8-1 

8 Financial Assumptions 

This chapter presents the financial assumptions used in EPA Base Case v.4.10. The first section 

gives a summary of each of the key financial parameters. The remainder of the chapter presents 

an in-depth explanation of the theoretical underpinnings and methods used to develop the two 

most important financial parameters – the discount rate and capital charge rate. 

8.1 Summary of Key Financial Parameters 

8.1.1 Capital Charge Rate, Book Life, and Discount Rate for Capital Expenditures 

EPA Base Case v.4.10 models a diverse set of generation and emission control technologies, 

each of which requires financing.1 Table 8-1 presents the capital charge rate, discount rate, and 

book life assumptions for the technologies in base case v.4.10. As will be discussed more fully 

later in this chapter, the capital charge rate is used to convert the capital cost of a technology into 

a stream of levelized annual payments that ensure capital recovery. The discount rate is used to 

translate future cash flows into current dollars by taking into account factors (like inflation and the 

ability to earn interest), which make one dollar tomorrow worth less than one dollar today. The 

discount rate allows inter-temporal tradeoffs and represents the risk adjusted time value of money. 

 The book life is the payback period on an investment. 

There are several things to note about Table 8-1. The technology differentiated capital charge 

rates are used in v.4.10 to derive the associated capital charge rates shown in the table. 

However, while the technology-differentiated discount rates appearing in the table were used in 

deriving these capital charge rates, in EPA Base Case v.4.10 a single U.S. discount rate of 6.15% 

is used across all technologies.

1

 The capital charge rates discussed here apply to new (potential) units and environmental 

retrofits that IPM installs. The capital cost of existing and planned/committed generating units and 

the emission controls already on these units are considered “sunk costs” and are not represented 

in the model. 
8-2 

Table 8-1 U.S. Discount Rates and Capital Charge Rates in EPA Base Case v4.10 

Investment Technology Capital 

Charge Rate 

Discount 

Rate 

Book 

Life 

Environmental Retrofits 11.3% 5.5% 30 

Advanced Combined Cycle 12.1% 6.2% 30 

Advanced Combustion Turbine 12.9% 6.9% 30 

Supercritical Pulverized Coal and Integrated Gasification 

Combined Cycle without Carbon Capture1 14.1% 7.8% 40 

Advanced Coal with Carbon Capture 11.1% 5.5% 40 

Nuclear without Production Tax Credit (PTC) 10.8% 5.5% 40 

Nuclear with Production Tax Credit (PTC)29.1% 5.5% 40 

Biomass with ARRA Loan Guarantees39.3% 4.6% 40 

Biomass without ARRA Loan Guarantees 11.1% 6.2% 40 

Wind and Landfill Gas with ARRA Loan Guarantees210.1% 4.6% 20 

Wind and Landfill Gas without ARRA Loan Guarantees 12.2% 6.2% 20 

Solar and Geothermal with ARRA Loan Guarantees210.1% 4.6% 20 

Solar and Geothermal without ARRA Loan Guarantees 12.2% 6.2% 20 

Notes:

The discount rates appearing in the table were used in deriving these capital charge rates. 

However, as noted in the text, a single U.S. discount rate of 6.15% is used across all 

technologies in EPA Base Case v.4.10. 

1The capital charge rate for these technologies includes a 3% climate change uncertainty 

adder. (See text.) 

2The capital charge rate for this technology reflects the impact of the PTC provided under the 

Energy Policy Act of 2005. (See text.) 

3The capital charge rate for these technologies reflects the impact of ARRA loan guarantees. 

(See text.) 

