Fuel Imported Coal, Diesel

Majority USD Fully indexed to USD None. Typically, pass-through arrangement, IPP “kept whole”, meaning full fuel cost passed through to utility

• Consider incentives to encourage local sourcing. In Indonesia FiTs include requirements to source a percentage of construction materials locally. Exemptions are issued for local content requirements when the target percent is not feasible.

UTILIZE COMPETITIVE BIDDING PROCESS TO DETERMINE KES TARIFF LEVELS

Consider utilizing a competitive bidding process, to let the market determine the value in KES tariffs. IPPs interested in KES tariffs will naturally emerge from the process with rates determined competitively. In South Africa, the government implemented a competitive bidding process after NERSA approved a REFiT policy in 2009. Following the abandonment of the REFiT program in 2011, South Africa moved to competitive tenders for grid-connected renewable energy with the REIPPPP. The process was established when there was uncertainty around South Africa’s public procurement framework and delays in finalizing PPAs had led to minimal investment. Despite a tight time schedule and tough qualification criteria, 6,422MW of electricity had been procured from 112 IPPs in seven bid rounds, and 3,052 MW of electricity generation capacity from 56 IPPs has been connected to the national grid from 2012 to date.

SUPPORT FINANCIERS OF POWER PROJECTS

Market development initiatives can be effective to increase local participation. Successful countries have prioritized capacity building, frameworks for appropriate investment vehicles, and promotion of credit enhancements to incentivize local investors.

Specifically, successful countries:

• Allow long-term investors to deploy capital into power projects. In markets where institutional investors are subject to less stringent regulation (e.g. South Africa), more long-term LCY capital is mobilized for power sector investments.

• Build financier’s understanding of power sector. Capacity building can increase the likelihood of a successful transition. This was done successfully in the Philippines, where the IFC provided local banks with trainings and investment tools to support them to finance projects.

SUPPORT DEVELOPMENT OF RELATED SECTORS

Local availability of equipment/skills helps to ensure successful transition to LCY tariffs. Countries with relevant local manufacturing capacity and skilled labor at the time of transition are at an advantage. In these markets, IPPs can source a significant portion of project equipment and ongoing O&M inputs locally.

Tax incentives help to promote investment and incentivize local sourcing. For instance, the Philippines offers a tax credit on equipment and services purchased locally, that is equivalent to 100 percent of the value of the VAT and customs duties that would have been paid if materials were imported61. Indonesia provides an exemption from import duty on capital goods (machinery and equipment, but excluding spare parts) for IPPs with a PPA and an “electricity business license for public use”62.

61 KPMG Global Energy & Natural Resources, Philippines Taxes and incentives for renewable energy, 2015 62 PricewaterhouseCoopers, Indonesia Power Sector Investment and Taxation Guide, 2015


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6. HOW SHOULD LCY TARIFFS BE STRUCTURED AND IMPLEMENTED IN KENYA?

This chapter synthesizes learning from retrospective analysis, country benchmarking and market sounding to provide recommendations on the design of LCY tariffs and the actions required to introduce LCY-denominated PPAs successfully. The chapter focuses on three areas:

1. Options for structuring tariffs, and the recommended tariff structure by technology 2. Actions to increase LCY financing in Kenya by using

• Credit enhancements and financial structures

• Policy changes to incentivize LCY financing

• Other initiatives that government and stakeholders can take to facilitate investment 3. Implementation roadmap (sequencing and broader ecosystem activities) that would need to

accompany tariff changes

OPTIONS AND RECOMMENDATIONS FOR LCY TARIFF STRUCTURE

The table below summarizes the options for LCY tariffs:

Table 15: LCY tariff structure options

LCY tariff structure options

1. LCY tariffs fully indexed to HCY Tariff denominated in LCY and payments are in LCY, but the whole tariff is indexed to HCY

2. LCY tariffs partially indexed to HCY Tariff is denominated in LCY, with a portion indexed to HCY – indexing can, among other things, be based on:

a) The average proportion of project costs incurred in LCY versus HCY by technology

b) The proportion of project financed by equity versus debt (with equity returns in HCY)

3. LCY tariffs with no indexing to HCY The tariff is in LCY and is not indexed to HCY

LCY TARIFFS FULLY-INDEXED TO HCY

Under this option, the tariffs are paid in LCY, however they are fully indexed to a HCY, e.g. USD. Hence, the value of payments incurred by the off-taker in LCY changes as per the FX rate. PPAs outline how IPPs are compensated for currency fluctuations, e.g. by requiring the off-taker to make payments to match the actual rate at which the IPP acquires HCY. The off-taker "trues-up" if the amount of HCY purchased is lower and vice versa. Some countries in Africa, such as Namibia, Mozambique, Zambia and Nigeria, have fully-indexed LCY tariffs. Such tariffs require easy currency convertibility in the country, and some governments support IPPs’ currency conversion when it is a concern. While fully indexed LCY tariffs may send a message to the market, there would be no economic difference to the Kenyan consumer as they would still bear the currency risk.

LCY TARIFFS PARTIALLY-INDEXED TO HCY

Indexing a portion of the LCY tariff into HCY has been adopted successfully by numerous countries. As described in the previous chapter, Philippines has taken the approach, as well as Egypt and Tunisia, e.g. for solar PV in Egypt, 30% of the tariff is in Egyptian Pounds (EGP), while the remaining 70% is indexed to the USD63. Moreover, the country allows HCY lending only for equipment that is not available in the country.

63 Oxford Business Group, “Egypt boosting its electricity capacity through renewables”, 2016


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In this structure, the tariff split between HCY and LCY can be determined based on different factors:

1. Indexing based on the proportion of project costs incurred in LCY versus HCY64. The figures below provide 1) the proportion of project costs incurred in LCY versus HCY by technology in Kenya, and 2) how the tariffs can be indexed considering the proportion of project costs that can be financed using LCY. The difference between the two figures is due to the following considerations:

a) Capex: Given that Kenya has free currency exchange, financing obtained in LCY can be easily converted into HCY for capex, wherever needed. Hence capex can be financed almost completely with LCY debt

b) Opex: While opex (e.g. salaries, spare parts, insurance) is relatively small compared to the capex in a renewable energy project, opex is incurred throughout the life of the PPA and is paid in the respective currency. Assuming many currency movements over the years, the currency mix of tariff should match the currency mix of opex.

Figure 32: Split in costs incurred in LCY versus HCY by technology, and indexing of tariffs

The table below shows the tariffs in KES, for illustrative purpose only, assuming a FX rate of 103 (USD/KES), and a base tariff of 0.10 USD cents for all technologies. Variation of actual tariff value by technology is ignored in the table to highlight the split between the indexed and non-indexed portions.

Table 16: Tariff indexing considering the currency of project costs

Technology Total tariff amount (KES)

Amount indexed to USD (KES)

Amount un-indexed (KES)

Hydro 10.3 1.6 8.7

Geothermal 10.3 1.8 8.5

Wind 10.3 2.7 7.6

Solar 10.3 1.2 9.1

Biomass 10.3 4.0 6.3

2. Indexing to provide equity returns in HCY: Another option would be to provide equity returns to IPPs in HCY. This would keep the market attractive to foreign IPPs, while still maintaining the majority portion of the tariff as non-indexed LCY.

64 Assumptions provided in Annex 7

16% 17%26%

39%

84% 83%74%

88%

61%

12%

SolarGeothermal BiomassWindHydro

Proportion of LCY tariff Proportion of HCY tariff

51%65%

56%45%

54%

49%35%

44%55%

46%

BiomassSolarWindGeothermalHydro

Cost incurred in LCY Cost incurred in HCY


63

LCY TARIFFS WITH NO INDEXING TO HCY

In this option, the tariff is completely in LCY with no indexing to HCY. The tariff structure usually works in markets in which the majority of labor and material can be sourced domestically, as well as markets with a developed financial sector. Countries with completely LCY-denominated tariff structure include India and South Africa.

EACH TARIFF STRUCTURE OPTION CAN BE FURTHER INDEXED

Given that inflation and interest rates in LCY are higher than those in HCY, further indexing of tariffs to inflation or interest rates is often deployed. This will help in sustaining IPPs’ returns to levels they achieve currently under a HCY regime:

• Indexing to inflation – Indexing to inflation ensures that real (inflation-adjusted) returns to IPPs are maintained, as well as accounting for increasing costs. A scalable portion can be indexed to inflation, e.g. to the Kenyan Consumer Price Index (CPI). FiTs in Kenya follow this approach, although their scalable portion is indexed to United States (US) CPI as FiTs are in USD.

• Indexing to interest rates – This indexing can be used on a case-by-case basis, depending on the source of financing. Where variable interest rates are used (e.g. by commercial banks), the tariff can be indexed to CBK rates to compensate for any fluctuations in interest rates. As pension funds are more willing to provide fixed interest rates, the indexing would not be necessary for projects financed by pension fund capital.

Based on the research provided in previous chapters and the tariff options listed above, in the near to medium term we recommend different tariff regimes for small projects and large projects.

