On November 10, 2020 the Asian Development Bank (ADB) approved a USD 200 million Policy Based Loan (PBL) to the country of Uzbekistan. The PBL can be used for general government budget support, but the loan is based on key policy updates that target the electricity sector, especially the distribution networks in the country.  I was honored to provide support to the program by conducting the economic and financial analyses for the loan and policy reforms.
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Policy-based lending has been a practice of the ADB since 1978 but has seen most of its growth since the Global Financial Crisis of 2009. A country’s primary motivations for seeking PBL are to achieve a quick response to immediate financing needs and for valuable policy advice / technical assistance for a particular sector’s growth. In Uzbekistan, the program provided critical budget support and targeted policy actions aimed at restructuring the power sector to enable competition and create a conducive environment for private investment. Specifically, the reforms target the following areas: 1) power sector restructuring and strengthened regulation; 2) financial sustainability for sector entities; 3) decarbonizing the sector; and 4) improving demand side energy efficiency. Economic benefits include: 1) loss savings, 2) carbon savings, and 3) demand side efficiencies.

The following summarizes the analysis[1]:
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1.Sector Overview
Uzbekistan is the largest electricity producer in Central Asia and remains a net exporter of power. Total available capacity in Uzbekistan is about 12,500 megawatts (MW) from 25 power plants. Approximately 88.8% of electricity generated in 2019 was from fossil-fueled thermal power plants (93.5% of thermal power is from natural gas) and the rest was from hydropower (12%). However, sector assets are operating at low levels of efficiency, and energy losses across the system are high. These results are due to (i) a lack of investment, (ii) inadequate governance, and (iii) poor financial performance.

A lack of investment in new and existing assets has led to aging infrastructure and an overloaded system. Nearly 40% of the nation’s generation capacity is either past or close to the end of operating life. Because of their age, transmission and distribution line losses are high, approaching 20% of net generation. As a result, operation and maintenance expenses are on the rise, blackouts are becoming more common, and system performance is in decline. Costs to repair the system will be much greater than public money alone can provide, meaning private sector funds will be required.

Inadequate governance has also led to inefficiencies. Regulatory decisions have been made among a confusing array of entities and agencies, while tariffs were set at government levels that are out of touch with the immediate sector needs. Furthermore, there has been no clear investment planning process, nor a clear framework for introducing private investment into the sector. The consequence has been poor returns on investment because decision-making does not pursue least-cost options, nor do investments necessarily align with long-term needs.

Finally, financial performance has been in decline. According to World Bank analysis, the sector’s quasi-fiscal deficit (the difference between actual revenue and full cost and loss recovery) had grown to $550 million, which was 0.7% of GDP in 2016. The 2017 deficit was higher still, due to a local currency revaluation against the US dollar. One impact of the devaluation was an effective doubling of external debt; the episode cost the electricity sector about $870 million.

2.Government Response
In response to the declining performance, the government has initiated the following reforms designed to improve performance and induce private sector investment: (i) demonopolize the sector, (ii) introduce a new tariff methodology, and (iii) develop a framework for tendering renewable energy projects. The ADB program is meant to support these policy reforms.

3.Benefits of the Program
Benefits of this program fall into three categories: 1) loss savings, 2) carbon savings, and 3) demand side efficiency.

a.Loss Savings
With the reforms, the sector will be able to (i) fully capture anticipated growth and (ii) reduce system losses. The net present value of these benefits is estimated at $344 million[1]. As a related fiscal benefit, the government will be able to reduce its significant subsidies, thereby saving budgetary resources for more strategic uses.

Fully captured growth. Load growth is expected to increase at a rate of 2.2% over the next 10 years based on historical demand trends and macroeconomic growth forecasts. Currently, inefficient generation and aging system assets have increasingly led to an inability for the sector to meet growing demand. Though Uzbekistan is fully electrified, the quality of service is poor and unreliable because of transmission bottlenecks and aging power plants. Unreliable power supply negatively impacts livelihoods and the profitability of many businesses.