Capital Cost Adder for Climate Change Uncertainty: Adopting the procedure followed in EIA’s 

Annual Energy Outlook 2010, the capital charge rates shown in Table 8-1 for Supercritical 

Pulverized Coal and Integrated Gasification Combined Cycle (IGCC) without Carbon Capture 

include a 3% adder to the cost of debt and equity (see section 8.2.3 for discussion of debt and 

equity). This capital cost adder reflects increased financing costs for investment decisions 

involving coal plants without carbon capture caused by uncertainty surrounding possible future 

climate change policies that could limit CO2 emissions from the power sector 

ARRA Loan Guarantees for Renewables and Biofuels: The American Recovery and 

Reinvestment Act (ARRA) of 2009 (Public Law 111-5) provides loan guarantees for renewables 

and biofuels. Following the procedure implemented in AEO 2010, these loan guarantees are 

reflected in a reduction of 2% in the cost of debt and equity for biomass, wind, landfill gas, solar, 

and geothermal technologies. Capital charge rates with and without the 2% reduction appear in 

Table 8-1 because the loan guarantees expires in 2016. 

Energy Policy Act Production Tax Credit for Nuclear: The Energy Policy Act of 2005 

(Sections 1301, 1306, and 1307) provides a production tax credit (PTC) of 18 mills/kWh for 8 

years up to 6,000 MW of new nuclear capacity. The financial impact of the credit is reflected in 

the capital charge rate shown in Table 8-1 for “Nuclear with Production Tax Credit (PTC).” 

8.1.2 ARRA Production and Investment Tax Credit (PTC and ITC) for Renewables 

In addition to the loan guarantees that are reflected in the capital charge rates for renewables 

shown in Table 8-1, ARRA 2009 (Division B, Title I, Sec. 1101, 1102, and 1603) also provides 

extensions of the PTC and 30 percent ITC to renewables. These are represented in EPA Base 

Case, v.4.10 as a 30% reduction in the capital cost of these technologies in 2012. 
8-3 

8.1.3 Discount Rate for Non-Capital Expenditures 

The discount rate for non-capital expenditures (e.g., annual fuel, variable operations and 

maintenance, and fixed operations and maintenance costs) in EPA Base Case v.4.10 is assumed 

to be 6.15%. This serves as the default discount rate for all non-capital expenditures. 

8.1.4 Inter-temporal Allowance Price Calculation 

Under a perfectly competitive cap-and-trade program that allows banking, the allowance price 

always increases by the discount rate between periods if affected sources have allowances 

banked between those two periods. This is a standard economic result for cap-and-trade 

programs and prevents sources from profiting by arbitraging allowances between two periods. 

The EPA Base Case v.4.10 uses the default discount rate of 6.15 percent in computing the 

increase in allowance price for cap-and-trade programs when banking is engaged as a 

compliance strategy. 

8.1.5 Nominal and Real Dollars 

EPA Base Case v.4.10 uses real 2007 dollars as its real dollar baseline. See Chapter 2 for further 

discussion on how IPM uses the real dollars for inter-temporal analysis. 

8.2 Development of the Financial Assumptions for EPA Base Case v.4.10 

This section explains the method used to derive the capital charge rate and discount rate as well 

as the assumptions underlying these financial parameters. 

8.2.1 Introduction 

As noted in section 8.1, the discount rate and the capital charge rate are the two parameters that 

encapsulate the financing assumptions for an investment option in EPA Base Case, v.4.10. The 

discount rate allows inter-temporal tradeoffs and represents the risk adjusted time value of money. 

 The capital charge rate is used to convert the capital cost into a stream of levelized annual 

payments that ensures capital recovery of an investment. 

Discount Rate 

The discount rate is a function of the following parameters: 

x Capital structure (Share of Equity vs. Debt) 

x Post-tax cost of debt (Pre-tax cost of debt*(1-tax rate)) 

x Post-tax cost of equity 

The weighted average cost of capital (WACC) is used as the discount rate and is calculated as 

follows: 

 WACC = [Share of Equity * Cost of Equity] 

 + [Share of Preferred Stock * Cost of Preferred Stock] 

 + [Share of Debt *After Tax Cost of Debt] 

The focal point is on debt and equity (common stock) because preferred stock is generally a small 

share of capital structures. 

