morin testimony final - national grid€¦ · 29/01/2010 · 14 journal of business...

National Grid Niagara Mohawk Power Corporation INVESTIGATION AS TO THE PROPRIETY OF PROPOSED ELECTRIC TARIFF CHANGES Testimony and Exhibits of: Roger A. Morin Andrew E. Dinkel Book 2 January 29, 2010 Submitted to: New York Public Service Commission Docket No. 10-E-____ Submitted by:

Testim

ony of

Roger A

. Morin

Before the Public Service Commission

NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID

Direct Testimony

of

Roger A. Morin, PhD

Dated: January 29, 2010

1

Testimony of Dr. Roger A. Morin, PhD

Table of Contents I. Introduction and Purpose .............................................................................1 II. Regulatory Framework and Rate of Return .................................................7 III. Cost of Equity Estimates............................................................................17 A. DCF Estimates ...............................................................................20 B. CAPM and Risk Premium Estimates.............................................39 C. Historical Risk Premium Estimate.................................................57 D. Flotation Cost Adjustment .............................................................62 IV. Summary and Cost of Equity Recommendation........................................68

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I. Introduction and Purpose 1

Q. Please state your name, address, and occupation. 2

A. My name is Dr. Roger A. Morin. My business address is Georgia State 3

University, Robinson College of Business, University Plaza, Atlanta, 4

Georgia, 30303. I am Emeritus Professor of Finance at the Robinson 5

College of Business, Georgia State University and Professor of Finance 6

for Regulated Industry at the Center for the Study of Regulated Industry at 7

Georgia State University. I am also a principal in Utility Research 8

International, an enterprise engaged in regulatory finance and economics 9

consulting to business and government. 10

11

Q. Please describe your educational background. 12

A. I hold a Bachelor of Engineering degree and an MBA in Finance from 13

McGill University, Montreal, Canada. I received my Ph.D. in Finance and 14

Econometrics at the Wharton School of Finance, University of 15

Pennsylvania. 16

17

Q. Please summarize your academic and business career. 18

A. I have taught at the Wharton School of Finance, University of 19

Pennsylvania, Amos Tuck School of Business at Dartmouth College, 20

Drexel University, University of Montreal, McGill University, and 21

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Georgia State University. I was a faculty member of Advanced 1

Management Research International, and I am currently a faculty member 2

of The Management Exchange Inc. and Exnet, Inc., where I continue to 3

conduct frequent national executive-level education seminars throughout 4

the United States and Canada. In the last thirty years, I have conducted 5

numerous national seminars on “Utility Finance,” “Utility Cost of 6

Capital,” “Alternative Regulatory Frameworks,” and on “Utility Capital 7

Allocation,” which I have developed on behalf of The Management 8

Exchange Inc. and Exnet in conjunction with Public Utilities Reports, Inc. 9

10

I have authored or co-authored several books, monographs, and articles in 11

academic scientific journals on the subject of finance. They have 12

appeared in a variety of journals, including The Journal of Finance, The 13

Journal of Business Administration, International Management Review, 14

and Public Utilities Fortnightly. I published a widely-used treatise on 15

regulatory finance, Utilities' Cost of Capital, Public Utilities Reports, Inc., 16

Arlington, Va. 1984. In late 1994, the same publisher released Regulatory 17

Finance, a voluminous treatise on the application of finance to regulated 18

utilities. A revised and expanded edition of this book entitled The New 19

Regulatory Finance was published in August 2006. I have engaged in 20

extensive consulting activities on behalf of numerous corporations, legal 21

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firms, and regulatory bodies in matters of financial management and 1

corporate litigation. Exhibit __ (RAM-1) describes my professional 2

credentials in more detail. 3

4

Q. Have you previously testified on cost of capital before utility 5

regulatory commissions? 6

A. Yes, I have been a cost of capital witness before some fifty (50) regulatory 7

bodies in North America, including the New York Public Service 8

Commission (Commission). I have testified before the following federal, 9

state, provincial, and other local regulatory commissions: 10

Alabama Florida Missouri Ontario Alaska Georgia Montana Oregon Alberta Hawaii Nevada Pennsylvania Arizona Illinois New Brunswick Quebec

Indiana New Hampshire South Carolina British Columbia Iowa New Jersey South Dakota California Kentucky New Mexico Tennessee City of New Orleans Louisiana New York Texas Colorado Maine Newfoundland Utah CRTC Manitoba North Carolina Vermont Delaware Maryland North Dakota Virginia District of Columbia Michigan Nova Scotia Washington FCC Minnesota Ohio West Virginia FERC Mississippi Oklahoma 11