• For projects of 10 MW and below: PPAs should be denominated fully in LCY. Given their size, these projects can be comfortably financed in LCY by local commercial banks and institutional investors in the near term.

• For projects above 10 MW: a partially-indexed tariff structure based on the split of average LCY versus HCY costs by technology (see above) is recommended to allow for an easier transition. This minimizes risk for IPPs where project costs are partially incurred in HCY, and provides space for local financiers to steadily increase their financing of power projects. One benefit of larger deals is that the global / regional project finance teams of banks may be involved, which can help to bring in relevant expertise and build up the local market.

Construction costs incurred in HCY can be financed in LCY if the financed amount is converted into HCY at spot FX market rates. In such a case, only the opex incurred in HCY need to be indexed to HCY. As market players adopt LCY financing and local sourcing of material and services increase, MoE can gradually reduce the indexed component in subsequent review of tariffs. A consideration can be given to large power projects, which cannot be completely financed by LCY and therefore take HCY financing. Tariff indexing for such projects can be discussed on a case-by-case basis.

ACTIONS TO INCREASE LCY FINANCING IN KENYA

POLICY INCENTIVES TO SUPPORT THE TRANSITION TO LCY TARIFFS

Policy can play a major role in supporting the transition to LCY tariffs, in particular to:

• Enhance tax incentives for LCY investments into the infrastructure sector. The local financial sector (banks, pension funds and insurance companies) can be encouraged to invest in the power sector through tax incentives. Currently, interest earned on listed infrastructure bonds with at least 3 years to maturity is exempt from both withholding and income tax65. Such incentives could

65 KenGen website: Public Infrastructure Bond Offer

http://www.kengen.co.ke/?q=investor-relations/public-infrastructure-bond-offer-pibo


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also be extended to the banking sector, for example, to make a portion of interest earned on loans to IPPs tax deductible.

• Create a distinct asset class for infrastructure (as has been done for real estate) – RBA and the Insurance Regulatory Authority (IRA) can create a separate asset class for infrastructure investments, which can help to increase LCY investments into the power sector.

• Introduce tax breaks on locally sourced materials – To encourage local sourcing, all equipment and services sourced locally for power projects can be made tax exempt (no VAT) with an expedited process to obtain exemptions. The key reason for high imports in the power sector is due to lack of local manufacturing of complex equipment. While equipment imported for renewable power projects are tax exempt, there is lack of clarity on the policy regarding materials such as pipes and other low-tech parts.

• Offer a higher LCY tariff to early movers: To encourage acceptance of LCY tariffs, MoE can offer a higher tariff to IPPs that opt for LCY tariffs early on, to accelerate a few LCY deals and achieve demonstration effect. This is likely to increase adoption of the tariffs by IPPs and smoothen a transition to LCY tariffs.

CREDIT ENHANCEMENTS AND FINANCIAL INSTRUMENTS

Credit enhancements facilitate access to debt capital and can be used to (i) mitigate the perceived risks of financing power projects and (ii) create conditions that attract LCY denominated financing. As we have discussed, in Kenya today; power projects are largely financed by DFIs and foreign investors. There is limited capital invested by local commercial banks and institutional investors, who primarily invest in LCY and seek more traditional, investment grade assets. These local investors are constrained from investing in power projects due to currency mismatch, high perceived risks, and shorter tenors.

The majority of project costs and revenues are denominated in HCY, which leads IPPs to seek financing in HCY rather than LCY which local investors are better placed to invest. In addition, local banks willing to provide loans to IPPs in LCY have little appetite to invest at the pre-commercial operations date (COD) stage. Local banks prefer to come in post-construction once they are guaranteed cash flows from the sale of power to Kenya Power. When banks participate at pre-COD stage, they are unable to correctly price the risk, resulting in risk premiums that can make the project commercially unviable. In addition to this, local banks’ tenor sweet spot is typically between 3-5 years and they are often unable to match the long-dated tenor required for power projects, which is between 10 – 12 years.

RECOMMENDED SOLUTIONS

Commercial banks and institutional investors in Kenya can become a key source of LCY financing for IPPs, facilitated by appropriate credit enhancement structures. The current macroeconomic environment means that commercial banks opt to hold their money in government securities e.g. a large bank we interviewed had an exposure of more than KES 100 billion in government securities in the third quarter of 2017. A share of these funds could be channeled into power projects, if the perceived risks were adequately mitigated. The figure below sets out important credit enhancement options for LCY financing in Kenya:


65

Figure 33: Credit enhancement options

CREDIT GUARANTEES

To unlock commercial bank financing, the issue of risk perception during construction phase can be addressed with a credit enhancement that would reassure the banks of payment for lending before completion date. One such company is GuarantCo, a private company that is part of the Private Infrastructure Development Group (PIDG) and sponsored by five G12 governments to help address and overcome constraints in the supply of LCY financing for infrastructure. GuarantCo can reassure commercial banks’ lending by providing:

1) A credit guarantee of up to 50% of the total loan for the project. This means that the commercial banks, pension funds and insurance companies who lend towards project development are guaranteed half of their investment during the high-risk period of the project, at a minimum rate of 3% per annum of guaranteed funds. Commercial banks appear to be more comfortable with the operation risks once the power plant has started generating cash flows.

2) Tenor extension of loans. Commercial Banks are comfortable with pricing risk up to seven years and therefore a credit enhancement to extend the tenor would be essential to close the gap between banks’ tenor preference versus what is needed for the project. To facilitate tenor extension, the GuarantCo structure could allow the uncovered tranche to amortize earlier so that the long end of the tenor is fully covered.

Credit guarantees can also be used to enhance project finance bonds or corporate bond issuances. For instance, guaranteeing coupon payments in case there is a shortfall to the bondholders. This allows the yield required by the investor to come down and thus, further encourage participation. To qualify for the provision of guarantees, criterion should be established for projects funded by the local banks and pension funds. For example, power projects could be subject to due diligence and as a minimum be required to meet some key criteria, such as i) projects must fall under the feed in tariff (FiT) program and be below 20MW ii) be financially bankable, with equity finance committed iii) have strong sponsors as shareholders owning at least 30% equity stake and iv) local IPPs given preference, and 40% local content encouraged if IPP is foreign.

SENIOR AND SUBORDINATE DEBT STRUCTURES

A senior/subordinate structure allocates cash flows generated by IPPs to investors based on priorities of different classes of varying seniorities (tranches) – senior to subordinated tranche. The provision of the subordinated tranche increases the credit quality of the senior tranche. The senior tranche has the first right on cash flow (priority for cash flow comes from the top); it would be unaffected if the IPP were to miss debt repayments, unless the amount of the losses exceeds the amount in the subordinated tranches. The senior tranche is suitable for the most conservative investors, such as pension funds and insurance companies. The subordinated tranches function as protective layers of the more senior tranches. If an IPP defaults, the losses thus incurred are allocated to the subordinated

Credit guarantees

(Provided by third party)

• Tenor extensions and interest rate reductions

• Covers up to 100% of the exposure

Local currency debt fund

• Sponsored by government / DFI / Others)

• Could participate with commercial banks

Senior / Subordinate Structure

• Bonds (Project, Corporate, Infrastructure), sometimes via SPV

Credit enhancements


66

tranche first (from the most junior to the most senior tranche). Due to its perceived riskiness, the subordinated tranches could also be credit enhanced.

The credit enhancement of the subordinated tranche can be provided by a DFI such as IFC, EIB or AfDB and can take the form of a loan, which is given to the IPP during construction phase, or a contingent facility or credit line, which can be drawn upon if the revenues generated by the IPP are not sufficient to service senior debt. This credit enhancement would be available during the lifetime of the project, including the construction phase. The project bond could be a listed issue (regulated by Capital Markets Authority); this would be more attractive to local pension funds and insurance companies. This listed issue would be perceived to have less risk and be more liquid while requiring less reserved capital. The listed issue could also be categorized as an infrastructure or corporate bond.

The credit enhancement for the senior and subordinated structure could either be funded or unfunded:

• Funded credit enhancement: This would be used with other financing to fund the construction phase, and then repaid during the operations phase when cash flows are generated. In terms of repayment priority, this would rank below the senior bond but ahead of the remaining risk capital of the project (generally subordinated debt and/or equity).

• Unfunded credit enhancement: In the unfunded credit enhancement structure, rather than funding a mezzanine debt tranche, a DFI would provide a long-term, irrevocable and revolving letter of credit (Letter of Credit) to the project, the benefit of which would be assigned to the trustee for the senior bonds. This Letter of Credit would act as a contingent credit line which would be drawn if cash flows generated by the IPPs are not sufficient to achieve construction completion and/or ensure senior bond debt service. In the event that the project runs into difficulties and the credit line is drawn, the DFI would inject funds under the Letter of Credit. This would create a mezzanine funding similar to the funded credit enhancement; the mezzanine loan only arises when the project risk occurs, not before. The European Investment Bank (EIB) has already utilized this structure to enhance project bonds in the past.