According to a World Bank Enterprise Survey in 2019, electrical outages happen twice a month, on average, and each episode lasts 2.3 hours. Business losses due to outages amount to 3.0% of annual sales of enterprises, which is worse than the regional average. The issue is even more pronounced in rural areas, and during winter, when demand surges. In these cases, blackouts are common and last 2–6 hours a day. The policy actions will help the sector respond to increased demand through deployment of large-scale solar and wind projects. Investment in efficient combined-cycle gas turbine (CCGT) generation and improved transmission and distribution will also help to reduce this unserved energy.

Reduced line losses. Transmission and distribution losses have grown to nearly 20%, largely offsetting government attempts to modernize the system. Modernization of the network, paid for by sustainable revenues, will allow transmission and distribution companies to address technical and operational inefficiency problems, improving loss rates. Reforms include the digitalization of grid system by introducing a modern SCADA system and measures to “green” the distribution networks while improving service quality.

Under the reforms, the transmission network is expected to improve from loss rates of 2.4% (of energy supplied to the network) in 2020 to 2.2% by 2025. A more significant improvement is expected at the distribution level, where nationwide losses averaged 15.1% in 2017 (of delivered energy)—a figure five times higher than high-income nations. By 2019, losses were 14.5% of supply and, with the reforms, are expected to fall to 8.9% by 2030. The total energy savings over 10 years would be 21.9 TWh, and a cumulative benefit equal to 5.8% of 2019 GDP.

b.Carbon savings
A second benefit to Uzbekistan emanates from carbon savings. The replacement of electricity sourced from natural gas with electricity from renewable sources will save significant amounts of gas that would normally be consumed by domestic power production, resulting in a mitigation benefit from lower levels of CO2 emissions. With the reforms, annual consumption of natural gas by the electricity sector is expected to fall from 12.3 billion cubic meters (bcm) in 2019 to 5.8 bcm by 2030, from the modernization of the generation fleet and the introduction of renewable energy. As a result, total carbon produced by the sector is expected to fall from 22 million tons (MT) per year in 2020, to approximately 17 MT in 2028 and beyond, leading to a cumulative savings of $383 million.[1]

c. Demand side efficiency
Finally, demand-side efficiency is addressed through regulatory standards and energy savings targets. A government program aims at reducing energy intensity (energy per unit of GDP) by 8%–10% annually in key sectors. Advanced energy savings technologies will be introduced from 2020 through 2030, including the replacement of heating boilers in thousands of buildings, upgrading electric motors and water pumps operated by the Ministry of Agriculture, and outlawing the importation of inefficient household appliances. Demand-side efficiency benefits will especially accrue to the commercial sector as these initiatives help to modernize energy-intensive industries over time, allowing for cost savings and increasing global competitiveness.

4. Conclusion
The implementation of the reforms will result in significant, targeted improvements in the electricity sector for Uzbekistan. The combination of policy actions can help to address the country’s overarching development objective, inclusive and market-led power sector development. As part of the process, the policies will enable competition, facilitate private investment, and enhance governance, accountability, and financial sustainability, while driving operational efficiency. These outcomes are vital to sustaining long-term economic growth.
The complete economic assessment can be viewed here, and all documents related to the program can be found here

[1] ADB. 2020. Program Economic Assessment, Power Sector Reform (Subprogram 1) (RRP UZB 54269).
[2] Total incremental and non-incremental benefits are $3.31 billion over 10 years, against costs of 1.8 billion. The discount rate used was 9%.
[3] The social value of carbon is measured as $36.3 beginning in 2016; an inflation factor of 2% is added for subsequent years.  

The transition to a global, low carbon, and climate resilient energy future may require an investment of nearly $7 trillion per year, over the next 15 years.[1] About $3.9 trillion of this total arises from developing countries, which are currently spending $1.4 trillion annually, leaving an “investment gap” of $2.5 trillion. Private sector financing is often touted as the only viable source of capital to fill that gap. As a result, development finance institutions (DFIs)[2] are committed to increasing private sector financial participation to meet climate-related energy and infrastructure goals. The most likely sources at this scale are called institutional investors - insurance companies, pension funds and sovereign wealth funds. But these investors have been relatively disengaged from this type of investment.

