Case Solution - ISCP



The Iceland Submarine Cable

SOLUTION NOTE

SYNOPSIS

THE ICELANDIC SUBMARINE CABLE PROJECT (ISCP) IS A PROPOSED €6.3 BILLION ENDEAVOR BY WHICH THE ICELANDIC GOVERNMENT WILL TAP INTO ITS GEOTHERMAL AND HYDROELECTRIC RESOURCES TO EXPORT ELECTRICITY TO THE EUROPEAN CONTINENT THROUGH TWO GIANT UNDERWATER CABLES. THE CONSTRUCTION OF THE PROJECT INVOLVES BUILDING THE CAPACITY TO HARNESS THE RENEWABLE ENERGY, LAYING TWO CABLES ALONG THE OCEAN FLOOR, AND CONSTRUCTING A CONVERTER STATION AT THE ENDPOINT.

The Icelandic government is very excited about the project because of the potential economic gains as well as the benefits of diversifying its economy away from its 70% dependence on the marine industries. The case is set in January of 2001 and the government is putting together its financial plan for the ISCP so that the deal can be pitched to investment banks or potential lead investors. Because the scope of the project is roughly 80% of Iceland’s annual GDP, financing it alone is not an option for the local government.

The key questions facing any evaluator of the ISCP are as follows:

1. How can one best forecast the revenues from such a large project that has so many variables?

2. How can all of the risks associated with the ISCP be accounted for and mitigated in the financial forecasts?

3. What discount rate should be used to evaluate a project that involves multiple countries as well as the North Atlantic Ocean?

4. What is the optimal capital structure for financing this project and how will the syndicate raise the necessary debt?

5. Are there any real options or other extraneous sources of value that could make the ISCP more attractive to potential equity investors?

Duke MBA candidates Tom Cowhey, David Helgerson, Jason LaRose, Paul Timm and Bill Wiseman prepared this Solution Note under the supervision of Professor Campbell R. Harvey for the sole purpose of aiding classroom instructors in the use of the Duke MBA case: “The Icelandic Submarine Cable”. It provides analysis and questions that are intended to present alternative approaches to deepening students’ comprehension of business issues and energizing classroom discussion.

Copyright ( 2001 Duke University, Fuqua School of Business.

Forecasting Project Cash Flows

THE PROJECT CASH FLOWS ARE FORECASTED BY ESTIMATING THE ASSOCIATED REVENUES, EXPENSES, AND CAPITAL INVESTMENT. ESTIMATING REVENUES IS DIFFICULT, AS THERE IS SUBSTANTIAL VOLATILITY IN THE FUTURE PRICE OF ELECTRICITY AND UNCERTAINTY IN THE AMOUNT OF A GREEN ENERGY SUBSIDY. MODELING THE COST STRUCTURE OF THE PROJECT IS TRIVIAL GIVEN THE INFORMATION CONTAINED IN THE CASE EXHIBITS. CAPITAL EXPENDITURES ARE ESTIMATED USING TEXTUAL DATA IN THE CASE AND THE EXPENSE TABLE PROVIDED IN EXHIBITS 17 AND 18.

Estimating Revenues

There are five major sources of uncertainty in the project’s revenue base:

1. The size of any green energy subsidy provided by the EU;

2. The price of electricity in the future, given the recent deregulation of the market;

3. The completion time of laying the actual cable;

4. The amount of electricity sold, as determined by the capacity of the new generation facilities in Iceland; and

5. The possibility of cable damage, interrupting the flow of electricity.

The green energy subsidy will most likely take the form of a fraction of a Euro per kilowatt-hour. The case states that the German gas tax is 50%, so a good estimate for the green energy subsidy will be in the range of 0-50% of the wholesale price of electricity, or about €0 to €3 per 100 kilowatt-hours. As this decision will be made via legislative bodies – and given that no statistical data is available for comparable situations – this variable was modeled as a uniformly distributed random variable for Monte Carlo simulation.

The future price of electricity in Germany is far more difficult to forecast. The following methodology was used; however, any reasonable judgment is acceptable as the market is very young.