• Corporate or infrastructure bond through a Special Purpose Vehicle (SPV): In order to tap into the capital markets liquidity (from institutional investors such as pension funds, asset managers and insurance companies), project bonds or corporate bonds can be utilized. The key advantage of the SPV is that it protects the bond issuer from IPPs’ loan obligations making the SPV bankruptcy remote. This bankruptcy remoteness of the SPV trust’s structures and the extra support provided by credit enhancement, enables the security to receive their own credit rating, independent of that of the IPP. This is important for most institutional investors since it enhances the SPV credit profile, which is usually better than that of an IPP (sponsor). These bonds could be listed or privately placed, deepening capital markets by establishing tradable instruments that enable investors to invest in infrastructure as an asset class. Key benefits would be the reduction of yields and borrowing costs, whilst increasing the tenor and liquidity of the project bonds.

GOVERNMENT OR DFI SPONSORED LCY FUND

A local currency fund can be structured to enable the funding of IPPs where lenders can structure bespoke solutions to assist previously unbankable developers, and to build skills and job capacity in the local developer pool. Commercial banks can for instance contribute senior debt to the fund, whilst DFIs contribute a first-loss debt facility, as well as grant type funding which would fill the development finance role in the fund. The fund’s main objective would be to overcome the hurdles that local IPPs typically face when trying to attract LCY funding. Most local IPPs traditionally do not have the track record and balance sheet support to raise finance from commercial banks. In addition, a small project of 10MW or less will incur the same transaction costs as bigger plants, (40MW or more) which a small project cannot afford. This fund would address these challenges by blending development capital (grants) in the debt mix. The fund manager will be tasked to conduct the detailed project assessment


67

and build up power projects, which would be managed as a portfolio, increasing the economies of scale and therefore reducing the financial burden of closing the financing.

This LCY debt fund can be set up in partnership with DFIs (who could provide seed funding), and local pension funds and insurance companies who could use the vehicle to pool their capital. The benefits would encourage LCY funding by i) improving the project’s credit profile by enabling the IPP to attract investors at favorable borrowing terms, ii) increase the risk appetite of most local commercial banks and pension funds, iii) enable issuance of long tenor loans, and iv) provide direct lending during construction of the power projects. This exposure could be refinanced post-COD once the projects have been de-risked.

In summary, LCY financing of power projects in Kenya needs to be unlocked and credit enhancements can play a critical role in doing so. Companies such as GuarantCo and Coface have already established their readiness to provide partial or full credit guarantees pre-construction as well as tenor extension. The success of these products relies on awareness in the market on their existence and how to use them effectively. Public sector actors can also play a role in endorsing these products in the market to increase uptake.

CAPACITY BUILDING

One of the biggest challenges in mobilizing funds locally for power projects has been the lack of capacity within the sector to evaluate the projects, specifically with respect to financing them using project finance. This has resulted in most of the participation in the sector being from international players, who prefer to invest in HCY. In order to increase LCY participation, there is a need to develop capacity within the sector to evaluate power projects.

Capacity building can catalyze LCY participation for diverse stakeholders, including developers, banks, pension funds (board of trustees) and regulators. Capacity building should cover the below elements below (an illustrative training schedule is provided in the Annex).

• Training in a classroom setting with case studies to emphasize learning points, inviting in-depth discussion and knowledge sharing on policy, regulatory frameworks, and financial instruments related to renewable energy finance. In addition, site visits shall also be organized to projects under construction as well as operating projects to increase appreciation of the different technologies.

• Creating a platform where stakeholders from public and private sectors can exchange expertise on technology roadmaps, data on risks or returns, market forecasts and analytical tools where risk can be properly assessed.

• Seeking dialogues and collaboration between banks, insurance companies and pension assets; for instance, the banks can take the construction risk and sell down partial exposure to pension funds and insurance companies after COD.

Funding of power projects by local financiers is often based on cash flow lending. Project finance is relatively new in Kenya. Most local banks have limited technical capacity to analyze and execute such transactions, especially for power projects. Traditionally, commercial banks’ lending is based on security or collateral available and financial performance track record of the borrowers. For projects developed through Special Purpose Vehicles (SPV), a financial performance track record does not exist. Although banks engage advisors who would undertake the necessary studies, the bank staff would need to be able to appreciate the reports produced by the advisors and make credit judgment. A one-on-one technical assistance can be provided on initial transactions, which can include contracts analysis (PPA, implementation agreement, construction contract, O&M contract etc.) and risk mitigation techniques.


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IMPLEMENTATION ROADMAP

Having proposed a series of actions that can be undertaken to support financiers and IPPs in transition to LCY denominated PPAs, we outline the sequence of activities in this section. These are laid out in three categories; short term, medium term and long term, with the view that any transition to LCY tariffs would be best implemented in a gradual or step-by-step manner. The figure below lays out these activities. The activities under ‘policy and incentives’ category will be led by MoE, ERC, Kenya Power with support from other Ministries, wherever required. Activities under ‘sector development’ will largely be led by donor, DFIs and industry associations.


69

Figure 34: Roadmap to implement LCY tariffs and financing

0 – 6 months 6 – 18 months 18 months onwards

Policy and incentives

Actors: MoE, ERC, Kenya Power, working with other Ministries

• Consult internally and with stakeholders to seek inputs on tariff structure. The consultations could be bilateral and/or workshops to receive feedback and increase buy-in on the recommended tariff structures.

• Establish internal systems / processes for LCY tariffs. Process and system updates will be required in the regulatory affairs and commercial departments in the ERC and Kenya Power.

• Begin preparations to introduce LCY tariffs for small power projects (e.g. <10 MW) and partially-indexed LCY tariffs for large projects

• Set up a distinct asset class for infrastructure for institutional investors

• Implement LCY tariffs for small power projects and partially-indexed LCY tariffs for large power projects

• Introduce tax breaks on locally sourced materials and services used in the power sector

• Increase LCY component of partially indexed tariffs of large power project to push the market towards non-indexed LCY tariffs. This activity can be combined with the periodic review of tariffs.

• Introduce tax incentives (e.g. lower tax on interest income) for institutional investors’ LCY investments in power projects

Sector development

Actors: Industry associations, Donors, DFIs. Commercial banks, pension funds, insurance companies

• Support capacity building of financiers, IPPs, sponsors in the power sector

• Work with regulatory authorities to expedite policy changes. Development partners can work with regulatory authorities (RBA, CMA, IRA) to channel investments through the capital markets, expedite policy updates, as well as facilitate the use of financial instruments described earlier.

• Support IPPs to obtain financing from capital markets, as the process involves costs and requirements that some IPPs may find difficult to manage

LCY pilot projects

Actors: Industry associations, Donors, DFIs. Commercial banks, pension funds, insurance companies

• Facilitate first mover projects with LCY financing by working with financial institutions that have shown appetite to invest in LCY, and selecting IPPs interested in LCY financing.

• Disseminate details of first mover projects to spur the increase in LCY financing and tariffs and achieve the demonstration effect.

• Continue facilitating LCY financing deals and dissemination of information on LCY PPAs to increase the demonstration effect

• Facilitate selective, large power project deals with LCY financing. Fill any remaining gaps in LCY financing and support transition to non-indexed LCY tariffs.

Short-term Medium term Long term


70

ANNEXES

ANNEX 1: RETROSPECTIVE ANALYSIS

RETROSPECTIVE ANALYSIS USING FIVE-YEAR (2012-2016) PERIOD

When the same analysis is conducted for the past 5 years (2012-2016), we estimate that there would have been an increase in financing costs of 35% under a LCY regime, leading to a 16% increase in tariffs.

Figure 35: Last five years’ analysis, KES billion

The reason for difference between the results of last 5 years’ (2012-2016) and 15 years’ (2002-2016) analysis is because of the different cost of KES financing, USD financing and KES depreciation. The average LIBOR + 7% over the last 5-years is 7.9%, whereas the average value over last 15 years is 9.1%. The average Kenyan 10-year Treasury Bonds + 2% over the last five years was 15.0%, whereas the average value over last 15 years is 13.7%. This results in a difference in HCY and LCY interest rates of 7.1% over the 5-year period, as opposed to 4.6% over the 15-year period. The interest rate difference outweighs the difference in KES depreciation, which was average 2.8% over the last 5-years vs. 2.0% over the last 15-years.

RETROSPECTIVE ANALYSIS USING TEN-YEAR (2007-2016) PERIOD

When the same analysis is conducted for the past 10 years (2007-2016), we estimate that there would have been an increase in financing costs of 25% under a LCY regime, leading to a 7% increase in tariffs.

56

20

20

28

28

41

+16%

104

+35%


89




71

Figure 36: Last ten years’ analysis, KES billion

The reason for difference between the results of last 10 years’ (2007-2016) and 15 years’ (2002-2016) analysis is because of the different cost of KES financing, USD financing and KES depreciation. The average LIBOR + 7% over the last 10 years is 8.6%, whereas the average value over last 15 years is 9.1%. The average Kenyan 10-year Treasury Bonds + 2% over the last 10 years was 14.1%, whereas the average value over last 15 years is 13.7%. This results in a difference in HCY and LCY interest rates of 5.5% over the 10-year period, which is higher than 4.6% over the 15-year period. KES depreciation difference during the 10-year period was an average of 3.7%, as opposed to 2.0% over the last 15 years.