Capital Charge Rate 

The capital charge rate is a function of the parameters that overlap in part with the discount rate, 

but also include parameters related to the amortization of capital: 

x Capital structure (Debt/Equity shares of an investment) 

x Pre-tax debt rate (or interest cost) 

x Debt Life 
8-4 

x Post-tax Return on Equity (ROE) (or cost of equity) 

x Other costs such as property taxes and insurance 

x State and Federal corporate income taxes 

x Depreciation Schedule 

x Book Life 

The capital charge rate is calculated by solving for earnings before interest, taxes, and 

depreciation (EBITDA) or pure operating earnings such that the project is able to recover the cost 

of equity as the internal rate of return over the lifetime of the project. The sum of discounted cash

flows to the equity holders over the lifetime of the project, discounted at the cost of equity is set 

equal to the initial investment. The capital charge rate so calculated is defined as follows: 

x Capital Charge Rate = EBITDA/Total Investment 

In other words, the capital charge rate is the rate of return required on invested capital, resulting 

from pure operations. 

8.2.2 Method for Deriving Discount Rate and Capital Charge Rate in EPA Base Case v 4.10 

Introduction to Risk 

The risk of an investment in the power sector is heavily dependent on market structure risks. The 

range of risks has increased due to deregulation which has resulted in approximately 35 percent 

to 40 percent of capacity being deregulated IPP (Independent Power Producer) capacity. For 

example, merchant IPP's selling into spot market have more market risk than regulated plants or 

IPP’s having long-term, known-price contracts with credit worthy counter parties. There are also 

technology risks and financing structure risks (corporate vs. project financings). Lastly, there is 

financial risk related to the extent of leverage. 

The risk, especially to the extent it is correlated with overall market conditions, is an important 

driver of financing costs. Other risks are handled in the cash flows and are treated as noncorrelated with the market. This emphasis on correlated market risk is based on the Capital Asset 

Pricing model and associated financial theory. This analysis takes into account differences in 

technology and market structure risks. 

Differences between corporate and project financings are highlighted but no specific adjustment 

has been made for them. 

Market Structure Risks 

The power sector in North America can be divided into the traditional regulated sector (as known 

as “cost of service” sector) and deregulated merchant sector (as known as “competitive” sector). 

x Traditional Regulated - The traditional regulated market structure is typical of the vertically 

integrated utilities where generation (and transmission and distribution, abbreviated T&D) 

investments are approved through a regulatory process and the investment is provided a 

regulated rate of return. Returns on investment in this form of market structure are cost plus 

regulated returns that are administratively determined. Returns are affected by market 

conditions due to regulatory lag and other imperfections in the process, but overall are less 

exposed to the market than deregulated investments, all else equal. In this report, we use the 

term “utility financing” to refer to this type of market structure. A closely related market 

structure is the situation where a plant is built under a power purchase agreement (PPA) with 

a utility with known pricing that allows for a very high degree of investment amortization during 

the contract period. In such an arrangement, the risks are more credit and performance 

related and much less market related. 

x Deregulated Merchant - In a deregulated merchant market structure, investments bear the 

full or a very high degree of market risk as the price that they can sell electricity at is 

dependent on what the short-term markets will bear. Return on investment in this form of 

market structure is not only dependent on the state of the economy, but also on commodity 
8-5 

prices, as well as on capital investment cycles and remaining price related regulation, e.g., 

FERC price caps on capacity prices. The capital investment cycle can create a “boom and 

bust” cycle which imparts source risk or uncertainty to the sector. The operational cash flows 

from investments in this sector are more volatile as compared to in the traditional regulated 

sector, and hence, carry more business or market risk. In this report, we use the term 

“merchant financing” to refer to this type of market structure. 

Technology Risks 

The selection of new technology investment options is partially driven by the risk profile of these 

technology investments. For instance, in a deregulated merchant market, an investment in a 

combustion turbine is likely to be much more risky than an investment in a combined cycle unit 

because while a combustion turbine operates as a peaking unit and is able to generate revenues 

only in times of high demand, a combined cycle unit is able to generate revenues over a much 

larger number of hours in a year. An investor in a combined cycle unit, therefore, would require a 

lower risk premium than an investor in a combustion turbine. 