1. Establishing a base price for electricity: Exhibits 11A and 11B show a ten-year history of German electricity prices in nominal terms. The current price of €6.35 per 100 kilowatt-hours was used as a proxy for the average price of electricity in 2002.

2. Forecasting changes in electricity prices: The mean rate of change and the volatility of the annual rate of change were computed separately.

a. Electricity prices in Germany have been dropping at an average rate of 1.22% over the past ten years, in nominal terms. However, much of this downward pressure occurs in the years leading up to and following deregulation. Following deregulation, it is estimated by the case writers that German electricity prices will rise, on average, at the rate of inflation (2.3% per annum), similar to the period from 1991-1995.

b. The volatility of the rate of price increase was assumed to be time-variant around our mean of 2.3%. The standard deviation of annual price change for the last ten years is 3.8%. However, this includes the large change caused by deregulation. Prior to deregulation, the standard deviation of annual price change was 1.6%. For the two years following deregulation, the value is 7.9%. Making the assumption that electricity price volatility is mean-reverting, the forecasted standard deviation of annual price change in electricity prices are:

Year |2002 |2003 |2004* |2005* |2006 |2007 |2008+ | |σ(Δ) |7.9% |7.9% |5.3% |5.3% |1.6% |1.6% |1.6% | |

* The intermediate volatility of 5.3% was taken from 1998-1999 data for the California deregulated energy market, a deregulated energy market in a more mature stage of development. This information is found in a case footnote.

The time to construct and lay a submarine cable is estimated in the case as 4-6 years for the first cable and 6-10 years for the second cable from the date of project initiation. It was assumed that there was a 60% probability that the initial cable would be completed by year 4 after commencement of construction, with a 30% probability that construction of the first cable would complete in year 5 and a 10% chance that construction would complete in year 6. Depending upon start year, the 2nd cable would always be completed and working in the 4th year after the completion of the first cable. It was assumed that project completion of the first cable would occur mid-year, allowing for six months of electricity sales in that year.

The amount of available generating capacity in Iceland is never a constraint to electricity sales. New capacity will be added at a rate of approximately 1 Terawatt-hour (TWh) per year. Estimates for down time caused by cable maintenance and repair were stated in the case at 6% on average. Coupling this with the stated power losses of 8.8% gives an annual capacity of 4.10 TWh of delivered electricity per cable.

Estimating Operating Expenses

Operating expenses can be broken down into generation expenses, project management expenses, start-up costs, and depreciation. The pro forma financial statements included in the case exhibits contain detailed estimates of the project’s cost structure. The key financial elements of the operating expenses are listed below.

1. Operating and maintenance costs of the generating facilities are variable with the amount of electricity generated. Total variable cost per 100 kilowatt-hours produced is approximately €0.6, not including maintenance capital expenditures.

2. Project management expenses are expected to be approximately 3% of revenue once the project is underway.

3. Start-up costs, including studies, financing charges, legal fees, and other one-time charges are forecast to be approximately €20 million per year until revenues are generated.

4. Depreciation of all assets is over a twenty-year straight-line schedule with a 10% salvage value, which is in accordance with Icelandic tax law.

5. Maintenance and generation costs are grown at 3.1% annually, which represents the recent historical average inflation rate in Iceland. Because the power generation facilities and associated labor costs will be housed in Iceland, it is only appropriate to use some estimate of future Icelandic inflation, not a German one.

Estimating Capital Investment

Exhibits 17 and 18 outline the total expected capital investment needed to create the electricity generation and delivery systems. The core issue in estimating the capital outlay for the project is determining the timing of the expenditures for the submarine cable. The assets that will be built in Iceland, including the geothermal power plants and the high voltage lines to carry the electricity to the cable’s coastal site, follow a construction schedule as presented in Exhibit 18. A number of studies have been conducted by Landsvirkjun to arrive at this schedule, and it is assumed that these expenditures are deterministic. Maintenance capital expenditures for generating assets eventually reach 8% of the total capital outlay for power plants, with a linear ramp from 0% to 8% during construction.

