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Practices in the financing firms and approach from energy regulators

The cost of capital is generally calculated as the weighted sum of the costs of different sources of financing used by the firm i.e. equity and debt, as they are traditionally understood. The Weighted Average Cost of Capital is a fundamental element in corporate financing. Financial analysts and investors systematically use it to valuate and select their investments, whether in shares or industrial projects.

It also serves as a discounting rate applied to future cash flows to produce a net discounted value, or a threshold value for estimating the profitability of an investment. In network industries subject to regulations, the WACC is also determined by regulators who directly influence operator revenues. Applied to the Regulated Asset Base (RAB) to obtain the cost of capital, the rate set is a sensitive value in the pricing of cost-oriented infrastructures (operational and investment costs have a more explicit nature).

The cost of debt before taxes is usually modelled by the formula:

CD = Rf + d,

  • where Rf is the rate without risk;
  • and d is the credit risk premium, measurement of a higher return in compensation for the risk of failure to pay.

The Capital Asset Pricing Model is most often used to determine the cost of capital after taxes: CE = Rf + β.EMRP,

  • where: EMRP is the market risk premium, additional profitability that shareholders expect for holding on to risky assets rather than safer investments;
  • and beta measures the exposure of the firm to market or systemic risks.

Thus, considering the privileged fiscal treatment of the debt, the expression after taxes of the cost of capital is:

CMPC = (1-g).( Rf +β.EMRP)+g.(1-t) ( Rf +d),

  • where g is the debt leverage and t the tax rate

The problem of determining parameters

In theory, the parameters of the WACC used in corporate finance are determined in an exclusively prospective manner over the period of investment (even if, sometimes, for this purpose, past trends are used as a reference). For example, the beta calculated using market data is reduced to an economic beta, stripped of the effects of debt on the company's risk profile and then "re-indebted" with a forecasting lever.

The WACC used for pricing calculations must constantly be updated according to the most recent data, like the risk-free rate in force. For regulators, concerns about the stability of the rate, invariable during the regulation period, is the primary consideration in their evaluation. This provides a certain level of visibility for operators. Regulated rates therefore differ because they integrate "standardised", rather than prospective, parameters. For example, an operator whose financial structure is clearly "sub-optimal", and likely to remain so for some time, should not be overpaid. We should note that for parameter g, regulators of energy infrastructures consider accounting values (percentage of RAB) rather than market values, as is the practice in traditional corporate finance.

Compared to brokerages, regulators are finally confronted with the issue of differentiation between prescriptive WACCs according to the type of infrastructure. In this respect, beta is the most difficult parameter to determine. However, this should not lead us to choose a value corresponding to that of a group with multiple businesses which includes the entity under consideration, even if the reasoning underlying its profile for specific risks is based essentially on qualitative considerations. Definition of the WACC is simple. Estimation of each of the parameters it comprises is, on the other hand, a complex exercise when it is performed with a level of precision commensurate with the stakes. In practice, financialanalysts tend to neglect this calculation and communicate essentially on the various developments likely to affect forecasted cash flows. Alternative methods, such as Arbitrage Pricing Theory, which circomvents the choice of a single financial structure in the updating of cash flows, are also used. With the RAB, regulators have less leeway to adjust prices without affecting WACC. Furthermore, today they must communicate, even consult, more openly on this rate, or rather the rates by type of asset. Nevertheless, these choices sometimes remain insufficiently justified or analytically robust despite appearances.

In recent years the drive to build solar power plants has increased. The cost of the electricity generated from solar power is much higher than for other renewable energy sources as shown in Table 1.

Despite this fact solar power plants are being installed around the world. There are several reasons for this. These include, reducing a countries dependence on oil, increasing a 'green' image, reducing CO2 emissions and an attempt to create new jobs and reducing a countries dependence on imported expensive diesel for power generation. In some parts of the world Solar power is the only alternative renewable energy that has the potential to provide significant quantities of electricity. The costs for the development of solar panels have been coming down as the technology improves and more facilities to manufacture the panels are being built.

In order to make a solar power project viable a Feed-In Tariff, alternative incentive schemes such as green certificates or high grant subsidies are required. However a Feed-In Tariff scheme maybe the most attractive one for investors. In this kind of incentive system the solar power plant is guaranteed to be able to sell the produced electricity at a pre-determined set price over the life time of the plant.

Table - Electricity production costs

Power source Cost €/MWh
Nuclear 28-35
CCGT (gas) 34-40
Hydroelectric Power 25-60
Solar 350
Wind 60

The key stages in studying the feasibility of a solar power plant project are in determining the:

  • Solar Potential – The amount of electricity that can be produced annually.
  • Capital Expenditures – This includes determining the type of photovoltaic cell to be used, grid connection requirements as well as installation and construction costs.
  • Project Schedule – Development studies, installation and construction, grid connection work, payment schedule.
  • Operating Expenditures – Insurance, operating and maintenance, business taxes, land leases.
  • Profit and Loss Forecasts, Cash Flows, depreciation of capital assets & Debt Structure

It is important that all the stages above are carried out correctly to give the project developer a precise evaluation of its financial need of the project. This will ensure that the project is financially viable at any point in time over the lifetime of the plant including its development.

A good feasibility study should also provide the developer with an estimate of some key ratios, so parties involved in development can appreciate its bankability. If the key first assumptions regarding the CapEx, Opex and electricity production levels show that the DSCR*1 and LLCR*2 ratios are less than zero then the project may have to be adapted so it can be financed according to project finance standards.

Once all these elements have been reviewed and compliance with bank expectation ensured the developer will be able to check that the project Internal Rate of Return is above 20% and look for potential equity partners.

In the recent years, the Italian natural gas market was subject to imbalances between supply and demand, especially during winter peaks in consumption. As a short-term solution, the government had taken various measures such as implementing interruptibility clauses for suppliers, obliging importers to subscribe to a strategic storage service and maximise supplies, reducing tariffs for use of transport services outside peak periods... Most of these measures are applied just before winter, when the government anticipates a risk of imbalance and launches emergency procedures. To explain this situation, we must remember that in Italy, from 1990 to 2006, demand for gas rose an average of 3.7% a year. At the same time, national production started to decline in the second half of the 90s, at an average annual rate of 5.5% until 2006 while, over the same period, imports rose by 7.5% a year.

However, the periodically critical situation of the Italian system cannot be explained exclusively by an annual imbalance within the system. It is also due to an imbalance between supply and demand on a daily basis recorded at specific seasonal periods. Indeed, according to a report presented in October 2007 by Mr. Alessandro Ortis, president of the Autorità dell'Energia (Italian energy regulator), during the winter, demand for gas during workdays is greater by more than 80 m3/day than import and production capacities. Storage is therefore indispensable as well as building up strategic reserves, before peak periods, and interruptibility of demand.

According to the same report, a gas system adapted to current demand would require an additional supply of at least 130 m3/day. Current investments and, in particular, the opening of the Rovigo methane terminal and additional transport capacities from Russia and Algeria will only provide, respectively, 25 m3/day and 35 m3/day. Thus, there is a serious and durable deficit in infrastructure because, at the same time, the future of other construction projects remains uncertain while the forecast increase in demand is 10 m3/day per year.

It is therefore likely that, for upcoming gas regulations, the Autorità will set a high remuneration for new transport and regasification infrastructures in order to contribute to improving, over the medium-term, the state of the gas market. Nevertheless, the country does not seem able to avoid new measures in favor of energy conservation and a greater diversification in means of producing electricity, half of which is currently produced by gas-fuelled thermal power plants.