Financing Structure Risks and Approach 

While investments in new units differ based on market structure and technology risks, differences 

also may occur because of financing schemes available. There are two major types of financing 

schemes: 

x Corporate finance is a category of financing where a developer raises capital on the strength 

of the balance sheet of a company rather than a single project. In this type of financing, the 

debtors have recourse to the entire company’s assets. 

x Project finance, as this category of financing is often labeled, allows developers to seek 

financing using only the project as recourse for the loan. For instance, a project developer 

may wish to develop a new combined cycle unit, but will seek to use project financing in such 

a way that if it defaults on the loan, debtors have recourse only to the project itself and not 

against the larger holdings of the project developer. This approach can be more risky than 

corporate finance, all else being equal, because there is less diversification than the 

corporation which can be thought as a collection of projects. However, there are some 

projects more suitable for project financing because: (1) they may have a self-sustaining 

revenue stream that is greater than the corporate average, or (2) risk is reduced through a 

long-term PPA with a credit worthy counterparty such as a vertically integrated utility or a 

regulated affiliate of a merchant company. 

There are many benefits of a project financing structure but there are also costs associated with it. 

 A project financing structure typically has higher transaction costs (and even higher debt costs as 

debt financing is largely privately placed), but it also solves some of the agency problems and 

underinvestment issues that corporate financed structures face1. 

However, as noted above, this analysis does not make an effort to quantify the relative costs and 

benefits of one structure over the other. Rather, the approach used is based on the premise that 

regardless of financial structure, each project has its own risks based on market structure and 

technology. Further, because corporate financing is more observable than project financing2 and 

has evolved in the power sector to the level of making key risk inferences possible (e.g., IPP and 

utility stock trades), assessment of market correlated risks should be based on IPP and utility 

corporate financing. 

1

 For more information on project financing, see paper titled “The Economic Motivations for Using 

Project Finance” by Benjamin C. Esty, Harvard Business School, Feb 2003 

2Project Financing data is less observable as it’s not explicitly traded. Also, often key financing 

parameters are unavailable due to confidentiality reasons. 
8-6 

Approach to Market Structure Risk 

In EPA Base Case 4.10, a hybrid financing model is used, i.e., it is assumed that future 

development activity would be roughly evenly split between utility financings and pure merchant 

financings. This is designed to reflect a shift in the market in ownership and risk profiles for power 

generation assets, and recent development trends and emphasis on long term contracts3. In this 

approach, for modeling purposes, we assume that new units are financed as a weighted average 

of utility and merchant financing parameters. For new units we assume that both utility and 

merchant components get equal weights. For retrofits, we assume that utility component gets 2/3 

and merchant component gets 1/3 weight4. 

x Example 1: The debt to equity capital structure of a combustion turbine is 55/45 under utility 

financing and 30/70 under merchant financing. Under the assumption that utility and 

merchant components get equal weights, the debt to equity ratio under hybrid financing is D = 

(55 + 30)/2 = 42.5 / E = (45 + 70)/2 = 57.5. 

x Example 2: The debt to equity capital structure of a retrofit is 55/45 under utility financing and 

45/55 under merchant financing. Under the assumption of a 2/3, 1/3, utility/merchant 

weighting, the debt to equity ratio under hybrid financing is D = (55 * 2/3) + (45 * 1/3) = 51.6 / 

E = (45 * 2/3) + (55 * 1/3) = 48.3. A full summary for all technologies appears in Table 8-2 

below. 

Capital Charge Rate – A More Detailed Description 

The capital charge rate is calculated by solving for earnings before interest, taxes, and 

depreciation (EBITDA) or pure operating earnings such that the project is able to recover the cost 

of equity as the internal rate of return over the lifetime of the project. The sum of discounted cash

flows to the equity holders over the lifetime of the project, discounted at the cost of equity is set 

equal to the initial investment. The capital charge rate so calculated is defined as follows: 

Table 8-2 Capital Structure Assumptions for EPA Base Case v4.10 

Technology Utility Merchant Hybrid 

Combustion Turbine 55/45 30/70 42.5/57.5 

Combined Cycle 55/45 45/55 50/50 

Coal & Nuclear 55/45 60/40 57.5/42.5 

Renewables 55/45 45/55 50/50 

Retrofits 55/45 45/55 51.7/48.3 

x Capital Charge Rate = EBITDA/Total Investment 

In other words, the capital charge rate is the rate of return required on invested capital, resulting 

from pure operations. 