The timing of the capital expenditures for the submarine cable is far less certain. The Landsvirkjun/Pirelli study conducted in 1993, and revisited in 1999, state that the first cable will be completed between years four and six, with the second cable being completed between years six and ten. Capital expenditures for the cables were modeled accordingly, using an equal amount of outlay in each year of construction.

Cost of Capital

USING THE INTERNATIONAL COST OF CAPITAL AND RISK CALCULATOR (ICCRC)[i]

Although many academics and financial services firms have attempted to build decisive models for calculating the risks and costs of capital in emerging markets, the results are always debatable. The ICCRC captures many of the essential factors surrounding sovereign or country risk, and calculates with better consistency the cost of capital in international capital markets. In this case, it was necessary to determine the cost of capital for the average Icelandic project, but there were several other “sovereign” risks to be addressed. Using a Risk-Free Rate of 5.4%, U.S. Risk Premium of 7.5%, and anchoring to the U.S. equity market, the ICCRC calculates a 16.8% cost of capital for the average Icelandic project. The 5.4% Risk-Free Rate is used because it seems most appropriate to match our project horizon most closely to the maturity of the bond. The U.S. Risk Premium of 7.5% is an estimate of the annual U.S. stock market return above the Risk-Free Rate.

Other Country or Sovereign Risk Factors

Given the complexities of laying an electric cable across the North Atlantic Ocean, distributing “green electricity” through the deregulated European power grids, and extracting perpetual and low-cost geothermal energy, this project would require a more rigorous analysis of the cost of capital. Obviously, the rate given for the average Icelandic project would not suffice in this case. This case must also address some form of adjustment for:

1. An integrated low-cost electricity provider

2. The risks of running a cable through the Faroe Islands

3. The uncertainty surrounding international laws for operating in the High Seas

4. The participation and commitment of countries in the European Union

Adjustment for Asset Beta of Comparable Projects

The first step for adjusting the standard Icelandic cost of capital is to find the asset betas of comparable firms. Using the average equity beta of .57 and debt/equity ratio of 54.8% from the case Exhibit 19, along with the Icelandic corporate tax rate of 30%, the peer average asset beta for an “integrated European electric utility”[ii] is .414. (Exhibit A) This new asset beta can then be used as an input for the “Optional Beta Adjustment” provided in the ICCRC. Adjusted for the stability and lower risk profile of integrated electric utilities, the base cost of capital for this project becomes 10.2%. And although these projects are significantly less risky than the average Icelandic project, there must be some additional adjustments for the unique nature of this project.

The European Union’s Impact on Cost of Capital

When evaluating international investments, the standard approach is to focus on the risks and costs of capital in the country where the project will be based. Since this project would extend beyond Iceland’s borders, and be subjected to additional risks and guarantees of doing business with the European Union, there needs to be an adjustment to the overall cost of capital for the EU’s participation. Since this project is permanently dependent on the electricity market in the EU, additional analysis of the risks and rewards will yield a lower cost of capital. Exhibit B shows the framework for adjusting the cost of capital based on the EU’s participation. Although each of the stated Country Risk Factors – as well as the rankings and weights assigned to them – is clearly debatable, the main issue here is that those variables are evaluated and then managed. Any reasonable adjustment to the cost of capital based on the involvement of the European Union will be acceptable in this case. Based on an overall favorable weighting from the EU’s inclusion, this analysis yields a net deduction of 1.5% from the original cost of capital.

The Faroe Islands’ Impact on Cost of Capital

Since this submarine cable must pass through the Faroe Islands and actually cross a land-based right-of-way in that country, the potential sovereign risks must also be evaluated there. While the Faroe Islands are a small semi-independent nation with little international exposure, there are still several factors that could complicate the economics of this project (See case Exhibit 13B).

Since the Faroe Islands are a necessary part of this project, their country risk factors must be considered in the overall project cost of capital. The weight assigned to the Faroe Islands should obviously be smaller than that of the European Union or Iceland, but the assigned premium to the cost of capital is +1.875%. Exhibit C illustrates the major weighted risk factors and the resulting premium calculation.