BREAKDOWN OF THE OVERALL FINANCING COST INCREASE

Analyzing the breakdown of the increase in overall financing cost, we find the last five years of the analysis period, 2012-2016, have contributed 87% to the overall increase in financing cost, as shown in the figure below.

Figure 37: Breakdown of financing cost increase

This is due to:

• Large number of projects started in the last five years: 14 out of 23 projects (capex $1,944 million) started operations during the period 2012-2016 (last five years). On the other hand, only 3 projects (capex $327 million) started during the period 2002-2006 (first five years), and 6 projects (capex $579 million) started operations in the period 2007-2011 (middle five years)

• Cumulative effect of loan repayment in the last five years: The loan tenor used is 15 years, i.e., loan repayments that started in the early years continued during the last five years. In other

7695

158158

4545

+7%

297

+25%


278



19.8 KES Billion

10%

87%

4%2002-2006

2007-2011

2012-2016


72

words, all loans were being repaid in the last five years, providing the period a high share in the financing cost increase

• Substantial difference between HCY and LCY interest rates in the last five years: The percent increase in financing cost is greatest in the last five years due to high difference in LCY and HCY interest rates

Considering the percent increase in financing cost in the three five-year periods, i.e. 2012-2016, 2007-2011, 2002-2006, shows the greatest increase in the last five years, as shown in the table below.

Figure 38: Increase in financing cost over the three five-year periods

Variations in increase in financing between different five-year periods are due to the differences in HCY and LCY interest rates, as well as different levels of KES depreciation, as shown in the table below. In addition, the interest rates are fixed for the loan duration, hence finance cost increase depends on the start year of loans.

LIST OF POWER PLANTS BY COMMISSION YEAR

The below table provides a list of power plants in Kenya by commission year, until 2016. Only power plants commissioned between 2002 and 2016 are included in our analysis.

New power plants have been commissioned since the beginning of 2017, e.g. Imenti Tea Factory, Gikira hydro, Regen-Terem Hydro, which are not listed below.

Table 17: List of power plants, by commission year

Technology Pre-2002 2002-2016

Thermal Embakasi (Active) Iberafrica 2

Embakasi (Reactive) Rabai

Kipevu 1 Aggreko

Iberafrica 1 Garissa

Tsavo Lamu

Kipevu 3

Thika Power

Gulf Energy (Athi River)

Triumph

Geothermal Olkaria 1 (1-3) Olkaria 2

Olkaria 3 (1-6) Eburru

Olkaria Wellhead 37

6.1

KES financing

6.8

USD financing

+11.5%

20.5

KES financing

22.4

USD financing

+9.4%

81.3

KES financing

98.5

USD financing

+21.2%

Increase in financing cost (2002-2006)KES Billion




73

Orpower Plant II, III

Olkaria IV, Wellheads 43, 914, 915

Olkaria I AU

Hydro

Masinga Sondu Miriu

Mesco Kindaruma (32Mw addition)

Ndula Sang'oro

Sagana Power Technology Solutions (Gikira)

Savani

Sosiani

Tana

Turkwel

Gitaru

Gogo

James Finlay

Kamburu

Kiambere

Kindaruma

Wanjii

Wind Ngong Hills - Phase I Ngong Hills - Phase II

Ngong Hills – Phase III

Cogeneration Mumias

Biojule


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ANNEX 2: FERFA BACKGROUND CALCULATION

The table belowTable 18 provides annual FERFA figures for 2002-2016.

Table 18: Annual FERFA figures

Year Losses due to FCY payments to IPPs (KES)

2002* 516,415,454

2003* 600,483,086

2004 698,236,147

2005 543,526,927

2006 307,253,273

2007 135,108,532

2008 335,669,969

2009 961,768,721

2010 1,495,389,491

2011 3,036,057,943

2012 2,582,390,860

2013 2,862,233,236

2014 953,371,243

2015 2,309,853,446

2016 3,240,857,120

*Data not available. Derived from figures in years 2004-2016


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ANNEX 3: MARKET SIZING METHODOLOGY

The following methodology was used to size LCY financing available to the power sector:

• Estimate of total available

o Banking sector (2016): estimated based on (i) the assets of the banking sector (ii) the proportion of assets in LCY, (iii) exposure limit of the banking industry to the power sector

o Pensions sector (2015): estimated based on (i) the maximum allowances of the asset classes long term insurers can use to invest in the infrastructure sector

o Insurance sector (2015): estimated based on (i) the market share of long-term insurers as a percent of total assets (ii) the maximum allowances of the asset classes long term insurers can use to invest in the infrastructure sector

• Growth rate and range of financing over the period 2016-2027

o Banking sector: applied CAGR over the period 2012-2016

o Pension and insurance sectors: applied CAGR over the period 2011-2015

Table 19: Top 10 banks by gross loans in 2016

Bank Gross (KES billion)

Kenya Commercial Bank 373

Equity Bank 221

Co-operative Bank 241

Barclays Bank 176

Standard Chartered Bank 132

I&M 104

Stanbic 118

Diamond Trust Bank 142

NIC Bank 113

Commercial Bank of Africa 105

Table 20: Percentage of assets and loans of selected banks in LCY vs. HCY in 2015

Bank % Loans in LCY % Loans in

foreign currency

% Assets in LCY % Assets in

foreign currency

KCB 81% 19% 86% 14%

Equity Bank 75% 25% 81% 19%

Co-operative Bank 79% 21% 83% 17%

Standard Chartered Bank 67% 33% 72% 28%

I&M 63% 37% 70% 30%

Stanbic 42% 58% 14% 86%

Diamond Trust Bank 58% 42% 74% 26%

NIC 56% 44% 31% 69%


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ANNEX 4: DETAILED COUNTRY BENCHMARKING INFORMATION

INDONESIA

MACROECONOMIC DATA

The table below has economic and financial indicators for Indonesia, compared to the same for Kenya.

Table 21: Key indicators of Indonesia and Kenya (2017)66

Category Indicators Indonesia Kenya

Economy GDP $932 billion $71 billion

Population 260 million 48 million

GDP per capita $3,570 $1,455

Financial sector Domestic credit provided by financial sector (% of GDP)

48% 42%

Energy investment w/ private participation 2002-2016

$22.6 billion $2.3 billion

Market cap of listed domestic companies (% of GDP)

45.7% 35%

ENERGY MARKET HISTORY

Indonesia has a monopoly state-owned off-taker, Perusahaan Listrik Negara (PLN). PLN also builds and operates generation assets, owning roughly 60% of Indonesia’s installed capacity as of 2015. Indonesia has an abundance of coal deposits, and over 90% of energy production comes from thermal resources. PLN was the only power producer in Indonesia until signing of the 1985 Electricity Law, which allowed private participation in generation. PLN signed its first PPA with an IPP in 1991, and several others followed shortly after, all with PPAs denominated in USD.

Sector development came to an abrupt halt during the Asian financial crisis in the late 1990s, during which Indonesian GDP fell by over 10% and the Indonesian Rupiah (IDR) depreciated over 600%67. PLN was particularly exposed, with a majority of costs and 100% of off-take obligations denominated in USD. Many PPA agreements signed with IPPs were abandoned, and investor confidence suffered greatly.

A series of contradictory regulations were passed from 1999-2006, leading to minimal investment in generating capacity, but ultimately resulting in FiT legislation in 2006 and 2010 aimed at attracting renewable energy IPPs. The majority of new PPAs during this time still utilized USD-denominated tariffs. Tariffs incentivized IPPs to build generation assets in underserved areas, as the Indonesian geography (17,000 islands make up the archipelago) presents unique challenges68. FiT tariffs were not pegged to inflation, and included requirements to source a percentage of construction materials locally69.