The details of my participation in regulatory proceedings are provided in 12

Exhibit __ (RAM-1). 13

Q. What is the purpose of your testimony in this proceeding? 14

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A. The purpose of my testimony in this proceeding is to present an 1

independent appraisal of the fair and reasonable rate of return on Niagara 2

Mohawk Power Corporation’s (“Niagara Mohawk” or the “Company”) 3

electricity delivery operations in the State of New York, with particular 4

emphasis on the fair return on the Company’s common equity capital or 5

book equity (ROE) committed to that business. Based upon this appraisal, 6

I have formed my professional judgment as to a return on such capital that 7

would: (1) be fair to the customer, (2) allow the Company to attract capital 8

on reasonable terms, (3) maintain the Company’s financial integrity, and 9

(4) be comparable to returns offered on comparable risk investments. I 10

will testify in this proceeding as to that opinion. I have also been asked to 11

comment on the reasonableness of the Company’s capital structure. 12

13

This testimony and accompanying exhibits and appendices were prepared 14

by me or under my direct supervision and control. The source documents 15

for my testimony are Company records, public documents, commercial 16

databases, and my personal knowledge and experience. 17

18

Q. Please briefly identify the exhibit and appendices accompanying your 19

testimony. 20

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A. I have attached to my testimony Exhibit __ (RAM-1) through Exhibit __ 1

(RAM-14) and Appendices A and B. These exhibits and Appendices 2

relate directly to points in my testimony, and are described in further detail 3

in connection with the discussion of those points in my testimony. 4

5

Q. Please summarize your findings concerning Niagara Mohawk’s cost of 6

common equity. 7

A. I have examined Niagara Mohawk’s risks and concluded that the 8

Company’s risk environment, including the impact of adopting the 9

Company’s proposal to adopt a revenue decoupling mechanism, is 10

comparable to the industry average. It is my opinion that a just and 11

reasonable rate of return on common equity (“ROE”) invested in Niagara 12

Mohawk’s electric utility operations is 10.85%. In the event that rates are 13

established for a three-year period in this proceeding, it is my opinion that 14

this ROE should be raised by 25 basis points to 11.1% to compensate 15

investors for the risk of a three year plan. 16

17

Q. What methods have you employed in arriving at such an opinion? 18

A. My opinion derives from studies I performed using the Discounted Cash 19

Flow (DCF), Capital Asset Pricing Model (CAPM), and Risk Premium 20

methods. I performed DCF analyses on two surrogates for the Company. 21

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They are a group of investment-grade, dividend-paying, combination 1

electric and gas electric utilities and a group consisting of the electric 2

utilities that make up Standard & Poor’s Electric Utility Index. The 3

companies in both groups were required to have the majority of their 4

revenues from regulated electric utility operations. I performed two 5

CAPM analyses: a “traditional” CAPM and a method using an empirical 6

approximation of the CAPM (ECAPM). I also performed a historical risk 7

premium analysis on the electric utility industry. 8

9

My recommended rate of return reflects the application of my professional 10

judgment to the indicated returns from my DCF, Risk Premium, and 11

CAPM analyses, to the Company’s current risk environment which I 12

estimate to be comparable on balance to the industry average, and to 13

capital market conditions that continue to reflect uncertainty. 14

15

Q. Dr. Morin, please describe how your testimony is organized. 16

A. The remainder of my testimony is divided into three (3) sections: 17

I. Regulatory Framework and Rate of Return 18

II. Cost of Equity Estimates 19

III. Summary and Cost of Equity Recommendation 20

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The first section discusses the rudiments of rate of return regulation and 1

the basic notions underlying rate of return. The second section contains 2

the application of DCF, CAPM, and Risk Premium tests. In the third 3

section, the results from the various approaches used in determining a fair 4

return are summarized. 5

6

II. Regulatory Framework and Rate of Return 7

Q. Please explain how a regulated company's rates should be set under 8

traditional cost of service regulation. 9

A. Under the traditional regulatory process, a regulated company’s rates 10

should be set so that the company recovers its costs, including taxes and 11

depreciation, plus a fair and reasonable return on its invested capital. The 12

allowed rate of return must necessarily reflect the cost of the funds 13

obtained, that is, investors' return requirements. In determining a 14

company's required rate of return, the starting point is investors' return 15

requirements in financial markets. A rate of return can then be set at a 16

level sufficient to enable the company to earn a return commensurate with 17

the cost of those funds. 18

19

Funds can be obtained in two general forms, debt capital and equity 20

capital. The cost of debt funds can be easily ascertained from an 21

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examination of the contractual interest payments. The cost of common 1