The High Seas Impact on Cost of Capital

Traditional project finance literature has avoided making any explicit evaluation of the sovereign risks associated with operating assets in the high seas. Since this project is so highly dependent on the submarine cable crossing the North Atlantic Ocean, there must be some provision for the added risks that come from the legal and political uncertainties of placing assets permanently in the high seas. Many of the risks can be accounted for by modeling the probabilities with Monte Carlo Simulation, and others can probably be insured against, but this project should still carry a premium of +1.25% on the cost of capital. Exhibit D explains the primary issues, weighted assessment of risks, and the resulting calculation. Again, these factors could be debated at length, but the important issue is that each item be addressed and then managed.

Final Cost of Capital Calculation

The total cost of capital assigned to this project should be 11.83%. This includes the beta adjustment against the average Icelandic project, as well as the impacts of the EU, Faroe Islands, and the High Seas. Although this cost of capital may seem low for a project of this magnitude, the numerous favorable European Union actually make this project much less risky than any of it’s comparables. Exhibit E illustrates the final cost of capital calculations.

Estimating the Capital Structure

FOR THE OPTIMAL SOLUTION, ONE MUST DETERMINE HOW MUCH DEBT A PROJECT LIKE THIS ONE COULD SUPPORT IN THE PUBLIC MARKETS. TO DETERMINE THIS AMOUNT, IT IS MOST APPROPRIATE TO RELY UPON GUIDANCE FROM THE STANDARD & POOR PUBLICATION “DEBT RATING CRITERIA FOR ENERGY, INDUSTRIAL, AND INFRASTRUCTURE PROJECT FINANCE.” ACCORDING TO THIS S&P COMMENTARY:

Capitalization and Financial Flexibility

In Standard & Poor’s experience, project sponsors will generally try structure and leverage a project to the greatest extent possible in order to limit its paid-in equity cash commitment. Fundamentally, the amount of leverage is irrelevant to the credit rating. What ultimately matters most is the project’s ability to generate cash sufficient to cover its debt obligation. Thus, it is theoretically possible to have no equity and still achieve an investment-grade rating.

Nonetheless, a project’s leverage level is often an indication of its creditworthiness. For instance, a merchant project’s ability to produce a stable and predictable revenue stream will never match that of a traditional contract revenue-driven project. Projects with merchant exposure may find that leverage cannot exceed 50% if investment-grade rated debt is sought. Contract-revenue driven projects, on the other hand, typically have had leverage levels around 70% to 80%.

A project’s debt amortization schedule often influences the rating, more so than the degree of leverage. Front-loaded principal amortization schedules that capitalize on the more predictable project cash flows in the near term may be less risky that those with whose delayed amortizations seek to take advantage of long-term inflation effects.

On a related point, investment-grade project debt should be amortizing debt. Few projects, particularly power projects, can adequately assume the refinancing risk of the bullet maturities characteristic of corporate or public financings. Corporate entities, such as power generation companies, hold numerous assets, each at different stages of their life cycles. Unlike a corporate entity, a single-asset power generation facility is more likely to have a finite useful life.

Because of this depreciating characteristic, a fixed obligation payable by an aging project near the end of a project’s life cycle is necessarily more risky and speculative than an obligation payable from cash sourced in diverse assets. Project sponsors may consider front-loaded amortization when commodity fuel and electricity price forecasts are subject to less error than long-range forecasts. (emphasis added)

Given the nature of the project and its assets, it is reasonable to expect debt to capitalization in the 70-80% range, for, while the Iceland Submarine Cable project would not obtain a supply contract, their electricity would be preferred in the short to medium-term over other sources due to environmental regulation considerations. Additionally, the debt would be structured to amortize at the earliest point in the project to ensure an investment-grade rating. However, to guarantee an investment grade rating, another important variable besides structuring would be the project’s Debt-Service Coverage Ratios (DSCR) following completion of all initial capital expenditures. It would be this ratio that will determine the exact amount of leverage that the project could sustain. Again according to S&P:

Coverage of Fixed Obligations: The DSCR

Standard & Poor’s relies on debt service coverage ratios (DSCRs) as the primary quantitative measure of project financial credit strength. The DSCR is the ratio of cash from operations (CFO) to principal and interest obligations. Cash from operations is calculated strictly by taking cash revenues and subtracting expenses and taxes, but excluding interest and principal needed to maintain ongoing operations.

