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“What’s the difference between a financial and economic analysis?”
This question was posed during a presentation in which I was using both terms. It’s a good question and the distinction is important. Both are concerned with benefits and costs; and, both compare net benefits for scenarios with the project to scenarios without it. But the perspective of the analysis is different in each case, which alters the ways in which benefits and costs are counted. The main distinction is that an economic analysis compares costs and benefits accruing to the entire economy, while the financial analysis makes that comparison from the perspective of an enterprise. In a financial analysis, the viability of the project is based on its financial profitability – what remains from the revenues after all the bills are paid. Since the enterprise has owners, who are providing equity, a financial analysis seeks to identify the return on equity the project can provide. Benefits, therefore, are the year-on-year cash inflows received by the enterprise, in the market. For example, an electricity project would measure benefits as anticipated revenues from electricity sales (inflows). Costs are financial outflows. For a financial analysis these are called direct costs, and are reflected in market prices for debt financing, engineering, construction, inputs, operations, maintenance, etc. They are allocated to appropriate time periods of the project lifecycle and usually discounted at a weighted average cost of capital. Discount rates can also be nuanced to reflect differing risks for different stages of development. Before a capital structure has been formed, the financial analysis can be a market study that determines whether the enterprise’s services are price competitive. During later stage development, the financial analysis takes the perspective of a special purpose vehicle (SPV), for which a three-statement proforma model can be developed. By contrast, an economic analysis considers the broader perspective of the public sector. Benefits in this case, are all social and economic benefits that accrue to the public welfare. These might include the avoided costs of less optimal project alternatives. They may also include health and public-use benefits, long-range climate benefits, and other advantages. For example, one benefit of a renewable energy facility is the avoided use of fuel. Therefore, a portion of the project benefits would be the cost of avoided fuel for a traditional energy source (i.e. fuel for gas-powered plant that will not be built). Additional benefits would include power capacity, avoided carbon output, etc. Costs are also different from a financial analysis; they consider what the project would cost monetarily, but also any additional burdens the project would impose on society. For both benefits and costs, economic prices are used in place of market prices. The difference between economic and financial prices arise from two sources. First, financial prices are often subject to price distortions such as transfer payments, price controls, monopolistic pricing, etc. These contain elements that are paid or received by the firm but do not affect economic prices. Second, non-market effects are outputs or inputs that are not captured in the marketplace such as positive or negative externalities. Finally, an economic analysis can also be a qualitative assessment if data for a quantitative study are not available. Often some type of proxy data can be found, but sometimes this is not the case. Furthermore, a quantitative assessment is not always required by the situation. For a comprehensive view, the Asian Development Bank provides Guidelines for the Economic Analysis of Projects, one of the best resources on this topic.
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Rich Swanson, PHD
Advising senior energy executives in realizing the full value of their investments through expert financial valuation, economic analysis and risk mitigation, to accelerate complex projects to financial close.In Africa and Asia energy development plans call for large investments in hydropower. But there is room to invest in this proven renewable energy source in the U.S. as well. And, the trends in the U.S. may be interesting for other countries as well. Late last year, the Department of Energy (DOE) awarded $24.9 million in funding to stimulate hydropower innovation in the U.S.[1] This follows its significant “Hydropower Vision” report released in 2016. Though advances in solar, wind and battery storage have been in the headlines, the US energy mix still features hydropower as its largest renewable energy source at 7% of total energy delivered (wind is not far behind at 6.5%). The DOE continues to promote hydropower innovation and envisions 48.3 GW of new capacity by 2050. [2] In fact, much of the DOE award money mentioned above appears to be clearing the way for new investments by promoting efficiency and environmental innovations. Here are three areas in which hydropower investment in the U.S. may make the best sense… • Augmenting capacity at existing sites. Refurbishment at existing sites takes the form of life extension, upgrades and expansions. Since the average age of the existing hydropower fleet is now approaching 50 years, the “re-commissioning” of these sunk costs can account for a significant increase in energy delivery.[3] • Non-powered dams and other existing infrastructure. There are over 80,000 non-powered dams in the US and thousands of miles of existing, man-made conduits that move water and wastewater. The abundance of existing infrastructure can limit cost, and environmental impact (due to using an existing structure) make this an attractive resource for hydropower development.[4] • Low-head hydro. These are small capacity facilities that use tidal flows or rivers with a head of 20 meters (66 ft) or less to produce energy. Often, no dam is needed. Using the drop in a river or even tidal flows to create electricity can provide a renewable energy source that will have a minimal impact on the environment.[5] Rich Swanson Advising senior energy executives in realizing the full value of their investments through expert financial valuation, economic analysis and risk mitigation, to accelerate complex projects to financial close. 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. 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:
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. The global total of renewable energy installations plateaued for the first time in nearly 20 years, in 2018 (IEA), prompting calls for improved policies and financing solutions. Global renewable energy installation in 2018 was 177 GW, roughly the same amount of capacity as was added in 2017. This marks the first year since at least 2001 that year on year growth has not occurred. Figure 1 shows overall growth in renewable development since 2001, segmented by technology. Figure 1 (Data Source: IEA)  The primary reason for the growth rate slowdown was a change in incentives for solar PV development in China. Last year, China sought to curb costs and focus on grid integration in an effort to sustain long-term solar PV expansion. In 2018 China added 44 GW of solar PV, compared with 53 GW the year before. After China, lower wind additions in the E.U. and in India also contributed to the slowdown. The U.S. increased net capacity marginally, from 17 GW to 18 GW, mainly through the addition of onshore wind. Figure 2 shows global renewable net capacity additions, segmented by country. (IEA 2019) Figure 2 (Data Source: IEA)  Policy instruments can be employed to reinvigorate the upward trend in capacity, but financing availability and incentives can also play a big role. Financial and fiscal incentives can be used to improve access to capital, lower financing costs, and reduce construction costs. The incentives can take the form of tax breaks, rebates, grants, performance-based incentives, concessional loans, guarantees, and risk mitigation. Tax credits and capital subsidies have been applied with especially helpful results.