equity funds, that is, investors' required rate of return, is more difficult to 2

estimate. It is the purpose of the next section of my testimony to estimate 3

Niagara Mohawk’s cost of common equity capital. 4

5

Q. What fundamental principles underlie the determination of a fair and 6

reasonable ROE? 7

A. The heart of utility regulation is the setting of just and reasonable rates by 8

way of a fair and reasonable return. There are two landmark United States 9

Supreme Court cases that define the legal principles underlying the 10

regulation of a public utility’s rate of return and provide the foundations 11

for the notion of a fair return: 12

1) Bluefield Water Works & Improvement Co. v. Public Service 13

Commission of West Virginia, 262 U.S. 679 (1923), and 14

2) Federal Power Commission v. Hope Natural Gas Company, 15

320 U.S. 591 (1944). 16

The Bluefield case set the standard against which just and 17

reasonable rates of return are measured: 18

A public utility is entitled to such rates as will permit it to earn a 19 return on the value of the property which it employs for the 20 convenience of the public equal to that generally being made at the 21 same time and in the same general part of the country on 22 investments in other business undertakings which are attended by 23 corresponding risks and uncertainties ... The return should be 24

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reasonable, sufficient to assure confidence in the financial 1 soundness of the utility, and should be adequate, under efficient 2 and economical management, to maintain and support its credit 3 and enable it to raise money necessary for the proper discharge of 4 its public duties. 5

Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm’n of W. 6

Va, 262 U.S. at 692 (emphasis added). 7

8

The Hope case expanded on the guidelines to be used to assess the 9

reasonableness of the allowed return. The Court reemphasized its 10

statements in the Bluefield case and recognized that revenues must cover 11

“capital costs.” The Court stated: 12

13 From the investor or company point of view it is important that 14

there be enough revenue not only for operating expenses but also 15 for the capital costs of the business. These include service on the 16 debt and dividends on the stock ... By that standard the return to 17 the equity owner should be commensurate with returns on 18 investments in other enterprises having corresponding risks. That 19 return, moreover, should be sufficient to assure confidence in the 20 financial integrity of the enterprise, so as to maintain its credit and 21 attract capital. 22

23 Fed. Power Comm’n v. Hope Natural Gas Co., 320 U.S. at 603 (Emphasis 24

added). 25 26 27

The United States Supreme Court reiterated the criteria set forth in Hope 28

in Federal Power Commission v. Memphis Light, Gas & Water Division, 29

411 U.S. 458 (1973), in Permian Basin Rate Cases, 390 U.S. 747 (1968), 30

and most recently in Duquesne Light Co. vs. Barasch, 488 U.S. 299 31

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(1989). In the Permian Basin Rate Cases, the Supreme Court stressed that 1

a regulatory agency's rate of return order should 2

reasonably be expected to maintain financial integrity, attract 3 necessary capital, and fairly compensate investors for the risks 4 they have assumed. 5 6

Permian Basin Rate Cases, 390 U.S. at 792. 7

8

Therefore, the “end result” of this Commission's decision should be to 9

allow Niagara Mohawk the opportunity to earn a return on equity that is: 10

(1) commensurate with returns on investments in other firms having 11

corresponding risks, (2) sufficient to assure confidence in the Company’s 12

financial integrity, and (3) sufficient to maintain the Company’s 13

creditworthiness and ability to attract capital on reasonable terms. 14

15

Q. How is the fair rate of return determined? 16

A. The aggregate return required by investors is called the “cost of capital.” 17

The cost of capital is the opportunity cost, expressed in percentage terms, 18

of the total pool of capital employed by the Company. It is the composite 19

weighted cost of the various classes of capital (e.g., bonds, preferred stock, 20

common stock) used by the utility, with the weights reflecting the 21

proportions of the total capital that each class of capital represents. The 22

fair return in dollars is obtained by multiplying the rate of return set by the 23