The ratio calculation also excludes any cash balances that a project could draw on to service debt, such as the debt service reserve fund or maintenance reserve funds. To the extent that a project has tax obligations, such as host country income tax, withholding taxes on dividends and interest paid overseas, etc., Standard & Poor’s will treat these taxes as ongoing expenses needed to keep a project operating.

Standard & Poor’s calculates several versions of the DSCR to help gauge a project’s credit strength. The most important ratio is the minimum DSCR that the project will see through debt maturity. Standard & Poor’s places emphasis on the minimum DSCR because it will likely point to the project’s greatest period of financial stress. Standard & Poor’s will also consider a project’s short-term DSCR, which looks forward three years, as a near-term measure of financial strength.

Another DSCR is the average DSCR, which averages all of the minimum DSCRs remaining through maturity (as opposed to calculating the average CFO and dividing by the average annual debt service). The average DSCR provides a general measure of a project’s cash flow coverage of debt obligations. As annual DSCRs can increase, decrease, or remain constant over time, however, the average DSCR risks masking a project’s credit profile. Nonetheless, the average DSCR, when viewed alongside the long-term and short-term minimum DSCR, does provide another measure of project comparability. Generally, stronger projects will show annual DSCRs that steadily increase with time to partially offset the risk that future cash flows tend to be less certain than near term cash flows. (emphasis added)

Standard & Poor’s also provides additional guidance on the levels of DSCR that are acceptable for an investment-grade rating:

Forecast Results

Cash coverage of fixed charges—primarily debt obligations—will outweigh many concerns and bear directly on the projects credit strength. Standard & Poor’s assesses the level of certainty that forecast cash flows will be adequate to fund operations, including ongoing maintenance expenses, fuel or other necessary inputs (particularly those with fixed take obligations), capital requirements, nonrecurring expenditures, and total fixed charges. Total fixed charges will include annual principal and interest payments, as well as key letter of credit expenses.

Standard & Poor’s does not assign fixed coverage levels for each rating category. The credit analysis considers lower cash flows with higher certainty to present less risk to debt coverage than high coverage levels from uncertain revenues. Hence, merchant projects that rely on noncontract sales or avoided cost will likely need higher coverage than comparable power projects with contract revenues. The high coverage levels that many merchant projects forecast provide no greater credit support than very low coverages from projects with more credit lease-like structures.

At a minimum, investment-grade merchant projects probably will have to exceed a 2.0x annual DSCR through debt maturity, but also show steadily increasing ratios. Even with 2.0x coverage levels, Standard & Poor’s will need to be satisfied that the scenarios behind such forecasts are defensible. Hence, Standard & Poor’s may rely on more conservative scenarios when determining its rating levels. For more traditional contract revenue driven projects, minimum base case coverage levels should exceed 1.3x to 1.5x levels for investment-grade. Obviously industry and other factors will cause these threshold tests to increase or fall. (emphasis added)

Therefore, the analysis is focused on achieving a minimum DSCR of 1.5x (after completion of all initial capital expenditures). This solution allows for four tranches of debt, each with an increasing interest rate ranging from 7.25% to 9.00%. These rates were determined by looking at investment grade U.S. electric utility corporate bond rates for 30-year bonds, as outlined in Exhibit 20. Although both Iceland and Landsvirkjun have ratings well above investment grade, the solution uses a range of rates based on U.S. integrated utilities just barely above investment grade rating as a way to account for the additional return that debt holders will likely require for this Icelandic project.

Cash flows from the project were assumed to pay down debt immediately upon becoming available, which would be consistent with a debt amortization schedule as opposed to bullet repayment. Using a spreadsheet optimization tool, it is determined that the optimal capital structure to have a debt/capitalization ratio of approximately 77%, with about €1.3 billion of equity and €5.3 billion of debt.