66 Source: World Development Indicators, World Bank 67 Source: PricewaterhouseCoopers, Indonesia Power Sector Investment and Taxation Guide, 2015 68 Source: Asian Development Bank, Summary of Indonesia’s Energy Sector Assessment 69 Local sourcing requirements vary by technology

https://en.wikipedia.org/wiki/Perusahaan_Listrik_Negara


77

Table 22: IPP and Feed-in-tariff introduction70

Table 23: Current energy market71 Indicators Values Energy mix

Installed capacity (MW)

55,000

State ownership of generating capacity

60%


812

Electrification rate 75%

Local materials requirement for IPPs

20-70%, depending on

technology

TRANSITION TO LOCAL CURRENCY TARIFFS

Indonesia is currently undergoing transition to LCY tariffs. In 2015, regulation required that all payments to IPPs be denominated in IDR. However, interviews with IPPs revealed that nearly all of these IDR tariffs are fully indexed to the USD. Many IPPs view indexing as a transitional phase, and while the policy situation remains fluid, they believe the intention is to ultimately move to unindexed IDR tariffs. However, the timeframe remains uncertain.72

70 Source: Independent Power Producer (IPP) Debacle in Indonesia and the Philippines: Path Dependence and Spillover Effects, by Xun Wu and Priyambudi Sulistiyanto 71 Source: ECN Policy brief - Indonesian feed-in-tariffs: Challenges & options 72 Source: Stakeholder interviews

Key dates and milestones

First IPPs Feed-in-tariff regulations

Year 1991 2006, 2010

Currency USD Blended USD and IDR (indexed to USD)

Structure • State utility (PLN) as sole purchaser, 10-20 year PPA

• PLN also owns 60% of generation capacity

• Flat FiT for 10-20 year PPA, not pegged to inflation or Fx

• FiT varies based on location (e.g. higher in underserved areas)

• Rupiah - Hydro, Biomass, Solar

• USD - Geothermal

Additional notes

• During Asian financial crisis, many IPPs abandoned or renegotiated, loss of investor confidence

• Half of new capacity since 2012 has come from IPPs

• Require IPP purchase and use of minimum percentage local materials where possible


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INVESTMENT IN IPPS73

Investment in IPPs has typically come from foreign equity and debt providers, and this continues today. IPPs confirmed that the majority of their debt still comes from DFIs. The primary explanation is that most IPPs still have USD-denominated PPAs or fully-indexed IDR tariffs, which provides limited incentive to raise local financing. IPPs also noted that most of their costs remain in USD, and that exemptions are issued for local content requirements when the target percent is not feasible. Pension funds and insurance companies are heavily regulated and can only invest in public equity or debt.

The existing local debt which is available comes from commercial banks. Local banks have begun financing smaller renewable energy projects, and interest rates on local debt is reasonably priced, with most estimates ranging from 9-11% in IDR. Larger Indonesian IPPs quote their cost of debt in USD for project financing at LIBOR + 5%. However, the larger project financing opportunities still require more capital and longer tenors than most local banks can provide.

Given that tariffs are moving towards IDR denomination, and local financing options remain limited, IPPs have begun to develop creative ways to attract financing. One IPP shared details of a tripartite PPA structure, whereby PLN pays tariffs to a local bank in IDR, and the bank pays the IPP in USD. Still, the financing for this project came from USD investors, with debt raised from insurance companies and export credit authorities in Japan and Korea. This IPP claimed that project financing is not well understood by local investors, who would only invest if the project was accompanied by a corporate guarantee from the operating company.

RESULT OF TRANSITION74

While Indonesian PPAs have been denominated in IDR since 2015, the fact that most remain fully indexed to the USD makes transition impacts difficult to assess. In many respects, the transition has not yet occurred, and PLN still faces considerable foreign currency risk. However, the transition to IDR denomination, even with full indexing, has sent a signal to the market. Most IPPs have begun to consider local financing options, and are developing creative partnerships in preparation for an unindexed IDR tariff. Local banks have also gained exposure to the power sector via hedging facilities, and are beginning to invest in small scale renewable energy projects. In hindsight, this largely symbolic move to indexed local currency tariffs may be considered a prudent first step in a gradual transition IDR tariffs.

THE PHILIPPINES

MACROECONOMIC DATA

The table below has economic and financial indicators for the Philippines, compared to the same for Kenya.

Table 24: Key indicators of the Philippines and Kenya (2017)75

Category Indicators Philippines Kenya





64% 42%

73 Source: Independent Power Producer (IPP) Debacle in Indonesia and the Philippines: Path Dependence and Spillover Effects, by Xun Wu and Priyambudi Sulistiyanto; Stakeholder interviews 74 Source: Stakeholder interviews 75 Source: World Development Indicators, World Bank


79

Energy investment w/ private participation 2002-2016

$23 billion $2.3 billion


79% 35%

ENERGY MARKET HISTORY76

The Philippines was the first country in Asia to have a Build Operate Transfer law, established in 1990. The law was successful in attracting IPPs, and under it they had signed 42 PPAs by 1998, with IPPs operating government-owned generation assets. All PPAs were originally denominated in USD, and during the Philippine Peso depreciation of the late 1990s, the National Power Corporation’s (off-taker) liabilities ballooned to account for one-third of national debt.

As a result of this unsustainable obligation, the Philippines passed the Electric Power Industry Reform Act of 2001, in which the government committed to sell generation and distribution assets to the private sector. The revenue generated from these sales was used to pay down the National Power Corporation’s debt obligations in USD. Over the period 2006-2009, private sector investors bid to purchase all generation assets in the Philippines. Ownership of power generation is now nearly 100% with the private sector. Distribution has also been privatized, and is largely done through private utilities or cooperatives with franchise rights to a specified customer base. As a result, the government is no longer directly involved in PPA transactions. While the Energy Regulatory Commission approves each contract, the terms are negotiated between two private parties.

Table 25: IPP and Feed-in-tariff introduction77


Initial IPP framework Feed-in-tariff regulations

Year First IPP commissioned in 1991 2008, 2012

Currency USD Philippines Peso

Structure • Competitive bidding process, multiple variations of Build-Operate-Transfer (BOT)

• Mix of Energy Conversion Agreement and PPA for Thermal

• FiTs for wind, solar, ocean, hydro and biomass guaranteed for 12-20 years

• Based on the actual leveled cost of generating electricity, plus a set return on invested capital.

• Annually adjust tariff rates for the entire contractual period based on Fx and CPI

Additional notes • Power crisis in early 1990s

• 1991-1993: 22 contracts for 2,648 MW signed

• By 1997, IPPs comprised 45% of total installed capacity

• Asian financial crisis, NPCs liabilities reach $23B in 2003

• Base rates reviewed every 3 years, adjusted based on national targets for tech and deployment

76 Source: IPPs in the Philippines, by Maria Joy V. Abrenica, School of Economics, University of the Philippines; Stakeholder interviews 77 Source: Resolution adopting the Feed-in-Tariff rules, Energy Regulatory Commission, Republic of the Philippines; Rate analysis of the FiT allowance implementation in the Philippines, by Sahcel C. Estoperes and Trixia Anne A. Tañedo; Getting FIT: An Analysis of the Feed-in Tariff Scheme in the Philippines, by Rainier Ric B. de la Cruz, School of Economics, University of the Philippines


80

Table 26: Current energy market78

Indicators Values Energy mix


19,000


11%


700



None

TRANSITION TO LOCAL CURRENCY TARIFFS79

This privatization effort also resulted in a transition to tariffs denominated in Philippine Peso, as private utilities negotiated rates with IPPs that matched the currency of liabilities with that of revenues. These typically include partial HCY indexing for capacity and energy charges, and full indexing where imported fuel is required (thermal). While 85-90% of IPPs have a purchase contract with a utility, the remaining IPPs sell power directly into the spot markets. In a typical arrangement, both the IPP and utility declare their contracted energy price to the market. IPPs then sell directly into the spot market, and bill the utility for the contracted amount. This structure is referred to as a “merchant market,” and the rules governing sale and purchase of energy through spot markets are complex. In essence, spot markets allow the market to determine pricing, and ensure utilization of supply. For example, an IPP that cannot generate sufficient energy to meet obligations to a utility may purchase energy through the spot markets to fulfill that obligation.

INVESTMENT IN IPPS

The transition to a privatized market where LCY tariffs are the norm has also shifted the investment landscape. Equity investment typically comes from local project sponsors, with the primary actors being existing large utilities and IPPs. There are some smaller local developers, and a few large foreign IPPs investing in the Philippines, but they are a minority of the market. Return expectations have fallen substantially in the current low interest rate environment. Combined with reduced risk perceptions in the Philippines, this has resulted in equity investors expected returns in the region of 10-12%.

On the debt side, historically the market was dominated by DFIs, and many are still invested in large projects. However, the landscape is changing, and local banks are now taking a larger role. Local banks, while initially hesitant about spot market risk and longer tenors, have become quite active in the energy space. Some now offer 15-year tenors at the Philippines interbank rate + 200-250 basis points. The banks remain resistant to fixed pricing, but typically offer an interest rate over five years, then reprice at a predetermined period in the future. While USD financing continues to play a role, banks are especially active in financing smaller IPPs (<10MW), as the capital requirements are below the amount required for DFI financing. Additionally, most DFIs won’t invest in fossil fuel power generation, so any new thermal plants typically raise local financing.

78 Source: Bright Archipelago: Government Roadmap for Philippines Renewable Energy Sector, EU-Philippine Business Network 79 Source: Stakeholder interviews


81

RESULT OF TRANSITION80

While the transition has resulted in several benefits for the Philippines, cost savings have not yet materialized, and consumers pay high energy costs (USD 19 cents/kWh as of April 2017 for Meralco, the Philippines’ largest utility).

Benefits realized to date:

• Government and utilities are no longer exposed to foreign currency risk.

• Market is much more functional: supply has grown along with demand, and local capital has successfully filled in the gap left by concessionary financing from DFIs.

• Foreign investors have remained interested to invest in the Philippines, largely due to solid economic growth and stability of the economy.