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regulator by the utility’s “rate base.” The rate base is essentially the net 1

book value of the utility’s plant and other assets used to provide utility 2

service in a particular jurisdiction. 3

4

While utilities like Niagara Mohawk enjoy varying degrees of monopoly 5

in the sale of public utility services, they must compete with everyone else 6

in the free, open market for the input factors of production, whether labor, 7

materials, machines, or capital. The prices of these inputs are set in the 8

competitive marketplace by supply and demand, and it is these input 9

prices that are incorporated in the cost of service computation. This is just 10

as true for capital as for any other factor of production. Since utilities and 11

other investor-owned businesses must go to the open capital market and 12

sell their securities in competition with every other issuer, there is 13

obviously a market price to pay for the capital they require, for example, 14

the interest on debt capital, or the expected return on equity. 15

16

Q. How does the concept of a fair return relate to the concept of 17

opportunity cost? 18

A. The concept of a fair return is intimately related to the economic concept 19

of “opportunity cost.” When investors supply funds to a utility by buying 20

its stocks or bonds, they are not only postponing consumption or giving up 21

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the alternative of spending their dollars in some other way; they are also 1

exposing their funds to risk and forgoing returns from investing their 2

money in alternative comparable risk investments. The compensation they 3

require is the price of capital. If there are differences in the risk of the 4

investments, competition among firms for a limited supply of capital will 5

bring different prices. These differences in risk are translated by the 6

capital markets into differences in required return, in much the same way 7

that differences in the characteristics of commodities are reflected in 8

different prices. 9

10

The important point is that the required return on capital is set by supply 11

and demand, and is influenced by the relationship between the risk and 12

return expected for those securities and the risks expected from the overall 13

menu of available securities. 14

15

Q. What economic and financial concepts have guided your assessment 16

of the Company’s cost of common equity? 17

A. Two fundamental economic principles underlie the appraisal of the 18

Company’s cost of equity, one relating to the supply side of capital 19

markets, the other to the demand side. 20

21

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On the supply side, the first principle asserts that rational investors 1

maximize the performance of their portfolios only if they expect the 2

returns on investments of comparable risk to be the same. If not, rational 3

investors will switch out of those investments yielding lower returns at a 4

given risk level in favor of those investment activities offering higher 5

returns for the same degree of risk. This principle implies that a company 6

will be unable to attract capital funds unless it can offer returns to capital 7

suppliers that are comparable to those achieved on competing investments 8

of similar risk. 9

10

On the demand side, the second principle asserts that a company will 11

continue to invest in real physical assets if the return on these investments 12

equals, or exceeds, the company's cost of capital. This principle suggests 13

that a regulatory board should set rates at a level sufficient to create 14

equality between the return on physical asset investments and the 15

company’s cost of capital. 16

17

Q. How does the Company obtain its capital and how is its overall cost of 18

capital determined? 19

A. The funds employed by the Company are obtained in two general forms, 20

debt capital and equity capital. The cost of debt funds can be ascertained 21

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easily from an examination of the contractual interest payments. The cost 1

of common equity funds, that is, equity investors’ required rate of return, 2

is more difficult to estimate because the dividend payments received from 3

common stock are not contractual or guaranteed in nature. They are 4

uneven and risky, unlike interest payments. 5

6

Once a cost of common equity estimate has been developed, it can then 7

easily be combined with the embedded cost of debt based on the utility’s 8

capital structure, in order to arrive at the overall cost of capital (overall 9

rate of return). 10

11

Q. What is the market required rate of return on equity capital? 12

A. The market required rate of return on common equity, or cost of equity, is 13

the return demanded by the equity investor. Investors establish the price 14

for equity capital through their buying and selling decisions in capital 15

markets. Investors set return requirements according to their perception of 16

the risks inherent in the investment, recognizing the opportunity cost of 17

forgone investments in other companies, and the returns available from 18

other investments of comparable risk. 19

20

Q. What must be considered in estimating a fair ROE? 21

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A. The basic premise is that the allowable ROE should be commensurate 1