To stress test the results, the solution includes Monte Carlo simulations on the variables discussed above (electricity price, EU green energy subsidy and year of project completion) that are referenced against the required investment grade DSCR levels. With a debt to capitalization ratio of 77%, in less than 8% of the cases did the DSCR fall below a 1.3 and in less than 3% of cases did the DSCR fall below 1.2. This led us to believe that at our debt to capitalization ratio of 77%, we could achieve an investment grade rating needed to fund the project.

Real Options Discussion

RICHARD BREALEY AND STEWART MYERS IDENTIFY CLASSIFY REAL OPTIONS FOR CAPITAL INVESTMENTS AS FOLLOW-ON INVESTMENT OPTIONS, ABANDONMENT OPTIONS, WAITING (LEARNING) OPTIONS, VERIFICATION (OF OUTPUT OR METHODS) OPTIONS[iii]. IT IS THE VALUE THAT MANAGERS CAN ADD BY ACTING ON SUCH OPTIONS THAT MAKES THEIR IDENTIFICATION IMPORTANT TO PROJECT EVALUATION. THE PAST TEN YEARS HAVE WITNESSED A GROWING BODY OF ACADEMIC LITERATURE ON REAL OPTIONS, AS WELL AS CONCRETE APPLICATIONS IN CONSULTING AND CORPORATIONS. AS ECONOMISTS A. DIXIT AND R. PINDYICK COMMENT, “THE NET PRESENT VALUE RULE IS NOT SUFFICIENT. TO MAKE INTELLIGENT INVESTMENT CHOICES, MANAGERS NEED TO CONSIDER THE VALUE OF KEEPING THEIR OPTIONS OPEN.”[iv] UNCERTAINTY CAN BE BETTER EVALUATED, MANAGED, AND STRUCTURED USING A REAL OPTIONS FRAMEWORK. IN THIS CASE, THE MAJOR UNCERTAINTIES LIE IN GERMAN ELECTRICITY PRICES, GREEN ENERGY SUBSIDIES, DEMAND, AND EU POLICY AND DEREGULATION PROGRESS.

Staging Decisions

The value of distinct project timing decisions becomes more apparent through a real options approach. In this case, several stages of the project, including technical planning, building power plants, and constructing and laying cables allow for alternative recourses, including options to wait while more information becomes available:

1. Power Plants: An initial planning and feasibility timeline begins the project implementation, following the creation of several Icelandic power plants. Choices include the mix and amount of geothermal and hydrogen energy produced (sensitive to EU subsidy decisions), and alternative uses for the energy that is available before the cables are complete. The labor and cost of materials required to build the plants may also influence these decisions.

2. Cables: Flexibility surrounding the cables falls into two main decision criteria: location and quantity. In addition to a cable endpoint in Germany, feasibility studies have approved North East Scotland, the Netherlands, and Belgium as potential recipients of the Icelandic power. Price stabilization, grid development, EU tax policy and legal uncertainties may prove one of these locations more valuable after the first cable has been laid, making these alternative options more attractive. The Faroe Islands provide a point of redirection if significant market changes occur. The quantity of cables can also be reduced or increased after the initial decision is made to lay the first of the two cables.

Abandon and Salvage Options

The two major components of the project present different salvage values if the specific project planned is undermined. The salvage value of the cable is likely to be nothing. The cost of pulling up the cable would most likely exceed any benefits of redirecting it. However, the power plants could be used for further aluminum and ferro-silicon projects in the future. Once the project has been completed, the low variable costs make project abandonment unlikely. It is highly debatable whether or not this option brings any value to the project since any plans to bring additional electricity-intensive industries to Iceland must be approved by a local government that is very sensitive to activities that may pollute the country.

Input Diversification Value

The option for strategic resource diversification may make this project especially attractive to potential equity investors. A power company dependent on coal or oil may find that adding geothermal and hydroelectric sources lowers the volatility of its input costs and could be a significant advantage of the project. Corporate partners may also find political advantages to their investment in renewable fuels from foreign sources.