One motive to engage these investors is their size. Institutional investors in OECD countries alone control about $92 trillion in assets.[3] To put this in context, official development assistance (ODA) from traditional multilateral and bilateral sources is about $147 billion annually. This is less than 1% of the assets on the balance sheets of institutional funds, and just 5% of the developing country investment gap mentioned above. According to a recent OECD publication, Mobilizing Institutional Investor Capital for Climate Aligned Development,[4] DFIs now face an excellent opportunity to engage institutional investors, if they take the right approach.

Institutional investors appear ready for partnerships with DFIs. Large investors are collaborating more with like-minded partners, and several priorities behind the collaboration fit DFI strengths: to get closer to investments (to better assess and manage risks), to increase deal flow, and to reduce expenses from intermediaries, due diligence and monitoring. These priorities could be met by DFIs, which would open the door to a mutually helpful arrangement. The big investors do not appear too exclusive about their partnerships, meaning synergies with DFIs are certainly possible.

According to the OECD authors, there is another group of investors, to whom the DFIs should pay attention, especially as a model. Green Investment Banks (GIBs) and Strategic Investment Funds (SIFs) have been the most effective at mobilizing private capital for climate-related purposes, including from institutional investors. Both are quasi-governmental entities that are embedded within a local community and have a strong private-sector mentality. GIBs are publicly capitalized entities with a mandate to facilitate privatesector investment for low carbon initiatives.[5][6] SIFs are equity investment organizations, typically established to achieve a policy objective and often to target private finance partners.[7]

One key to the success of GIBs and SIFs has been their “localness,” most importantly manifest in their ability to assess and manage local risk. Infrastructure investments are necessarily local, and it is famously difficult to understand local risks from afar. Both GIBs and SIFs are established and networked inside local business and political communities; and they possess an intimate understanding of market and regulatory frameworks that govern the energy sector in their neighborhoods. So, not only can they identify and assess project risks, but they also have a better ability to monitor and manage those risks through the stages of project development and service delivery, than someone overseeing the investment from a distance.

Further, GIBs and SIFs are governed by private sector financial principles and managed by private finance professionals. By contrast, DFIs are governed and managed from a public finance perspective. The differences can be felt in terms of investment decision making, the speed and agility by which decisions are made, and the viability of projects in the investment pipeline. The authors of the OECD article suggest several strategies for DFIs to more closely emulate these local organizations; I summarize them here:

1. Involve private sector investors early in the project development process. Too often private investors are brought into the process at the end, with little opportunity to affect the project.
2. Staff up with people who speak the language of finance and risk. MDBs are often staffed by people with sector specific experience. Hiring those who can bridge the communications gap will be helpful.
3. Move to a “pull” strategy. Institutional investors have a fiduciary mandate for the funds they manage. Rather than push institutions toward projects they are skeptical about, DFIs should actively seek investors’ concerns about development initiatives, and then co-create strategies with them to overcome their concerns.
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These adjustments may be difficult to make, but the rewards could be significant; and they may be necessary to move from delivering “billions to trillions” in climate-related finance.

Matching loan terms with useful life could help accelerate private financing for hydropower.

Hydropower has seen a resurgence over the past two decades, growing by over 500 GW since 1999 worldwide.[1] With the importance of a global transition to both modern and renewable power, it’s easy to see why. Large hydropower can help to drive economic development in places such as Southeast Asia and Africa. It can also serve as a backstop for more variable renewable energy sources, such as wind and solar. In fact, the ancillary services provided by hydropower such as black start capacity and frequency regulation, plus the ability to supply peaking power cheaply, make hydropower an essential component to a well-balanced energy system.

However, large scale hydropower projects bring unique risks, which has meant that private holders of finance have often been reluctant to invest. In Africa, the lack of available private financing for hydropower is a key constraint. This is unfortunate, because only about 8% of Africa’s hydropower potential has been tapped, leaving a huge unmet market need, and lots of ROI on the table. Further, when private finance is included, it often comes with restrictive terms that make projects less tenable.

As one key example, there is a disconnect between debt tenor and the useful life of most facilities. Hydropower plants can often produce for 50 years and more, but debt maturities from many institutions are rarely longer than 15-18 years, and sometimes shorter.[2] This arrangement forces tariffs unnecessarily high during the early years of operation in order to meet debt servicing obligations; it also has the effect of limiting debt-equity ratios to preserve higher debt coverage. For a large project with which I am very familiar, the difference between a 15-year and 30-year tenor drives the tariff up by nearly 15%, holding all else equal.