with returns on investments in other firms having corresponding risks. 2

The allowed return should be sufficient to assure confidence in the 3

financial integrity of the firm, in order to maintain creditworthiness and 4

ability to attract capital on reasonable terms. The attraction of capital 5

standard focuses on investors' return requirements that are generally 6

determined using market value methods, such as the Risk Premium, 7

CAPM, or DCF methods. These market value tests define fair return as 8

the return investors anticipate when they purchase equity shares of 9

comparable risk in the financial marketplace. This is a market rate of 10

return, defined in terms of anticipated dividends and capital gains as 11

determined by expected changes in stock prices, and reflects the 12

opportunity cost of capital. The economic basis for market value tests is 13

that new capital will be attracted to a firm only if the return expected by 14

the suppliers of funds is commensurate with that available from alternative 15

investments of comparable risk. 16

17

Q. How does Niagara Mohawk’s cost of capital relate to that of its parent 18

company? 19

A. Niagara Mohawk is a wholly owned subsidiary of Niagara Mohawk 20

Holdings, Inc., which is a wholly owned subsidiary of National Grid USA, 21

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which in turn is an indirect, wholly owned subsidiary of United Kingdom-1

based National Grid plc (“National Grid”). I am treating Niagara 2

Mohawk’s electric utility operations as a separate stand-alone entity, 3

distinct from its holding company, National Grid, because it is the cost of 4

capital for Niagara Mohawk’s electric utility business that we are 5

attempting to measure and not the cost of capital for National Grid’s 6

consolidated activities. Financial theory establishes that the true cost of 7

capital depends on the use to which the capital is put, which, in this case, 8

is Niagara Mohawk’s electric utility operations in the State of New York. 9

The specific source of funding an investment and the cost of funds to the 10

investor are irrelevant considerations. 11

12

For example, if an individual investor borrows money at the bank at an 13

after-tax cost of 5% and invests the funds in a speculative oil extraction 14

venture, the required return on the investment is not the 5% cost but rather 15

the return foregone in speculative projects of similar risk, say 20%. 16

Similarly, the required return on Niagara Mohawk is the return foregone in 17

comparable risk electric utility operations, and is unrelated to the parent’s 18

cost of capital. In other words, the cost of capital is governed by the risk 19

to which the capital is exposed and not by the source of funds. The 20

identity of the shareholders has no bearing on the cost of equity. 21

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Just as individual investors require different returns from different assets 1

in managing their personal affairs, corporations should behave in the same 2

manner. A parent company normally invests money in many operating 3

companies of varying sizes and varying risks. These operating 4

subsidiaries pay different rates for the use of investor capital, such as long-5

term debt capital, because investors recognize the differences in capital 6

structure, risk, and prospects between subsidiaries. Therefore, the cost of 7

investing funds in an operating utility subsidiary such as Niagara Mohawk 8

is the return foregone on investments of similar risk and is unrelated to the 9

identity of the investor. This is particularly true with respect to Niagara 10

Mohawk and other New York State utilities that are owned by corporate 11

holding company parents with multiple businesses in other states and/or 12

countries. 13

14

III. Cost of Equity Estimates 15

Q. How did you estimate the fair ROE for Niagara Mohawk? 16

A. I employed three methods: (1) the DCF, (2) the CAPM, and (3) the Risk 17

Premium. All three are market-based methods and are designed to 18

estimate the return required by investors on the common equity capital 19

committed to Niagara Mohawk. 20

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Q. Why did you use more than one approach for estimating the cost of 1

equity? 2

A. No one individual method provides the necessary level of precision for 3

determining a fair return, but each method provides useful evidence to 4

facilitate the exercise of an informed judgment. Reliance on any single 5

method or preset formula is inappropriate when dealing with investor 6

expectations because of possible measurement errors and vagaries in 7

individual companies’ market data. Examples of such vagaries include 8

insufficient or unrepresentative historical data due to a recent merger, 9

impending merger or acquisition, and a new corporate identity due to 10

restructuring activities. The advantage of using several different 11

approaches is that the results of each one can be used to check the others. 12

13

As a general proposition, it is dangerous to rely on only one generic 14

method to estimate equity costs. The difficulty is compounded when only 15

one variant of that method is employed. It is compounded even further 16

when that one method is applied to a single company. Hence, several 17

methods applied to several comparable risk companies should be 18

employed to estimate the cost of capital. 19

20

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As I have stated, there are three broad generic methods available to 1

measure the cost of equity: DCF, CAPM, and Risk Premium. All three of 2

these methods are accepted and used by the financial community and 3

firmly supported in the financial literature. The weight accorded to any 4

one method may very well vary depending on unusual circumstances in 5

capital market conditions. 6

7

Each method requires the exercise of considerable judgment on the 8

reasonableness of the assumptions underlying the method and on the 9

reasonableness of the proxies used to validate the theory and apply the 10

method. Each method has its own way of examining investor behavior, 11

its own premises, and its own set of simplifications of reality. Investors 12

do not necessarily subscribe to any one method, nor does the stock price 13

reflect the application of any one single method by the price-setting 14

investor. There is no guarantee that a single DCF result is necessarily the 15

ideal predictor of the stock price and of the cost of equity reflected in that 16