3An alternate approach is to categorize the United States into the two previously discussed 

financial regions – Cost-of-service and competitive. The cost-of-service region will have capital 

charge rates based on utility financial assumptions and the competitive region will have capital 

charge rates based on merchant financial assumptions. Such an approach could result in 

overbuilding in the cost-of-service region due to lower capital charge rates in the absence of 

regulatory prohibitions or external sales. This is similar to the public vs. IOU financing arbitrage 

problem, i.e. what stops government utilities from supplying all power? In fact, there are formal 

and informal limits, and because fully characterizing these limits is extremely complex, a hybrid 

approach is used. 

4Retrofits are largely associated with coal fired plants and most coal fired plants are currently 

owned and operated by utilities in a “utility financing” structure. Moreover, since the magnitude of 

the retrofit investment is not as large as a plant investment, the financing of a retrofit is more likely 

to happen from a firm’s internal cash flows instead of external financing. 
8-7 

The discounted cash flow to the equity holders of the project is characterized in terms of the Free 

Cash Flow to Equity (FCFE). FCFE is a valuation technique to estimate cash flows paid to the 

equity shareholders of a company after all expenses, reinvestment, and debt repayment have 

been made. The FCFE approach is suited for valuation of assets that have finite economic lives 

and where debt levels vary from year to year. In the FCFE approach, it is assumed that the asset 

has a finite life and debt reduces over time based on a mortgage-style repayment structure. 

Specifically the cash flows to the equity5 are calculated as follows: 

Cash Flows to Equity = EBIT (1-tax rate) 

 - Interest (1-tax rate) 

 + Depreciation 

 - Capital Expenditures 

 - Working Capital Change 

 - Principal Payments 

 + New Debt Issued 

Discount Rates and Capital Charge Rates 

Based on the above approach, the discount rates and capital charge rates summarized in Table 

8-1 above were obtained for investments in the U.S. The procedures and assumptions used to 

calculate the rates in Table 8-1 are discussed in the sections below. 

8.2.3 Calculation of the Hybrid Capital Charge Rates 

ROE 

The first step was the calculation of a return on equity (ROE) using an average ROE under utility 

financing (10.3%) and merchant financing (15.2%) assuming a 50:50 debt/equity ratio. This 

resulted in a ROE of 12.75%6. This ROE is kept the same across each technology7 but the risk 

differences across technologies are implemented through the capital structure. See the discussion 

of capital structures in this subsection under “Debt Equity Share” and the discussion of “Debt and 

Equity Shares and Technology Risk” in section 8.2.4. 

Note that a 50:50 mix (corresponding to the hybrid capital structure for a combined cycle – see 

Table 8-2) has been chosen. This is because we assumed that the overall IPP risk was on 

average reflective of the risk profile of combined cycle units which in turn was assumed to be 

intermediate between base load and peaking. The combined cycle technology is considered to 

have “average” market risk being an intermediate type technology. Also, in the aggregate, the five 

selected IPP companies8

 have more combined cycle capacity in their supply mix than any other 

technology. Additionally, going forward, it is expected that gas will continue to play an 

increasingly important role in the supply mix of both utilities and merchant companies, with 

combined cycle technology playing a dominant role. For all of these reasons, it was considered 

appropriate to use the ROE corresponding to a combined cycle facility. 

5An alternative definition of free cash flow to equity is as follows: Net Income + Depreciation – 

capital expenditures – working capital change – Principal Payments + New Debt Issued 

6The Pennsylvania-New Jersey-Maryland Interconnection (PJM) uses a 12% ROE for a combined 

cycle at a 50:50 debt/equity ratio to calculate the cost of new entry (CONE) for their capacity 

markets. Hence, the estimates are fairly close to those used by a major RTO. 