The options presented are not comprehensive, but illustrate the most likely additions to the value of the project based on expected uncertainties. For instance, it is possible that this project will provide expertise for an energy company interested in harnessing more of the world’s untapped renewable energy sources. The value of this gained expertise will vary between companies, but it certainly could sway an equity investment decision.

In summary, real options present a tool that expands upon the DCF solution discussed earlier by evaluating the uncertainties and simplistic assumptions surrounding the investment decision. As Professor Benjamin Esty writes, “(A DCF valuation) assumes that investments are often now or never decisions… Often, the key decision is not whether to invest, but when. In reality, managers add value by making mid-course corrections in response to new information.”[v] This would certainly be the case in the Icelandic submarine project.

Estimating the NPV of the Project

BASED UPON THE ASSUMPTIONS OUTLINED ABOVE, WE CONDUCTED A MONTE CARLO SIMULATION, RUNNING 5,000 TRIALS AND CALCULATING AN APV VALUE FOR THE PROJECT. THE PROJECT CASH FLOWS WERE DISCOUNTED AT THE DISCOUNT RATE DETERMINED IN EXHIBIT E (11.8%), AND THE VALUE OF THE TAX SHIELD FOR EACH TRANCHE OF DEBT WAS DETERMINED BY USING A DISCOUNT RATE EQUAL TO THE INTEREST RATE ASSOCIATED WITH THAT SERIES.

Based upon the finding that this project would have a positive NPV in over 95% of the cases predicted, with a Mean NPV of €747 million, we determined that this project should be undertaken with the structure proposed.

A copy of the model used to determine capital structure and the APV value is presented as Exhibit F. The results of our Monte Carlo analysis are presented in Exhibits G-I, predicting minimum DSCR, German electricity price in 2019 and free cash flow in 2019, respectively.

Exhibit A: Comparable Firms and Asset Beta Calculations

Exhibit B: European Union Impact on Cost of Capital:

Explanation of Impact Model:

Each of the primary country factors is ranked in order of importance with 1 being the highest and 9 being the lowest. Weights are then assigned to each factor as the inverse of it’s ranking. If a factor creates a favorable advantage for the project, its entire weight is assigned to the “Weight Favorable” column. Added risks or uncertainties for the project are assigned values in the “Weight Unfavorable” column. In the EU case, the Favorable items outweigh the Unfavorable items by a difference of 6 points. These 6 points are then multiplied by 0.25 (representing 1/4th of the impact on total cost of capital) to arrive at a –1.5 Net Impact on the Cost of Capital. The same methodology (but with different factors and weights, as well as smaller multipliers) is also applied to the Faroe Islands and High Seas Impacts as illustrated below.

Exhibit C: Faroe Islands Impact on Cost of Capital:

Exhibit D: High Seas Impact on Cost of Capital:

Exhibit E: Cost of Capital Calculations

Total Project Cost of Capital: Iceland, The European Union, Faroe Islands, and High Seas

Exhibit E: NPV / Debt Repayment Model (1 of 3)

Exhibit E: NPV / Debt Repayment Model (2 of 3)

Exhibit E: NPV / Debt Repayment Model (3 of 3)

Exhibit F: Monte Carlo Results : APV

Exhibit G: Monte Carlo Results : Minimum DSCR

Exhibit H: Monte Carlo Results : German Electricity Price in 2019

Exhibit I: Monte Carlo Results : Free Cash Flow in 2019

Endnotes

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[i] Campbell R. Harvey, “The International Cost of Capital and Risk Calculator (ICCRC)”

[ii] “Integrated European Electric Utility” is defined as a highly diversified and vertically integrated electric company. The firms used for these calculations own assets for all parts of the electricity value chain including raw material extraction, power generation, and electricity distribution.

[iii] Richard Brealey and Stewart Myers: Principles of Corporate Finance; sixth edition, p. 619.

[iv] “The Options Approach to Capital Investment, “ Harvard Business Review, May-June 1995.

[v] “Improved Techniques for Valuing Large-Scale Projects,” Benjamin C. Esty, Journal of Finance, Spring 1999.

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