price, just as there is no guarantee that a single CAPM or Risk Premium 17

result constitutes the perfect explanation of a stock’s price or the cost of 18

equity. 19

20

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Q. Are there any practical difficulties in applying cost of capital methods 1

in the current environment of turmoil in capital markets? 2

A. Yes, there are. All the traditional cost of equity estimation methods are 3

difficult to implement when you are dealing with the unprecedented 4

conditions of instability and volatility in the capital markets and the fast-5

changing circumstances of the utility industry. This is not only because 6

stock prices are extremely volatile at this time, but also utility company 7

historical data have become less meaningful for an industry experiencing 8

considerable volatility. Past earnings and dividend trends may simply not 9

be indicative of the future. For example, historical growth rates of 10

earnings and dividends have been depressed by eroding margins due to a 11

variety of factors including the sluggish economy, restructuring, and the 12

transition to a more competitive environment. Moreover, historical 13

growth rates may not be representative of future trends for several utilities 14

involved in mergers and acquisitions, as these companies going forward 15

are not the same companies for which historical data are available. 16

17

A. DCF Estimates 18

Q. Please describe the DCF approach to estimating the cost of equity 19

capital. 20

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A. According to DCF theory, the value of any security to an investor is the 1

expected discounted value of the future stream of dividends or other 2

benefits. One widely used method to measure these anticipated benefits in 3

the case of a non-static company is to examine the current dividend plus 4

the increases in future dividend payments expected by investors. This 5

valuation process can be represented by the following formula, which is 6

the traditional DCF model: 7

Ke = D1/Po + g 8

where: 9

Ke = investors’ expected return on equity 10

D1 = expected dividend at the end of the coming year 11

Po = current stock price 12

g = expected growth rate of dividends, earnings, book value, stock 13

price 14

15

The traditional DCF formula states that under certain assumptions, which 16

are described in the next paragraph, the equity investor’s expected return, 17

Ke, can be viewed as the sum of an expected dividend yield, D1/Po, plus 18

the expected growth rate of future dividends and stock price, g. The 19

returns anticipated at a given market price are not directly observable and 20

must be estimated from statistical market information. The idea of the 21

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market value approach is to infer ‘Ke’ from the observed share price, the 1

observed dividend, and an estimate of investors' expected future growth. 2

3

The assumptions underlying this valuation formulation are well known, 4

and are discussed in detail in Chapter 8 of my new text, The New 5

Regulatory Finance. The standard DCF model requires the following 6

main assumptions: a constant average growth trend for both dividends and 7

earnings, a stable dividend payout policy, a discount rate in excess of the 8

expected growth rate, and a constant price-earnings multiple, which 9

implies that growth in price is synonymous with growth in earnings and 10

dividends. The standard DCF model also assumes that dividends are paid 11

at the end of each year when in fact dividend payments are normally made 12

on a quarterly basis. 13

14

Comparable Groups 15

Q. How did you estimate Niagara Mohawk’s cost of equity with the DCF 16

model? 17

A. I applied the DCF model to two proxies for Niagara Mohawk. As a first 18

proxy, I started with the universe of electric utilities covered by Value 19

Line (SIC Codes 4911-4913). From this original group, I eliminated 20

foreign companies, private partnerships, private companies, and 21

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companies below investment-grade (i.e., companies with a bond rating 1

below Baa3 under Moody’s Investor Service’s ratings). From this 2

narrowed group, I further eliminated companies that do not pay dividends 3

and companies with market capitalization less than $500 million (to 4

minimize any stock price anomalies due to thin trading). I eliminated 5

companies that derive less than 50% of their revenues from regulated 6

electric utility operations. Finally, from this restricted group, I retained 7

those companies designated as “combination electric and gas” utilities by 8

AUS Utility Reports, meaning that these companies all possess large 9

amounts of energy distribution assets. 10

11

As a second proxy for Niagara Mohawk, I examined a group consisting of 12

the electric utilities that make up S&P’s Electric Utility Index. The two 13

groups are displayed on Exhibit __ (RAM-2) and Exhibit __ (RAM-3), 14

respectively. 15

16

Q. Are you aware that the Commission has expressed some reservations 17

with your comparable groups in the past, and, if so, how do you 18

respond? 19

A. In the past, the Commission has expressed concern that my comparable 20

groups of electric and combination utilities were riskier than New York 21

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electric utilities because their bond ratings were superior to the average 1