All of these effects make privately funded hydropower less competitive than many other power sources. So, most recent projects have been completed with public funds since public funds tend to come with longer maturities and concessional lending rates. But public funding introduces different problems. It can drive down the cost of electricity, distorting tariffs and skewing incentives, potentially discouraging other generation investments.

Today there is a growing consensus to increase private investment across all infrastructure types. One way to do this, as advocated by Africa50,[3] is for development finance institutions to help private lenders extend loan tenors toward 30 years for hydropower, by offering partial risk or credit guarantees. With the resulting higher credit rating, projects can look more attractive to institutional investors that have an appetite for long-term bonds. Governments can also help by offering longer-term power purchase agreements and pursuing policies that deepen local capital markets.
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Global hydropower generation is forecast to increase 9.5% by 2025, rising from 4,250 TWh to 4,650 TWh, not including pumped storage.[4] It will also likely remain the world’s largest source of renewable generation. But to fully realize a renewable transition, hydropower will need to play an even larger role. To realize this role will require flexibility by all stakeholders, and a renewed commitment to creative financial thinking.


[1] International Hydropower Association

[2] Brookings Institution. “Enhancing the Attractiveness of Private investment in Hydropower in Africa.” 2018.

[3] Africa50 is an “infrastructure investment platform that contributes to Africa's growth by developing and investing in bankable projects.” (From the company website.)
 
[4] International Energy Agency. 2020. “Renewable energy Market Update; Outlook for 2020 and 2021.”
 

As the COVID-19 pandemic began to reveal its seriousness in early 2020, renewable energy market predictions for hydropower, solar and wind were dire; but the realities have turned out quite differently. The IEA’s 2020 Outlook, published in May, predicted: “…additions of renewable electricity capacity will decline by 13% in 2020 compared with 2019, the first downward trend since 2000.” However, a more recent “Renewables 2020” anticipates a year of
excellent growth, once all data has been compiled. “In sharp contrast to all other fuels, renewables used for generating electricity will grow by almost 7% in 2020.” Despite the pandemic, both 2020 and the future look positive for hydropower, solar and wind.

Hydropower additions grew by more than 18 GW in 2020, with significant large project installations in China, Lao PDR, India, Nepal, Viet Nam and Indonesia. In Europe, new projects in Portugal (pumped storage) and Turkey (large dams) helped to increase capacity additions. Over the next five years, global hydropower is expected to add about 10 GW to 13 GW annually, not including China. Asia will likely account for over 40% of that growth, led by India and Pakistan. Much of the remainder will occur in Southeast Asian countries where the private sector is becoming increasingly involved in hydropower development. China is expected to see the largest national increase, likely exceeding 107 TWh. Growth in Latin America is being led by Colombia, Argentina and Brazil. Overall, global hydropower generation (excluding pumped storage) is forecast to increase 9.5% by 2025, rising from 4,250 TWh to 4,650 TWh, and to remain the world’s largest source of renewable generation.

Solar PV additions are expected to have reached 107 GW in 2020, though progress across application segments has been uneven. For utility-scale projects, COVID-19 delayed construction activity in March and April but progress picked up in May. Initially, projections were for a drop in these large-scale installations, but instead both the U.S. and China saw growth (3% from the U.S. and 33% from China). Industrial installations fell as the global economy tightened, but a shift in demand toward residential load precipitated an increase in home installations. It is anticipated that 2021 will be another record year globally, with a 10% rise over 2020 and installations of about 117 GW.

Wind capacity additions are expected to have reached 65 GW by the end of 2020, 8% more than in 2019. Again, COVID-19 led to a slowdown in onshore construction between February and April because of global supply chain disruptions and logistical challenges. By contrast, the offshore sector was only mildly affected because longer project lead times mean short term disruptions have a smaller impact. For 2021, the forecast assumes a further acceleration of wind additions to 68 GW, 7.3 GW of which will be offshore.
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What began as a seemingly devastating circumstance for the energy transition, has instead demonstrated a resiliency in the sector.
 