Key reasons why cost savings have not yet been realized:

• Legacy USD PPA contracts still in existence, which the Philippine government signed during the 1990s. Given energy shortages at the time, contracts with operating IPPs (under a Build-Operate-Transfer agreement) were quite generous. As these generation assets were sold off to the private sector, investors who acquired generating assets were required to take on PPAs under the original terms with the operating company. In addition, the Philippines government continues to pay remaining debt obligations in USD from power sector investments in the 1990s (the sale of generating assets did not fully cover the outstanding debt).

• Feed-in Tariff (FiT) structure outlined in the Renewable Energy Act of 2008, and updated in several subsequent resolutions. Renewable energy IPPs can apply for a FiT rate from the National Renewable Energy Board (NREB), which entitles them to a higher rate from utilities and in spot markets. The amount of the FiT is based on the NREB’s assessment of levelized cost by technology. This subsidy is funded through a national levy, and customers in the Philippines pay an additional line item in their monthly bill based on the percentage coming from renewable energy sources.

While the transition has not yet resulted in cost savings, the full benefits of transitioning to LCY tariffs will likely be realized over time. While the Electric Power Industry Reform Act was passed in 2001, it was not until 2009 that the last power station was sold to the private sector. Given the recent transition, remaining public obligations, and complexity of current markets, it is still too early to evaluate cost saving effects of transitioning to local currency.

INDIA

MACROECONOMIC DATA

The table below has economic and financial indicators for India, compared to the same for Kenya.

Table 27: Key indicators of India and Kenya (2017)81

Category Indicators India Kenya

Economy GDP $2.2 trillion $71 billion

Population 1.3 billion 48 million



76% 42%

Energy investment w/ private participation $135 billion $2.3 billion

80 Source: Stakeholder interviews 81 Source: World Development Indicators, World Bank


82


69% 35%

ENERGY MARKET HISTORY82

India’s generation capacity was 100% state-owned prior to the country opening to foreign investment in 1990. Early tariffs were denominated in USD and accompanied by a sovereign guarantee, but after numerous challenges in working with foreign IPPs (notably Enron), all PPAs have since remained denominated in Indian Rupee (INR). Despite this, the country has been able to attract IPPs, who negotiate PPAs with one of India’s multiple state-owned utilities.

IPPs have grown rapidly since 2000, and now own 44% of power generation capacity in India83. However, IPP growth has encountered challenges. Rapid investment in installed capacity and delays in grid expansion have resulted in a glut of supply, putting downward pressure on prices. Combined with fluctuations in commodity prices and availability of local supply of coal and LNG, this has resulted in stranded IPP-owned power generation assets left without a commercially viable fuel source.

Table 28: IPPs and Feed-in-tariff introduction84

82 India’s Primary Energy Evolution: Past Trends and Future Prospects, by Kaushik Deb and Paul Appleby, Group Economics, BP plc; Power - India Brand Equity Foundation 83 India Central Electricity Authority 84 Source: Renewable Energy Tariffs: Regulations and Design, by Rakesh Shah, Central Electricity Regulatory Commission; Terms and Conditions for Tariff determination from Renewable Energy Sources, Central Electricity Regulatory Commission



Year 1991 2009

Currency Rupee Rupee

Structure • Multiple state-owned generating and utility companies

• FiT for all renewable energy technologies – typically >13 years

• Fixed rate over life of tariff

Additional notes

• First interconnection of National Grid in 1991

• Owned, operated, and maintained by state-owned Power Grid Corporation

• Tariff rates reviewed every three years

• Goal to install 20 GW of solar power by 2022


83

Table 29: Current energy market


Installed capacity (MW) 308,000


56%


806



None

TRANSITION TO LOCAL CURRENCY TARIFFS85

India only briefly offered tariffs in USD, and has utilized INR tariffs for nearly 30 years. PPAs are typically fixed for 20 years, and often not indexed to a HCY or local benchmark like inflation or interest rates. The country has largely been able to attract IPPs because of its scale and market potential. In addition, India has a more developed manufacturing sector than Kenya, allowing IPPs to source construction materials within India in INR. Still, the current structure presents challenges, particularly for renewable energy IPPs.

Legislation in 2009 announced higher FiT rates for renewable energy, with a fixed rate over the life of the tariff (13-25 years). However, these rates are dropping rapidly based on technology costs, and for renewable energy they typically do not include a capacity charge. Paradoxically, this situation is made possible largely by the lack of contract enforceability in India. Many IPPs accept lower rates in order to get their PPA signed, assuming that they can find grounds to renegotiate in the future.

INVESTMENT IN IPPS86

While the Indian manufacturing and financial sectors are more developed than many countries in Southeast Asia or Sub-Saharan Africa, interviews with renewable energy IPPs revealed that a significant portion (up to 60%) of their costs and investment capital remain in USD. One solar IPP interviewed estimated 65% of their project costs were in USD, with a similar proportion of debt financing from foreign investors denominated in USD. The key reason for the high proportion of HCY financing is its lower cost of capital compared to INR financing. With PPA revenues in INR, this requires IPPs to shoulder hedging costs to avoid currency risk.

Similar to other LCY tariff environments, local banks have become active in power sector financing, though the financing has been limited from insurance and pension funds. IPPs have been able to find local equity investors, but a significant proportion of debt financing in the power sector still comes from abroad.

85 Source: Stakeholder interviews 86 Source: Renewable Energy Sector Funding, by Resurgent India; Stakeholder interviews


84

SOUTH AFRICA

MACROECONOMIC DATA

The table below has economic and financial indicators for South Africa, compared to the same for Kenya.

Table 30: Key indicators of the South Africa and Kenya (2017)87

Category Indicators South Africa Kenya

Economy

GDP $295 billion $71 billion



Financial sector

Domestic credit provided by financial sector (% of GDP)

67% 42%

Energy investment w/private participation $15.5 billion (2012-2016)

$2.3 billion (2002-2016)


323% 35%


Indicators Values Energy mix (MW)

Installed capacity (MW) 53,144


77%

Electricity Consumption (GWh annually)

240,000


TRANSITION FROM FEED-IN-TARIFF’S (FITS) TO COMPETITIVE BID PROCESS

The South African Renewable Energy Feed-in Tariff (REFiT) was introduced in 2009 by the National Energy Regulator of South Africa (NERSA). Initially, the ReFiT program started with strong support from IPPs, but the tariff structures led to unintended policy and regulatory uncertainty. NERSA had initially introduced tariffs that were too low and quickly revised the tariffs again when project developers made it clear that they considered them inadequate to incentivize investment. This revised tariff, fully-indexed for inflation and designed to provide an approximate return on equity of 17%, was met with satisfaction by project developers. It was not long after these attractive tariff levels had been accepted by the market that NERSA unexpectedly released a consultation paper on new tariff reviews that advocated another reduction. These haphazard amendments by NERSA to the tariff structure was

87 Source: World Development Indicators, World Bank 88 Source: IPP Procurement Program, Government of South Africa

3%

0%

Hydro

10%Landfill gas

Wind

3%

Solar

Gas turbine 3%

Coal

Nuclear

75%

6%


85

a key influence in the REFiT program’s shortcoming. This regulatory ambiguity ensured that not a single project materialized under the REFiT program.

There were other additional issues that resulted in the failure of the REFiT program:

• In 2011, the National Treasury questioned the legality of REFiT within South Africa’s Constitutional Public Procurement Framework. The Minister at the time, Dipuo Peters – believed that fixed tariffs were not fair, equitable, transparent and competitive as was the mandate for all state purchases for goods and services.

• In addition to this, Eskom, the public utility and off-taker had the mandate to administer procurement of new IPP projects. However, Eskom did not have a central procurement mechanism, and this led to delays in finalizing power purchase agreements and interconnection agreements. There are also thoughts that Eskom may have possibly sabotaged the success of REFiT by not supporting IPPs due to conflicts of interest with its own generation plans.

Based on the issues highlighted above, the Department of Energy was left with no choice but to re-introduce an entirely new program through the transition of a competitive bidding process for renewable energy – the Renewable Energy Independent Power Project Procurement Programme (REIPPPP).

Table 32: South Africa – Key dates and milestones in power tariffs



Year 2001 REFiT (2009), REIPPPP (2011)

Currency ZAR ZAR

Structure South Africa’s first experiment in privatizing power generation (2001)

Feed-in-Tariff introduced (2009)

National Treasury questions legality of REFiT (July 2011)

Competitive bidding process introduced via REIPPPP (Aug 2011)

Additional notes Kelvin Power Station is the only large privately-owned coal-fired power station in SA

Issues stemming from regulatory uncertainty curtail success of REFiT

Key stakeholders brought together to re-design new competitive bidding process

Increased competition resulting in reduced pricing especially across different technologies

The Renewable Energy Independent Power Project Procurement Programme (REIPPPP) was introduced in August of 2011 as an auction through the release of an RFP. The auction was structured as a rolling bid-window program that allows for both continued market interest and increased competitive pressure among bidders to participate and offer reduced pricing. The first auction was not fully subscribed but over time, with increased understanding of the REIPPPP, there was a change in perception. The risk of corruption was also deemed as minimal in the program, facilitating increased participation by investors.