bond rating for my comparable groups. But as I show later, there is little 2

relationship between bond ratings and equity risk for entities that hold 3

investment grade bond ratings. Credit ratings examine risk from a 4

bondholder viewpoint rather than from a shareholder viewpoint. The 5

former is concerned mainly with the ability to service debt and 6

creditworthiness while the latter is concerned with variability and 7

uncertainty of return. Moreover, this criticism is essentially moot because 8

the vast majority of the companies in my two groups of utilities are also 9

members of the comparable groups that have been relied upon by the 10

Commission in recent decisions. Also, my beta risk estimate for Niagara 11

Mohawk of 0.74 is virtually identical to the average beta of the group of 12

companies relied upon by the Commission in other cases, implying 13

comparability of risk. 14

15

The Commission has also criticized my two groups of companies because 16

I employed a 50% minimum regulated revenues screening criterion 17

instead of 70%. Again, this criticism is not justified because the average 18

percentage of regulated electric revenues in my two comparable groups of 19

utilities are 71% and 74%, respectively. 20

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In practical terms, there are only minor differences between the groups of 1

companies that the Commission has relied upon in other cases and my 2

own, and I am confident that the comparable groups that I utilize are 3

regarded by investors as utility businesses that are similar to Niagara 4

Mohawk. 5

6

DCF Dividend Yield Component 7

Q. How did you estimate the two components of the DCF model? 8

A. In order to apply the DCF model, two components are required: the 9

expected dividend yield (D1/P0) and the expected long-term growth (g). 10

The expected dividend D1 in the annual DCF model can be obtained by 11

multiplying the current indicated annual dividend rate by the growth factor 12

(1 + g). 13

14

From a conceptual viewpoint, the stock price to employ in calculating the 15

dividend yield is the current price of the security at the time of estimating 16

the cost of equity. This is because the current stock prices provide a better 17

indication of expected future prices than any other price in an efficient 18

market. An efficient market implies that prices adjust rapidly to the 19

arrival of new information. Therefore, current prices reflect the 20

fundamental economic value of a security. A considerable body of 21

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empirical evidence indicates that capital markets are efficient with respect 1

to a broad set of information. This implies that observed current prices 2

represent the fundamental value of a security, and that a cost of capital 3

estimate should be based on current prices. 4

5

In implementing the DCF model, I have used the dividend yields reported 6

in the November 2009 edition of Value Line’s VLIA software. Basing 7

dividend yields on average results from a large group of companies 8

reduces the concern that the vagaries of individual company stock prices 9

will result in an unrepresentative dividend yield. 10

11

Q. Dr. Morin, are you aware that in recent decisions, the Commission 12

has criticized the dividend yield component of your DCF 13

methodology? 14

A. Yes, I am. In recent cases, the Commission has relied on the average 15

stock price over either three months or six months periods to compute the 16

dividend yield component of the DCF model. I disagree with the use of 17

stock prices reaching back three to six months. The proper stock price to 18

employ is the current price of the security at the time of estimating the cost 19

of equity, rather than some historical average stock price reaching back 20

three or six months. The reason is that the analyst is attempting to 21

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determine a utility’s cost of equity in the future, and since current stock 1

prices provide a better indication of expected future prices than any other 2

price according to the basic tenets of the Efficient Market Hypothesis, the 3

most relevant stock price is the most recent one. The Efficient Market 4

Hypothesis, which is widely accepted, states that capital markets, at least 5

as a practical matter, incorporate into security prices relevant publicly 6

available information, such that current security prices reflect the most 7

recent information and thus are the best representation of investor 8

expectations. Use of any other price violates market efficiency principles. 9

10

There is yet another justification for using current stock prices. In 11

measuring the cost of equity as the sum of dividend yield and growth, the 12

period used in measuring the dividend yield component must be consistent 13

with the estimate of growth with which it is paired. Since the current 14

stock price is caused by the growth foreseen by investors at the present 15

time and not at any other time, it is clear that the use of spot prices is 16

preferable. It is inappropriate to match an average stock price reaching 17

back three to six months with a current estimate of expected growth. This 18

not only violates market efficiency principles, but also constitutes a 19

mismatch in the application of the DCF model. An average stock price 20

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dating back three to six months reflects stale information and may not be 1