SOURCES:
International Energy Agency. May 2020. “Renewable energy Market Update; Outlook for 2020 and 2021.”
International Energy Agency. November 2020. “Renewables 2020; Analysis and Forecast to 2025.”
International Energy Agency. July 2020. “World Energy investment 2020.”

Real options analysis captures the value of flexibility in hydropower design that other decision-making processes may not.

The academic journal Renewable Energy Focus has recently published one of our collaborative research articles. The article highlights valuation techniques at hydropower plants when risks of climate change and other uncertainties are high. Here is part of the abstract, with a link to more.
Development strategies on the African continent include significant hydropower investment to meet a growing energy demand. However, long-lived assets, such as hydro facilities, face climate risks, among others, that shorter-term investments may not. Various tools for quantifying these risks and offering decision-makers some guidelines for investment strategies, particularly under climate uncertainty, are increasingly used to evaluate broad policy choices and specific investment decisions. Given uncertainties such as climate change, and the wide range of decision-making levels, all available tools have a role, depending on the need of the decision-maker. However, not all yield the same result under all circumstances.​

This paper reviews three methods of analysis for decision making under uncertainty: Benefit-Cost analysis under uncertainty (BCA), Robust Decision Making (RDM), and Real Options Analysis (ROA). The paper then illustrates each within a project, the Batoka Gorge Hydropower Facility. We find that within the context of Batoka, the three analyses point to similar design choices with one important exception: Real Options offers values for the flexibilities embedded in projects or suites of projects, whereas the others do not incorporate these valuations. Furthermore, we find that flexibility, especially when integrating multiple risks into the project, creates value in smaller designs, such that the NPV exceeds that of inflexible, though larger designs.
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To read the full article, follow this link: https://authors.elsevier.com/a/1a8Ha6F2kzMSYY. 

In India, inefficiencies in the national power sector may be costing the nation 4% of GDP per year according to a new World Bank report.* Instead, with the right investment, universal connection to grid power could increase the income of rural households by $9.4 billion a year; and, eliminating power shortages may prevent an estimated $22.7 billion in business losses annually.*
 
According to the report, 178 million people still lacked access to grid-delivered electricity in 2017; and, many suffered from frequent power cuts, dragging down economic production. These present realities stand in the context of forecasts by which India may well triple its electricity demand over the next 20 years.
 
Still, India has not been idle regarding this sector. India’s electricity system has seen rapid growth in both supply and demand, over the last 5 years. In fact, over 130 million people have been connected since 2013, the result of new generation construction, and significant investment in both transmission and distribution.*
 
Despite progress, both capacity and energy remain at deficit levels, though the deficits are shrinking. The Table shows India’s capacity and energy demand and supply, deficits and shortages during the past 5 years. Figures are from India’s Ministry of Power Annual Report.**
 
India's national energy supply, demand and deficits (in million units, TWH)

​Inefficiencies are found all along the power sector value chain. India’s electricity system is predominantly coal-based; the nation has the fourth largest coal reserves in the world. Despite the availability of fuel, India fails to meet demand (by 14% in 2016 according to the report) because of a lack of competition and inefficient mining methods. Only 10% of underground coal mines are mechanized, and the average output per labor shift is less than one twenty-fifth of that in the U.S. Further, the inefficient and over-use of coal is causing significant negative health effects on the population. Subsidies and inefficient generation, transmission, and distribution also play a role in shortages (75% of India’s generation capacity if from coal). Losses in transmission and distribution exceed 20% - a much higher rate than elsewhere in the world.
 
Recommendations of the report go beyond the simple liberalization of energy prices; without solving other issues, prices would merely reflect all inefficiencies and be unreasonably high. Instead reforms should prioritize efficient coal allocation and delivery, promote competition in both fuel and electricity supply, and then allow electricity prices to reflect the true cost of supply. In this way the right incentives will be present to promote investment. Social assistance can then be targeted to help those in need to cope with higher prices.
 
To see the report, click here.
To watch a short video about India’s power sector, click here.

* Zhang, F. “In the Dark; how much to power sector distortions cost South Asia?” World Bank, 2019, Washington DC.
** India’s Ministry of Power, 2018-2019 Annual Report, 2019, p. 18-19.