Key considerations in the design of the REIPPP

• Facilitated the competitive process by allowing the market to find its clearing price

• Qualification criteria was indicative of a project’s bankability and allowed the market to filter projects


86

• Non-negotiable agreements allowed for early engagement with lenders to address key risks in obtaining the PPA

• There was on-going engagement with stakeholders to provide feedback and amend documents

The procurement approach of the REIPPP

• Multiple bid windows created multiple bidding opportunities to avoid a temptation to rush to meet all qualification criteria

• Bid in tariff provided competition in any bid window with tariff caps

• Capped MW allocation ensured effective competition

• Objective qualification criteria (to the extent possible), was objective and purposefully designed to elicit a pass or fail result

• Objective scoring and ranking of qualifying bidders was clear and transparent

To illustrate the success of the REIPPPP: 6,422 MW of new electricity supply has been procured from 112 renewable energy IPPs in seven bid rounds as well as 3,052 MW of electricity generation capacity from 56 IPPs connected to the national grid89. By achieving a competitively priced and clean energy bid program, the REIPPPP has proven to be a success in attracting substantial private sector expertise and investment into grid connected renewable energy sources at competitive prices.

INVESTMENT IN IPPS

South Africa has one of the most developed financial markets in Africa90:

• The Johannesburg Stock Exchange (JSE) is the 19th largest exchange in the world and largest exchange on the continent with a market capitalization of USD 1 trillion as of end of 2013.

• The total assets under management by pension funds and assets managers was about R12 trillion (USD 925 billion) as of 2015. Furthermore, Regulation 28 which is the governing law for pension funds in the country allows up to 10% of pension assets to be invested in private equity, an increase from the previous 2.5% allowance for all ’other’ asset classes. For example, the South African Government Employees’ Pension Fund (PIC), with over USD 1 billion in assets is one example of a pension fund that has made investments in renewable energy projects such as solar power and there are numerous others as well.

• As of March 2017, power projects under IPPPP had attracted investment (equity and debt) to the value of R201.8 billion (USD 15.5 billion) of which R48.8 billion (USD 3.75 billion) (24%) is foreign investment. (R12.97/USD).

Figure 39: Distribution of investment between domestic and foreign investors

89 Source: South Africa’s Renewable Energy IPP Procurement Program: Success Factors and Lessons, World Bank 90 Source: World Bank, Government of South Africa, Desk research

22%

73%

27%

78%Debt

Domestic

Equity

Foreign

24%

76%

Foreign equity andfinancing share

Domestic equity andfinancing share


87

Based on the competitive bid process initially conducted in the auctions between 2011-2013, certain trends emerged on the financing of the projects:

• 56 out of the 64 bids were project financed, with one proposing a corporate bond, and a small hydro project being corporate financed. The latter, was eventually restructured and financed primarily via debt. Reports indicate that return on equity for the corporate funded projects in the subsequent bid rounds was low (approx. 12-13%).

• As more renewable projects have been completed under the program there is a perceived reduction in the financial risks of power projects. This is in part due to increased knowledge of renewables in the country as well as robust project finance expertise in-country.

• The trend toward corporate financing in REIPPPP may or may not continue, but it is likely that more International utilities will be interested in entering the South Africa renewable energy market, especially European utilities struggling to grow market share in their home markets.

RESULTS OF REIPPP

Several elements have contributed to the success of the REIPPP program.

• The procurement process was well designed. Recognizing that there was little institutional capacity to run a sophisticated, multi-project, multibillion-dollar international competitive bidding process for renewable energy; South Africa’s Department of Energy with funding from the National Treasury’s Public-Private Partnership Unit hired local and international transaction advisors to assist in the design of the program. This allowed advisers to draw on both knowledge and experience of other renewable energy markets ensuring a well thought out design of the program.

• High standards were set for the bidding process - the Government ensured strict adherence to the bid requirements. The launch of the REFiT program two years before the transition to REIPPP had allowed participants to identify sites and begin resource measurements and thus, were more prepared for the transition to the REIPPPP. For example, despite a tight time schedule and tough qualification criteria, the REIPPP program attracted 53 bids in the first round and 51 in the second round. The government was also keen to learn from previous mistakes made on the REFiT program ensuring that good communication and market readiness were given attention.

• Flexibility in the design of subsequent bidding rounds was adjusted and incorporated swiftly. For example, the capacity made available in the first round of bidding exceeded the capacity that could be delivered by the market. In round two, the capacity tendered was reduced to encourage more competition.

• The renewable energy sector was highly competitive, due to the increased pool of project developers who could participate in renewable energy. This was further enhanced by the specialization of most renewable energy technologies. For example, when South Africa ran its first competitive tender for IPPs— only two bids were received for two large gas turbine peaking plants and one was withdrawn shortly after.

• Subsequent bidding rounds incorporated more stringent thresholds as well as targeted criteria for local content objectives, which resulted in employment creation.

• The local capital market responded positively to the opportunity presented by the REIPPP program, with total investment estimated at US$15 billion in its 3,000+ MW of renewable energy.

• Commercial banks were willing to finance construction, and some continued on-selling debt to insurance companies due to competing demands in other South African infrastructure sectors.

• REIPPP program stretched local banks, and other sources of funding, such as pension funds, were mobilized.

• Real returns to equity in round one was estimated to be close to the 17 percent (in local currency) and this provided a platform in determining the original feed-in tariffs. Equity returns


88

dipped slightly in round two for wind and probably more substantially for photovoltaics. Dollar returns in the range of 12% –13% were reported91.

• Project bidders were required to incorporate a tax of 1 percent of project revenues into a government renewable energy fund to support subsequent procurement programs.

Table 33: Pricing trends92

REFiT REIPPPP (ZAR/kWh) REIPPPP ZAR/kWh)

2009 Tariff 2011 Tariff Bid Cap Round 1 Round 1

Wind 1.25 0.94 1.15 1.14 14.3

Photovoltaic 3.94 2.31 2.85 2.76 34.5

Concentrated solar trough with storage

3.14 1.84 2.85 2.69 33.6

The depth and liquidity of South Africa’s financial and capital markets has been the main driver for LCY funding for IPPs. The main commercial banks have dominated REIPPPP lending: Standard (17 Projects), Nedbank (23 Projects), Absa (14 Projects), Rand Merchant Bank (11 Projects) and Investec (4 Projects). These banks have either played lead or co-lead debt-arranging roles and participated in several projects as providers of subordinated mezzanine debt.

This financial superiority and market depth has allowed debt tenors to reach 15 years and at times, 17 years from the Commercial Operation Date (COD); with spreads on the benchmark (JIBAR) ranging between 310 and 400 points i.e. (risk premium: 250; liquidity: 120; and statuary costs: 30 points).

In addition to this, the creation of a well-designed program with input from key stakeholders in the country has ensured that knowledge and expertise both locally and internationally is well embraced. Stakeholders in the program received an opportunity to voice their concerns at inception and thus, reduced the regulatory and market uncertainty that had overwhelmed the REFiT program. The government also showed a willingness to learn from its previous oversights in the ReFiT program by creating an enabling environment with strong policy and government support as well as a fair and transparent evaluation process. Furthermore, declining equipment costs and the competitive bidding nature of the program also ensured a reduction in bid prices and by design reduction in tariffs.

TANZANIA

MACROECONOMIC DATA

The table below has economic and financial indicators for Tanzania, compared to the same for Kenya.

Table 34: Key indicators of Tanzania and Kenya (2017)93

Category Indicators Tanzania Kenya



GDP per capita $846 $1,455

91 Source: South Africa’s Renewable Energy IPP Procurement Program: Success Factors and Lessons, World Bank 92 Source: Comparison of IRP assumptions with actual IPP tariffs, a feed-back loop between planning assumptions and actuals, CSIR Energy Center 93 Source: World Development Indicators, World Bank, Government of Tanzania, Desk research

Before and after the

introduction of the Bid process


89


17% 42%

Energy investment w/ private participation $630 million $2.3 billion


24% 35%

ENERGY SECTOR OVERVIEW

Tanzania is bestowed with numerous sources of energy, which include biomass, hydro, uranium, natural gas, coal, geothermal, solar and wind. Biomass provides more than 80% of the country’s energy need through firewood and charcoal, primarily in the rural areas. One of the major reasons for the high reliance on the biomass is because of very low connectivity of the population to electricity. As per the most current available statistics, less than 30% of Tanzania’s population is connected to electricity through the grid.

Tanzania has an installed capacity of approximately 1500 MW. Although the current unrestrained peak demand is estimated at 1000 MW, it has been projected to grow at 10-15% per annum due to the various development policies put in place by the government. Natural gas is the largest contributor to Tanzania’s energy mix, followed by hydro. The Government has put in place ambitious plans to increase the installed capacity. Renewable energy including the smaller power producers are integral part of the Government’s initiative because of the low carbon footprint of such sources.