7Even though ROE is kept the same across all technologies, it doesn’t mean that the market risks 

are considered the same for each technology. See capital structure discussion in the next 

paragraph. 

8Our merchant parameters are derived from market observations of five IPP companies – see 

discussion on development of merchant financed parameters. 
8-8 

Debt Equity Share 

Second, the capital structures (D/E)9 for the various technology types were calculated using an 

average of utility and merchant financing. The utility debt capacity (and returns) is assumed to be 

independent of technology type based on the theoretical assumption that regulation will provide an 

average return to the entire rate base. The merchant debt capacity is based on market risk where 

a base load plant is likely to have a higher debt capacity than a combustion turbine plant. Table 

8-2 presents the capital structure assumptions used in EPA Base Case v4.10. 

The risk differences across technologies are implemented by varying the capital structure. As 

shown in Table 8-2 and discussed above, a peaking unit such as a combustion turbine is 

estimated to have a capital structure of 42.5/57.5 while a base load unit such as nuclear and coal 

is assumed to have a capital structure of 57.5/42.5. This is based on the intuition that less risky 

technologies can carry more leverage. As debt is less expensive than equity, this will 

automatically translate into a lower capital charge rate (and a lower discount rate) for base load 

technologies and a higher capital charge rate (and a higher discount rate) for peaking technology, 

assuming other components of the capital charge rate calculation remain the same. 

Cost of Debt 

Third, the cost of debt was adjusted to reflect the average cost of debt for utility and merchant 

financings for each technology. The utility cost of debt is assumed to be the same across all 

technologies while the merchant cost of debt is higher than utility and is higher for a combustion 

turbine unit than for a combined cycle or a coal plant. Table 8-3 summarizes the debt rates used 

in EPA Base Case v4.10. 

Table 8-3 Debt Rates for EPA Base Case v4.10 

Technology Utility Merchant Hybrid 

Combustion Turbine 6.25% 9% 7.63% 

Combined Cycle 6.25% 8% 7.13% 

Coal & Nuclear 6.25% 8% 7.13% 

Wind 6.25% 8% 7.13% 

Retrofits 6.25% 8% 6.83% 

 

These financing parameters were then combined with taxation assumptions and technology 

specific assumptions on depreciation, book life and debt life to yield the capital charge rates 

outlined in Table 8-1 above. 

8.2.4 Development of Merchant Financing Parameters 

Merchant ROE 

The Independent Power Producer (IPP) return on equity parameter was estimated to be 15.2%10. 

This was based on empirical analysis of stock price data of five pure play comparable merchant 

generation companies, namely Reliant, NRG, Dynegy, Mirant, and Calpine. First, levered betas11

(a measure of total corporate risk which includes business and financial risk) for the five 

companies were calculated using five years of historical stock price data. Second, unlevered 

betas (a measure of business risk, i.e., those affected by a firm’s investment decisions) were 

9A project’s capital structure is the appropriate debt capacity given a certain level of equity, 

commonly represented as “D/E,” i.e., debt/equity. The debt is the sum of all interest bearing short 

term and long term liabilities while equity is the amount that the project sponsors inject as equity 

capital. 

10Merchant ROE, as additionally observed by EIA, have risen over time. 

11Levered beta is directly measured from the company’s stock returns with no adjustment made 

for the debt financing undertaken by the company. It is also known as equity beta. Hence, levered 

beta incorporates both business and financing risk undertaken by the company. 
8-9 

calculated using the estimated levered beta, the companies’ market debt/equity ratio, and the 

riskiness of debt. As most comparables historically had periods of financial distress, the 

unlevering12 approach was modified to include the riskiness of debt, instead of purely using the 

Hamada equation.13 The unlevered betas were then relevered14 at the target debt/equity ratio of 

50/50 to get the relevered equity betas and return on equity. The return on equity was determined 

using the Capital Asset Pricing Model (CAPM). 

