8-1



## 8 Financial Assumptions This chapter presents the financial assumptions use d in EPA Base Case v.4.10. The first section gives a summary of each of the key financial parame ters. The remainder of the chapter presents an in-depth explanation of the theoretical underpin nings 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 genera tion and emission control technologies, each of which requires financing. 1 Table 8-1 presents the capital charge rate, disco unt 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 u sed to convert the capital cost of a technology int o a stream of levelized annual payments that ensure c apital recovery. The discount rate is used to translate future cash flows into current dollars bytaking into account factors (like inflation and th e ability to earn interest), which make one dollar to morrow 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 investme nt.

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 c apital charge rates shown in the table. However, while the technology-differentiated discou nt rates appearing in the table were used in deriving these capital charge rates, in EPA Base Ca se 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 n ew (potential) units and environmental retrofits that IPM installs. The capital cost of e xisting and planned/committed generating units and the emission controls already on these units are co nsidered “sunk costs” and are not represented in the model.8-2

Table 8-1 U.S. Discount Rates and Capital Charge R ates 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 Gasifi cation Combined Cycle without Carbon Capture 1 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) 2 9.1% 5.5% 40 Biomass with ARRA Loan Guarantees 3 9.3% 4.6% 40 Biomass without ARRA Loan Guarantees 11.1% 6.2% 40 Wind and Landfill Gas with ARRA Loan Guarantees 2 10.1% 4.6% 20 Wind and Landfill Gas without ARRA Loan Guarantees 12.2% 6.2% 20 Solar and Geothermal with ARRA Loan Guarantees 2 10.1% 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. discou nt rate of 6.15% is used across all technologies in EPA Base Case v.4.10.
1 The capital charge rate for these technologies incl udes a 3% climate change uncertainty adder. (See text.)
2 The capital charge rate for this technology reflect s the impact of the PTC provided under the Energy Policy Act of 2005. (See text.)
3 The capital charge rate for these technologies refl ects 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 rate s shown in Table 8-1 for Supercritical Pulverized Coal and Integrated Gasification Combine d 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 increase d financing costs for investment decisions involving coal plants without carbon capture caused by uncertainty surrounding possible future climate change policies that could limit CO 2 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 20 16.

Energy Policy Act Production Tax Credit for Nuclear : The Energy Policy Act of 2005 (Sections 1301, 1306, and 1307) provides a producti on 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 “Nuc lear with Production Tax Credit (PTC).”

8.1.2 ARRA Production and Investment Tax Credit (PT C and ITC) for Renewables In addition to the loan guarantees that are reflect ed 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 renewab les. These are represented in EPA Base Case, v.4.10 as a 30% reduction in the capital costof 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 c osts) 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 perio ds if affected sources have allowances banked between those two periods. This is a standa rd economic result for cap-and-trade programs and prevents sources from profiting by arb itraging 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 int er-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 param eters.

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 invest ment 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 cap ital cost into a stream of levelized annual payments that ensures capital recovery of an invest ment.

Discount Rate The discount rate is a function of the following pa rameters:

x Capital structure (Share of Equity vs. Debt)

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

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 parame ters that overlap in part with the discount rate, but also include parameters related to the amortiza tion of capital:

x Capital structure (Debt/Equity shares of an invest ment)

x Pre-tax debt rate (or interest cost)

x Debt Life8-4

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 fo r earnings before interest, taxes, and depreciation (EBITDA) or pure operating earnings su ch that the project is able to recover the cost of equity as the internal rate of return over the l ifetime of the project. The sum of discounted cash flows to the equity holders over the lifetime of th e project, discounted at the cost of equity is set equal to the initial investment. The capital charg e 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 he avily dependent on market structure risks. The range of risks has increased due to deregulation wh ich has resulted in approximately 35 percent to 40 percent of capacity being deregulated IPP (In dependent Power Producer) capacity. For example, merchant IPP's selling into spot market ha ve 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 (cor porate 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 corre lated market risk is based on the Capital Asset Pricing model and associated financial theory. Thi s analysis takes into account differences in technology and market structure risks.