Tanzania developed its first National Energy Policy (NEP) in 1992, as a result of the socio-economic changes that were sweeping through the country at that time. The NEP was subsequently revised in 2003 and again in 2015. Tanzania changed legislation in 1992 to allow private sector participation in the power sector due to market liberalization. Currently 42% of the country’s installed capacity is owned by the private sector. Tanzania introduced a feed-in tariff scheme for small power producers (100 kW to 10 MW) in 2008 with the framework being reviewed in 2015. In the Second Generation SPP (Small Power Producer) framework, EWURA applies two approaches depending on the technology: Renewable Energy Feed-In Tariffs are applied for small hydro and biomass projects whereas a bidding approach is applied for solar and wind projects. The Second Generation SPP framework is based on guiding principles that include SPPs receiving a fixed tariff for the duration of the Small Power Purchase Agreement (SPPA). However, to date we did not find any projects that have been awarded using the bidding process. Tanzania enacted the Public Partnership Act law in 2010 which set the framework for public participation in provision of public services like electricity. The law was passed to encourage private sector participation in the power sector because it provides a defined framework for implementation of projects.




1,564


59%

Electricity Consumption per Capita (kWh, 2014)

133

Electrification rate <30%

94 Source: TANESCO


90


None

LOCAL CURRENCY TARIFFS To promote private sector participation in the power sector, the feed in tariff for small power plants (<10 MW) was introduced in 2008. The tariff was denominated in Tanzania Shillings (TZS). However, the transition was unsuccessful. This was primarily due to a reason not concerning currency, but the credit worthiness of the offtaker, TANESCO. Investors requested for a guarantee or letter of support from the Government of Tanzania, but this was not forthcoming. As such, few projects were executed. At the same time, there was limited LCY finance available from local banks. The few projects that were implemented under this regime were undertaken by local corporations who financed using their balance sheet.

In 2014, the developers lobbied to the Government to revise the standardized PPA with the intention of denominating the tariff in USD. The Government, with the support of the World Bank, conducted a study and issued a revised standardized PPA in 2015 with the tariff now denominated in USD, but payable in TZS at the prevailing rate on the date of payment. Although there was a small drop in the tariff, there was increased interest in the power sector from investors resulting in a few PPAs being signed.

INVESTMENT IN IPPS

The banking sector in Tanzania is relatively traditional in its exposure, with minimal participation in infrastructure. The lending capacity of the sector is limited, with a maximum loan of USD 70 million. To limit exposure, lenders are only likely to lend up to 10% of the maximum amount for a transaction. In addition, banks also have limited technical knowledge of the power sector, thus are unable to adequately evaluate power sector investments and structure project finance transactions. There is little to no investment by domestic institutional investors.

37%

21%

39%

2% 1%

Hydros Oil Gas Biomass Imports


91

ANNEX 5: INTERVIEWS CONDUCTED FOR THIS STUDY

Table 36: List of interviewees

Stakeholder type Organization Contact Position

Financiers Fund Managers / Asset Managers / PE

PineBridge / Sanlam Nicholas Malaki Chief Investment Officer / Senior VP

African Alliance Stephen Muriu CEO

Stanlib Humphrey Gathungu

Chief Investment Officer

GenAfrica Fahima Zein Chief Investment Officer

Insurance companies

Britam James Mose Portfolio Manager

ICEA Lion Einstein Kihanda CEO, ICEA Lion Asset Managers

Jubilee Insurance Edwin Gitaka Investment Manager

Commercial Banks

Equity Bank Rohit Singh Group Director of Corporate Banking

Standard Chartered Christopher Kirigua Executive Director & Head of Public Sector

Citi Michael Mutiga Corporate and Investment Banking

Barclays Bank Michael Awori Regional Head of Debt Finance

CBA William Muguima Head of Corporate

Stanbic Jonathan Muga Head Mining, Energy, Infrastructure (East Africa)

Multilaterals / DFIs

IFC Richard Warugongo Senior Investment Officer, Africa Infrastructure

AfDB Farid Mohamed Infrastructure and Private Sector Investments

GIZ Tanja Faller Head of Regional Programs on Energy

Norfund Inge Stolen Senior Investment Manager

Proparco Mercyline Njoroge Investment Officer

TDB Group Joseph Mate

DEG Ragnar Gerig Direct of Energy, Africa and Asia

AFD Lucie Astier Project Officer, Financial Institutions and Private Sector Support

Sponsors / Developers

Local Kleen Energy Rosemary Mugo Director

Kenergy Renewables Khilna Dodhia CEO

TransCentury John Mugo Division Head, Power

Astonfield Ameet Shah Co-Chairman and Director

Kajire Energy Wanjau Wambugu Director


92

Stakeholder type Organization Contact Position

Esham Park David Kinyua, Stephen Gugu

Director Consultant

International Frontier Energy Bernard Osawa Project Director & Partner

Berkley Power Nikhath Zigmund Investment Manager

Quantum Power David Caroll Director

Tembo Power Raphael Khalifa CEO

Solar Century Roberto Martin Business Development Manager

responsAbility Raoul Ilahibaks Senior Associate

Government National Treasury, PPP Unit

Teodoro Regino Technical Expert

National Treasury Livingstone Bumbe Deputy Director, Debt Management

Central Bank of Kenya Dr. Patrick Njoroge Governor

Utilities KenGen Simon Ngure Acting CFO

Kenya Power John Ihuthia Regulatory Affairs Department

GDC George Muia General Manager Strategy, Research and Innovation

Regulators Capital Markets Authority

Paul Muthaura CEO

Retirement Benefits Authority

Nzomo Mutuku CEO

Other London Stock Exchange Nirmal Nandwani Associate


93

ANNEX 6: SAMPLE CLASSROOM TRAINING SCHEDULE O

bje

ctiv

es

For financiers (staff; Board of Trustees)

• Increase understanding of the power sector and the associated risks • Improve exchange of expertise on technology roadmaps, data on risks

and returns, market forecasts, analytical tools to assess risk, etc.

For IPPs, sponsors

• Improve understanding of financing options, risk mitigation during project construction

• Increase competency in contract management

For all • Increase awareness of the financing and credit enhancement mechanisms available

Training design

Two day sessions, every quarter for three quarters, consisting of: • Classroom learning: To teach core principles. Sessions will include:

– Presentations on key topics – Exercises to apply new concepts – Group discussions and experience sharing

• Field visits to power plants; Talks by market actors, e.g. financiers and IPPs who have deal-making experience, as well as government representatives

• Activities between sessions: – Material for self-learning and the ability to revisit concepts – Peer-to-peer group learning. Formation of learning groups, offering space

to discuss and engage with content

Quarter 1: Financiers; Optional to IPPs

• Understanding different technologies

• Life cycle of the project and assessment of the risks at different stages of the project

• Key competencies required to reduce risk: Risk assessment to focus on events that would impact the revenue generating ability of the project, which ultimately affects loan repayment capability

• Field visits to power plants (different technologies).

Quarter 2: Financiers and IPPs

• Project financing – Financing mechanisms – equity, debt, mezzanine

– Special Purpose Vehicles • Credit enhancements and financial instruments available in Kenya,

including collaborative arrangements, e.g. banks take the construction risk and after COD sell down partial exposure to institutional investors

• Loan and credit evaluation, best practices • Talks by financiers with real life deal experience

Quarter 3: Financiers and IPPs

• Deal origination and development of project pipeline – Identification of potential deals, and sources of deals in the market (e.g. energy service companies, equipment vendors, utilities, etc.)

• Areas to address during preparation and negotiation of various contracts including implementation agreement, PPAs, EPC contracts, O&M contracts

• Kenya’s energy policy and regulatory framework – Presentations by MoE, ERC, Kenya Power


94

ANNEX 7: ASSUMPTIONS USED FOR TARIFF INDEXING

All project development and construction costs are assumed to be financed with LCY. Following are the assumptions used for opex.

Technology Staffing costs Equipment (spare parts) costs

Insurance costs

Hydro As % of capex 0.5% 1.5% 0.75%

Incurred in HCY 0.0% 80.0% 80.0%

Incurred in LCY 100.0% 20.0% 20.0%

Geothermal As % of capex 0.5% 2.0% 0.5%


Incurred in LCY 100.0% 20.0% 20.0%

Wind As % of capex 0.4% 3.75% 0.5%


Incurred in LCY 100.0% 20.0% 20.0%

Solar As % of capex 0.24% 0.8% 0.4%

Incurred in HCY 20.0% 100.0% 80.0%

Incurred in LCY 80.0% 0.0% 20.0%

Biomass As % of capex 0.7% 3.5% 0.2%


Incurred in LCY 100.0% 40.0% 100.0%

Other assumptions:

Cost of debt in LCY 13.7%

Project/PPA Term (years) 20

LCY Debt repayment period (years) 15

l c ocal urrency-denominated tariffs for ......dalberg; elsie mbugua, nandu hirani and anthony ngugi...

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