The CAPM parameters used to estimate the ROE are as follows: 

x Risk Free Rate based on 20 year T bond rate: 4.9%15

x Market Risk Premium 1926-200616: 7.1% 

x Size Premium: 0.65%17

The estimation of the IPP ROE described here is fairly close to what EIA has published. EIA 

estimates a 2010 ROE of roughly 14.8% at a D/E ratio of 45/55 and increasing to approximately 

16% by 2012.18

Merchant Cost of Debt 

The cost of debt for the merchant sector was computed assuming an average 3-month LIBOR 

(London Interbank Offered Rate) of 4.9-5% and an average spread of 3% reflecting the low 

medium grade or low grade nature of merchant bonds. An additional one percent spread was 

assumed for combustion turbine units due to the high price risk for combustion turbine units. 

Debt and Equity Shares and Technology Risk 

The capitalization structure for merchant financings was estimated to be 45/55 based on empirical 

analyses. This capitalization structure was assumed to be on average reflective of the combined 

cycle for reasons discussed earlier in this document. 

Each generation technology was considered to have its own risk profile. Some evidence indicated 

that the greater the base load share, the lower the asset risk. This is consistent with having 

revenues that are more related to variable cost advantages as well as the value of capacity as 

opposed to peaking units which are more dependent on scarcity or capacity revenue, which, in 

turn, has very high systemic risk. 

There are two main mechanisms for reflecting the greater risk for peakers and the lower risk for 

base load. First, the ROE could have been adjusted such that for a given target leverage, the 

ROE would be higher for peakers, and lower for base load. For example, an unlevered beta and 

12The unlevering process removes a company’s financing decision from the beta calculation. The 

calculation therefore, attempts to isolate the business (operating risk) of the firm. 

13The Hamada equation is described at http://www.answers.com/topic/hamada-equation as “A 

fundamental analysis method of analyzing a firm's costs of capital as it uses additional financial 

leverage, and how that relates to the overall riskiness of the firm. The measure is used to 

summarize the effects this type of leverage has on a firm's cost of capital (over and above the cost 

of capital as if the firm had no debt).” 

14The relevering process estimates the levered beta of the firm given a target capital structure and 

the pure business risks of the firm as determined from the unlevering process 

15Federal Reserve Statistical Release (H15 data), May 2007 

16Source: Stocks, Bonds, Bills, and Inflation, 2007 Yearbook Valuation Edition, 

Morningstar/Ibbotson’s Associates 

17Source: Stocks, Bonds, Bills, and Inflation, 2007 Yearbook Valuation Edition, 

Morningstar/Ibbotson’s Associates 

18See Electricity Market Module of NEMS, EIA Annual Energy Outlook, May 2009 
8-10 

ROE (which assumes zero leverage) could have been calculated using the risk differentiated 

capital structures and then relevered at some target leverage. This would have yielded a different 

ROE for each technology but the same capital structure across all technologies. 

The second option was to keep the same ROE while varying the capital structure. This was the 

adopted approach. Thus, even though the leverage of peakers was lowered, the ROE was not 

lowered. This raised the weighted average cost of capital and the resulting capital charge rate. 

This effectively also raised the unlevered beta for peakers relative to combined cycle. For base 

load, leverage was raised without raising ROE, effectively lowering the unlevered beta and the 

cost of capital. 

8.2.5 Development of Utility Financing Parameters 

Utility ROE 

The utility return on equity was calculated to be 10.3%. This was based on empirical analysis of 

correlation of returns on the S&P utility Index vs. the broader S&P 500 market index for the last 

five years to determine the levered beta and then unlevering and relevering based on a process 

similar to that for merchant sector. The ROE is also consistent with what state commissions have 

awarded the shareholder-owned electric utilities recently.19

Utility Cost of Debt 

The cost of debt for the utility sector was estimated to be 6.25%. The utility bonds were 

categorized into various credit rating rungs based on information obtained from the Edison Electric 

Institute.20 Historical yields were analyzed for the various rungs based on data obtained from 

Bloomberg. A weighted average cost of debt was then determined based on the historical yields 

and percentages of utility credit rating classes. The estimated value was also corroborated against 

the yield to maturity of Moody’s average utility bond index. 