Differences between corporate and project financing s are highlighted but no specific adjustment has been made for them.

Market Structure Risks The power sector in North America can be divided in to the traditional regulated sector (as known as “cost of service” sector) and deregulated mercha nt sector (as known as “competitive” sector).

x Traditional Regulated - The traditional regulated market structure is ty pical of the vertically integrated utilities where generation (and transmis sion and distribution, abbreviated T&D) investments are approved through a regulatory proce ss 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 determi ned. Returns are affected by market conditions due to regulatory lag and other imperfec tions 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 m arket structure. A closely related market structure is the situation where a plant is built u nder a power purchase agreement (PPA) with a utility with known pricing that allows for a veryhigh degree of investment amortization during the contract period. In such an arrangement, the r isks are more credit and performance related and much less market related.

x Deregulated Merchant- In a deregulated merchant market structure, inve stments bear the full or a very high degree of market risk as the pr ice 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 commodity8-5 prices, as well as on capital investment cycles and remaining price related regulation, e.g., FERC price caps on capacity prices. The capital in vestment 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 a s compared to in the traditional regulated sector, and hence, carry more business or market ri sk. In this report, we use the term “merchant financing” to refer to this type of marke t 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 deregul ated 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 pe aking unit and is able to generate revenues only in times of high demand, a combined cycle unitis 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 mark et structure and technology risks, differences also may occur because of financing schemes availab le. 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 sin gle project. In this type of financing, the debtors have recourse to the entire company’s asset s.

x Project finance, as this category of financing is often labeled, allows developers to seek financing using only the project as recourse for th e 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 develope r. This approach can be more risky than corporate finance, all else being equal, because th ere 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 becaus e: (1) they may have a self-sustaining revenue stream that is greater than the corporate a verage, or (2) risk is reduced through a long-term PPA with a credit worthy counterparty suc h as a vertically integrated utility or a regulated affiliate of a merchant company.

There are many benefits of a project financing stru cture 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 italso solves some of the agency problems and underinvestment issues that corporate financed stru ctures face1.

However, as noted above, this analysis does not mak e 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 i s more observable than project financing2 and has evolved in the power sector to the level of mak ing key risk inferences possible (e.g., IPP and utility stock trades), assessment of market correla ted risks should be based on IPP and utility corporate financing.

1 For more information on project financing, see pap er titled “The Economic Motivations for Using Project Finance” by Benjamin C. Esty, Harvard Busin ess School, Feb 2003

2 Project Financing data is less observable as it’s n ot 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 powe r generation assets, and recent development trends an d emphasis on long term contracts3. In this approach, for modeling purposes, we assume that newunits are financed as a weighted average of utility and merchant financing parameters. For n ew units we assume that both utility and merchant components get equal weights. For retrofi ts, 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. Unde r 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 o f a retrofit is 55/45 under utility financing and 45/55 under merchant financing. Under the assumpti on of a 2/3, 1/3, utility/merchant weighting, the debt to equity ratio under hybrid fi nancing is D = (55 * 2/3) + (45 * 1/3) = 51.6 / E = (45 * 2/3) + (55 * 1/3) = 48.3. A full summaryfor all technologies appears in Table 8-2 below.

Capital Charge Rate – A More Detailed Description The capital charge rate is calculated by solving fo r earnings before interest, taxes, and depreciation (EBITDA) or pure operating earnings su ch that the project is able to recover the cost of equity as the internal rate of return over the l ifetime of the project. The sum of discounted cash flows to the equity holders over the lifetime of th e project, discounted at the cost of equity is set equal to the initial investment. The capital charg e rate so calculated is defined as follows:

Table 8-2 Capital Structure Assumptions for EPA Ba se 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.

3 An alternate approach is to categorize the United S tates 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 assumption s. Such an approach could result in overbuilding in the cost-of-service region due to l ower 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 characterizi ng these limits is extremely complex, a hybrid approach is used.