Of the available tax credits, a production or energy credit is often seen as the most effective. This is in contrast to the most popular tax tool which is a reduction in sales or energy taxes. However, a drawback to this type approach is the difficulty in designing mechanisms that specifically promote renewable energy. Instead, production tax credits, based on energy produced, and investment credits, based on up-front costs, are often seen as a more effective alternative. Production and investment tax credits have been especially instrumental in both wind and solar development in the U.S. The allowance of accelerated depreciation, whereby the cost of the facility is counted against taxable income more heavily during early years of operation, has also been beneficially applied. (IRENA 2019) Capital subsidies can be helpful in creating a level playing field with incumbent technologies. The subsidies can target specific technologies and work best when the qualifications are highly specific. This approach is most often used in countries at early stages of new-technology integration, after which performance-based subsidies might take over. As an interesting case study, Nepal offered capital subsidies in 2013 for projects up to 1 MW depending on the technology and location of facility (as an incentive to supply remote areas). The subsidy covered 40% of the capital cost, a soft loan covered an additional 40% and the developer was responsible for the final 20%. (IRENA 2019) More financial incentives will be required to achieve long-term climate goals; current power additions are only 60% of what’s required. According to the IEA, renewable capacity growth should be more than 300 GW annually, through 2030, to reach international goals. Currently, the energy industry is losing ground; last year, energy-related CO2 emissions rose by 1.7%, despite growth of 7% in generation from renewables. (Utility Dive) Increased availability of flexible financing (from both government and the private sector), along with fiscal incentives may be critical, to re-energize growth. Recent GLS analysis, accomplished for two national electricity companies, illustrates how new transmission infrastructure can reduce energy system emissions by replacing traditional fuels, and reducing congestion when integrating renewables. In one African case, analysis showed that the economic benefit of a new transmission line, from carbon reduction alone, was 3.0% of GDP, while the total economic benefits were 4.5% of GDP.
The transmission line will eventually connect a mini-grid to the primary grid. At present the mini-grid is supplied by hydropower; but during seasons of low-flow, a diesel generator is required to service the load. The total CO2 mitigated over the lifetime of the line was calculated to be 2.7 MT. The model was built assuming a CO2-eq for traditional fuel of 1.5 kg/kWh, and a cost of carbon of USD 0.036/kg. The anticipated load of the new line, previously forecasted by AECOM, was used as a proxy for the current energy now being sourced from traditional fuels. Public-private partnerships can offer governments the opportunity to undertake major public-works projects, in partnership with a private developer, that might be too expensive or risky to undertake alone, especially for developing nations. The contracts that govern these partnerships establish the rules by which the parties relate. These contracts sometimes contain a Right of First Action clause (RoFA), often seen in real estate or extraction industries. The holder of this clause has the right, but not the obligation, to invest in expanding the project in some way, in the future. We believe the inclusion of this clause can help align the often-conflicted incentives of public and private parties (governments want long-term value preservation through appropriate operation and maintenance, while private parties may be incentivized to cut costs in order to maximize profits). If government sponsors delineate the expansion work from the initial build-operate work of the private partner through the creation of the RoFA, they have created an additional asset – a future source of potential cash flows. Our research shows how to quantify these potential cash flows and derive a transparent value of the RoFA.
In this way, the RoFA is an asset that exists in addition to the primary revenues expected upon the completion of the initial build-out. If the public sector is issuing a Request for Proposals (RFP), there are several ways in which the RoFA can be appropriated. For example, the RoFA could be offered immediately to the private partner, augmenting the value of the project, or it could be held by the public sector until certain conditions are met – such as value preservation on behalf of the private company. By Rich Swanson, GLS Group Consultant
Renewable energy sources could form the spine of a Green Energy Corridor in Africa, setting the stage for a leapfrog in technologies, compared to the way developed nations expanded their own grids. In 2016 Africa added 4,400 MW of renewable-power capacity. Moving forward, a significant portion of planned renewable development comes from hydropower; Africa’s potential to generate power from its rivers is vast and largely untapped. However, accessing power from hydro-generation comes with both benefits and challenges. For example, multiple risks, from climate change to offtake and cost-overrun uncertainty, threaten such projects. Our research found that there can be value to a “flexible-engineering” approach to renewable energy projects. We studied a large, planned project and found that this approach could save developers well over 10% of total project value. Our economic analysis quantified several risk factors and estimated valuations for starting small and building in stages as additional information becomes available. Importantly, our process incorporated the value of flexibility so planners can compare such designs directly with static, or monolithic plans. |
Richard Swanson, Ph.D.Asset valuation and project finance expert, specializing in financial and economic analysis of civil infrastructure assets. Archives
June 2020
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