Debt and Equity Shares 

The target capitalization structure for utilities was determined using US utility capitalization ratios 

derived from Bloomberg data. Similar CAPM parameters were used to estimate the ROE of the 

utility sector. The capitalization structure for utility financings was estimated to be 55/45 based on 

empirical analyses and this capitalization structure was assumed to be on average reflective of all 

technologies. 

Technology Risks 

For the utility financing, we assumed that the required returns for regulated utilities are 

independent of technology. This assumption was a simplifying assumption, and further empirical 

work may be warranted here. 

8.2.6 Development of Other Parameters 

Taxation and Insurance Costs 

Corporate and State Income Taxes: The maximum US corporate income tax rate is 35%.21 State 

taxes vary but on a national average basis, the state taxes are 6.50%.22 This yields a net effective 

tax rate of 39.3%. 

19See page 35, 2006 Financial Review, Annual Report of the U.S Shareholder Owned Electric 

Utility Industry 

202006 Financial Review, Annual Report of the U.S Shareholder Owned Electric Utility Industry 

21Internal Revenue Service, Publication 542. 

22Population weighted average based on 2008 state taxes information available at Federation of 

Tax Administrators, ttp://www.taxadmin.org/fta/rate/corp_inc.html. 
8-11 

State Property Taxes: US state property taxes are approximately 0.9% based on a national 

average basis. This is based on extensive primary and secondary research conducted by ICF 

using property tax rates obtained from various state agencies. 

Insurance Costs: Insurance costs are approximately 0.3%. This is based on estimates of 

insurance costs on a national average basis. 

Inflation 

The inflation rate of 2.25% is based on an assessment of implied inflation from an analysis of 

yields on 5 year and 10 year Treasury securities and Treasury Inflation Protected Securities 

(TIPS). 

Book life, Debt Life and Depreciation 

Table 8-4 presents a summary of various assumed lives at the national level. 

Table 8-4 Book Life, Debt Life and Depreciation Schedules for EPA Base Case v. 4.10 

Technology Book Life 

(Years) 

Debt Life 

(Years) 

US - MACRS 

Depreciation Schedule 

Combined Cycle 30 20 20 

Combustion Turbine 30 15 15 

Coal Steam and IGCC 40 20 20 

Nuclear 40 20 15 

Solar and Geothermal 20 20 5 

Biomass 40 20 7 

Wind and Landfill Gas 20 20 7 

Retrofits 30 20 20 

Book Life or Useful Life of Plant: 

The book life or useful life of a plant was estimated based on researching financial statements of 

utility and merchant generation companies. The financial statements23 typically list the period over 

which long lived assets are depreciated for financial reporting purposes. The research conducted 

broadly supports the numbers outlined in the table above. 

Debt Life: The debt life is assumed to be on a 20 years schedule except in the case of combustion 

turbine where debt life is lower. 

Depreciation Schedule: 

The US MACRS24 depreciation schedules were obtained from IRS Publication 94625 that lists the 

schedules based on asset classes. The document specifies a 5 years depreciation schedule for 

wind energy projects and 20 years for Electric Utility Steam Production plants. These exclude 

combustion turbines which have a separate listing at 15 years. Nuclear Power Plants are 

separately listed at 15 years as well. 

23SEC 10K filings of electric utilities and pure merchant companies. For example, Calpine’s 10K 

lists 35 years of useful life for base load plants, DTE energy uses 40 years for generation 

equipment; Dynegy gives a range of 20-40 years for power generation facilities; Mirant reports 14-

35 years for power production equipment; Reliant: 10-35 years 

24MACRS refers to the Modified Accelerated Cost Recovery System, issued after the release of 

the Tax Reform Act of 1986. It allowed faster depreciation than with previous methods. 

25IRS Publication 946, “How to Depreciate Property”, Table B-2, Class Lives and Recovery 

Periods.