4 Retrofits are largely associated with coal fired pl ants and most coal fired plants are currently owned and operated by utilities in a “utility finan cing” structure. Moreover, since the magnitude of the retrofit investment is not as large as a plant investment, the financing of a retrofit is more lik ely to happen from a firm’s internal cash flows instead of external financing.8-7 The discounted cash flow to the equity holders of t he project is characterized in terms of the Free Cash Flow to Equity (FCFE). FCFE is a valuation te chnique 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 valuati on of assets that have finite economic lives and where debt levels vary from year to year. In t he 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 calc ulated 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 t he sections below.

8.2.3 Calculation of the Hybrid Capital Charge Rate s ROE The first step was the calculation of a return on e quity (ROE) using an average ROE under utility financing (10.3%) and merchant financing (15.2%) as suming 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 “Deb t 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 ass umed 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 co mbined cycle technology is considered to have “average” market risk being an intermediate ty pe technology. Also, in the aggregate, the five selected IPP companies 8 have more combined cycle capacity in their supply mix than any other technology. Additionally, going forward, it is exp ected that gas will continue to play an increasingly important role in the supply mix of bo th 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 combi ned cycle facility.

5 An alternative definition of free cash flow to equi ty is as follows: Net Income + Depreciation – capital expenditures – working capital change – Pri ncipal Payments + New Debt Issued

6 The Pennsylvania-New Jersey-Maryland Interconnectio n (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.

7 Even though ROE is kept the same across all technol ogies, it doesn’t mean that the market risks are considered the same for each technology. See c apital structure discussion in the next paragraph.

8 Our merchant parameters are derived from market obs ervations of five IPP companies – see discussion on development of merchant financed para meters.8-8

Debt Equity Share Second, the capital structures (D/E)9 for the vario us technology types were calculated using an average of utility and merchant financing. The uti lity debt capacity (and returns) is assumed to be independent of technology type based on the theoret ical assumption that regulation will provide an average return to the entire rate base. The mercha nt debt capacity is based on market risk where a base load plant is likely to have a higher debt c apacity 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 implem ented by varying the capital structure. As shown in Table 8-2 and discussed above, a peaking u nit 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 l ess 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 rat e 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 o f debt is assumed to be the same across all technologies while the merchant cost of debt is hig her than utility and is higher for a combustion turbine unit than for a combined cycle or a coal pl ant. 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 equi ty 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 betas 11 (a measure of total corporate risk which includes b usiness and financial risk) for the five companies were calculated using five years of histo rical stock price data. Second, unlevered betas (a measure of business risk, i.e., those affe cted by a firm’s investment decisions) were

9 A project’s capital structure is the appropriate de bt capacity given a certain level of equity, commonly represented as “D/E,” i.e., debt/equity. T he 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.

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

11 Levered beta is directly measured from the company’ s stock returns with no adjustment made for the debt financing undertaken by the company. I t 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 co mpanies’ market debt/equity ratio, and the riskiness of debt. As most comparables historicall y had periods of financial distress, the unlevering 12 approach was modified to include the riskiness of debt, instead of purely using the Hamada equation. 13 The unlevered betas were then relevered 14 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 1926-2006 16: 7.1%

x Size Premium: 0.65% 17

The estimation of the IPP ROE described here is fai rly close to what EIA has published. EIA estimates a 2010 ROE of roughly 14.8% at a D/E rati o of 45/55 and increasing to approximately 16% by 2012. 18

Merchant Cost of Debt The cost of debt for the merchant sector was comput ed assuming an average 3-month LIBOR (London Interbank Offered Rate) of 4.9-5% and an av erage 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 hig h price risk for combustion turbine units.

Debt and Equity Shares and Technology Risk The capitalization structure for merchant financing s was estimated to be 45/55 based on empirical analyses. This capitalization structure was assume d to be on average reflective of the combined cycle for reasons discussed earlier in this documen t.

Each generation technology was considered to have i ts 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 adv antages as well as the value of capacity as opposed to peaking units which are more dependent o n 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

12 The unlevering process removes a company’s financin g decision from the beta calculation. The calculation therefore, attempts to isolate the busi ness (operating risk) of the firm.