The Nam Theun 2 Hydropower (NT2) energy export project in Lao PDR, illustrates a unique blend of financing vehicles for a large power project. It closed in 2005 and began operations in 2010, allowing several years of retrospect for lessons to be learned. According to a World Bank review, “Nam Theun 2 demonstrates that it is possible to privately finance a large and complex project in a small and economically weak country. It also demonstrates how a single project can dramatically improve economic growth and contribute to poverty reduction and environmental protection (Head, 2006).”

The project was large with power production of 1,075 MW; 95% of is sold to Thailand, and the remaining 5% to Lao PDR. When the NT2 closed its financing, it was the largest ever foreign investment in Lao PDR, the world’s largest private sector cross-border power project financing deal, and the largest hydroelectric project ever to use private sector financing (World Bank, 2005).
 
The financing structure of NT2 was as follows:

• US $300 M equity
• US $500 M debt from foreign commercial banks and Development Finance Institutions
• US $500 M from Thai commercial banks (Asian Development Bank, 2012)
• In total, there were 26 financial institutions who participated in financing and guarantees

 
The capital structure features a debt to equity ratio of 72/28, and the private sector supplied about 85% of the total cost. It was developed as a BOOT (Build, Own, Operate, Transfer), with the concessionaire as a locally registered SPV, the Nam Theun 2 Power Company (NTPC), of which the Government of Laos owns 25%. NTPC contracted to finance and develop the project, and then to operate it for 25 years. After that, it will revert to the State free of charge. During the concession period, the Government will receive dividends, royalties and taxes amounting to $80m/year (Head, 2012).

To make the project bankable, and secure financing, a power purchase agreement (PPA) was established between NTPC and the Electricity Generating Authority of Thailand (EGAT), to guarantee sales. This was a 25-year agreement for NTPC to supply 5,636 GWh/year to EGAT on a take-or-pay basis. The tariff was predetermined and denominated half in US$ and half in Thai Baht, to avoid exposure to local currency devaluation (Head, 2012).
Funds for the 25% equity portion of NTPC, amounted to $87 M. This was raised through concessionary loans and grants. However, money was made available to the Lao Holding State Enterprise (the Government holding company) as a loan at commercial rates. This difference in rates created an additional revenue stream for the government (Head, 2012).

International debt totaling $350m was raised from export credit agencies (ECAs), with multilateral banks insuring the debt against political risk through guarantees. (Debt coming from Thai commercial banks was uncovered for political risk.) A total of nine commercial banks participated including BNP Paribas, Societe General, Fortis Bank and Bank of Tokyo-Mitsubishi.

The project showcases the benefits of credit enhancement mechanisms now offered by the MDBs. Though, guarantees only covered $126 M (10% of the total cost), they provided sufficient confidence to leverage a much larger sum from international sources. The public sector provided only 15% of the total project cost, and much of this was concessionary lending for the purchase of the Laos government equity shares (Head, 2012).

Source: Head, “Hydro Finance Handbook,” HCI Publications, 2009.

The US still has a significant amount of hydropower potential; the question is how to develop it. The US Department of Energy (DOE) finds that hydropower could grow from its present capacity of 101 gigawatts (GW) to nearly 150 GW by 2050, with the right investment. The scenario explored, was a combination of 13 GW of new generation capacity, and 36 GW of new pumped storage capacity. The new capacity would result from upgrades to existing plants, adding power at existing dams and canals, and a limited number of new facilities on undeveloped stream-reaches.

In the DOE’s assessment, entitled “Hydropower Vision,” this level of investment would achieve several benefits, including a $24 billion savings from avoided greenhouse gas emissions, attributable directly to new development. Pumped storage schemes can also provide a backstop to more variable renewable energy sources such as wind and solar.

In order to realize much of the potential, the industry will need to rely on private investment for a significant portion of the development. Today, federal agencies own about 49% of all installed capacity; these agencies include the U.S. Army Corps of Engineers, the U.S. Bureau of Reclamation, and the Tennessee Valley Authority. An additional 24% of the existing capacity is publicly owned through utilities, irrigation districts, and cooperatives. The remaining 27% of installed capacity is privately owned.