13 The Hamada equation is described at http://www.answers.com/topic/hamada-equation as “A fundamental analysis method of analyzing a firm's c osts of capital as it uses additional financial leverage, and how that relates to the overall riski ness 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).”

14 The relevering process estimates the levered beta o f the firm given a target capital structure and the pure business risks of the firm as determined f rom the unlevering process

15 Federal Reserve Statistical Release (H15 data), May2007

16 Source: Stocks, Bonds, Bills, and Inflation, 2007 Y earbook Valuation Edition, Morningstar/Ibbotson’s Associates

17 Source: Stocks, Bonds, Bills, and Inflation, 2007 Y earbook Valuation Edition, Morningstar/Ibbotson’s Associates

18 See Electricity Market Module of NEMS, EIA Annual E nergy Outlook, May 20098-10

ROE (which assumes zero leverage) could have been c alculated using the risk differentiated capital structures and then relevered at some targe t leverage. This would have yielded a different ROE for each technology but the same capital struct ure across all technologies.

The second option was to keep the same ROE while va rying the capital structure. This was the adopted approach. Thus, even though the leverage o f 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, effe ctively 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 1 0.3%. 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 u nlevering and relevering based on a process similar to that for merchant sector. The ROE is al so consistent with what state commissions have awarded the shareholder-owned electric utilities re cently. 19

Utility Cost of Debt The cost of debt for the utility sector was estimat ed 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 r ungs based on data obtained from Bloomberg. A weighted average cost of debt was the n determined based on the historical yields and percentages of utility credit rating classes. T he estimated value was also corroborated against the yield to maturity of Moody’s average utility bo nd index.

Debt and Equity Shares The target capitalization structure for utilities w as determined using US utility capitalization ratio s derived from Bloomberg data. Similar CAPM paramete rs were used to estimate the ROE of the utility sector. The capitalization structure for u tility financings was estimated to be 55/45 based o n empirical analyses and this capitalization structur e was assumed to be on average reflective of all technologies.

Technology Risks For the utility financing, we assumed that the requ ired returns for regulated utilities are independent of technology. This assumption was a s implifying 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 sta te taxes are 6.50%. 22 This yields a net effective tax rate of 39.3%.

19 See page 35, 2006 Financial Review, Annual Report o f the U.S Shareholder Owned Electric Utility Industry

20 2006 Financial Review, Annual Report of the U.S Sha reholder Owned Electric Utility Industry

21 Internal Revenue Service, Publication 542.

22 Population weighted average based on 2008 state tax es 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% base d on a national average basis. This is based on extensive primary and secondary research conducted by ICF using property tax rates obtained from various stat e agencies.

Insurance Costs: Insurance costs are approximately 0.3%. This is ba sed on estimates of insurance costs on a national average basis.

Inflation The inflation rate of 2.25% is based on an assessme nt of implied inflation from an analysis of yields on 5 year and 10 year Treasury securities an d Treasury Inflation Protected Securities (TIPS).

Book life, Debt Life and Depreciation Table 8-4 presents a summary of various assumed liv es at the national level.

Table 8-4 Book Life, Debt Life and Depreciation Sc hedules 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 estimat ed based on researching financial statements of utility and merchant generation companies. The fina ncial statements 23 typically list the period over which long lived assets are depreciated for financi al 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 sche dule except in the case of combustion turbine where debt life is lower.

Depreciation Schedule: The US MACRS 24 depreciation schedules were obtained from IRS Publ ication 946 25 that lists the schedules based on asset classes. The document spe cifies a 5 years depreciation schedule for wind energy projects and 20 years for Electric Util ity Steam Production plants. These exclude combustion turbines which have a separate listing a t 15 years. Nuclear Power Plants are separately listed at 15 years as well.

23 SEC 10K filings of electric utilities and pure merc hant 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: 1 0-35 years

24 MACRS refers to the Modified Accelerated Cost Recov ery System, issued after the release of the Tax Reform Act of 1986. It allowed faster depreciation than with previous methods.

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