representative of current market conditions. 2

3

Q. As a practical matter at this point in time, does it matter if one relies 4

on current stock prices or on average stock prices going back three 5

months? 6

A. As a practical matter, it does not. This is because utility stock prices have 7

been relatively constant over the past three months, as the graph below 8

illustrates over the September-December 2009 period. The Dow Jones 9

Utility Index has remained relatively stable over the period, suggesting 10

that DCF estimates based on current stock prices would not differ 11

markedly from estimates based on the past three months. 12

13

14

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DCF Growth Component 1

Q. How did you estimate the growth component of the DCF model? 2

A. The principal difficulty in calculating the required return by the DCF 3

approach is in ascertaining the growth rate that investors currently expect. 4

Because no explicit estimate of expected growth is observable, proxies 5

must be employed. 6

7

As proxies for expected growth, I examined the consensus growth 8

estimates developed by professional analysts employed by large 9

investment brokerage institutions. Projected long-term growth rates 10

actually used by institutional investors to determine the desirability of 11

investing in different securities influence investors' growth anticipations. 12

These forecasts are made by large reputable organizations, and the data are 13

readily available to investors and are representative of the consensus view 14

of investors. Because of the dominance of institutional investors in 15

investment management and security selection, and their influence on 16

individual investment decisions, analysts' growth forecasts influence 17

investor growth expectations and provide a sound basis for estimating the 18

cost of equity with the DCF model. 19

20

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Growth rate forecasts of several analysts are available from published 1

investment newsletters and from systematic compilations of analysts’ 2

forecasts, such as those tabulated by Zacks Investment Research Inc. 3

(Zacks). I used analysts' long-term growth forecasts contained in Zacks as 4

proxies for investors' growth expectations in applying the DCF model. 5

The latter are also conveniently provided in the Value Line software. I 6

also used Value Line’s growth forecasts as additional proxies. 7

8

Q. Why did you reject the use of historical growth rates in applying the 9

DCF model to electric utilities? 10

A. The average historical growth rates in earnings and dividends for electric 11

utilities are 3.2%, and 2.0% over the past 5 years, respectively. Please see 12

Exhibit __ (RAM-4), columns 2 and 3, for the historical growth in 13

earnings and dividends per share over the last five years for the electric 14

utility companies that make up Value Line’s Electric Utility composite 15

group. Several companies have experienced negative earnings growth 16

rates, as evidenced by the numerous historical growth rates reported on the 17

table that are negative. If we eliminate the negative growth rates, the 18

corresponding growth rates are 5.1% and 3.6%. 19

20

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Historical growth rates have little relevance as proxies for future long-term 1

growth at this time. They are downward-biased by the sluggish earnings 2

performance in the last five/ten years, due to the structural transformation 3

of the electric utility industry from a fully integrated regulated monopoly 4

to a more competitive environment. These anemic historical growth rates 5

are certainly not representative of these companies’ long-term earning 6

power, and produce unreasonably low DCF estimates, well outside 7

reasonable limits of probability and common sense. To illustrate, adding 8

the historical growth rates of 3.2% and 2.1% to the average dividend yield 9

of approximately 4.8% prevailing currently for those same companies, 10

produces preposterous cost of equity estimates of 8.0% and 6.9% using 11

earnings and dividends growth rates, respectively. Of course, these 12

estimates of equity costs are unreasonable as they are barely above or 13

below the cost of long-term debt for these companies. A similar pattern 14

emerges if ten-year instead of five-year historical growth rates are 15

examined. 16

17

I have therefore rejected historical growth rates as proxies for expected 18

growth in the DCF calculation. In any event, historical growth rates are 19

somewhat redundant because such historical growth patterns are already 20

incorporated in analysts’ growth forecasts that should be used in the DCF 21

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model. 1

2

Q. Did you consider any other method of estimating expected growth to 3

apply the DCF model? 4

A. Yes, I did. I considered using the so-called “sustainable growth” method, 5

also referred to as the “retention growth” method. I am aware that this 6

method has been used by the Commission in its DCF analyses in past 7

cases. According to this method, future growth is estimated by 8

multiplying the fraction of earnings expected to be retained by the 9

company, 'b', by the expected return on book equity, ‘ROE’. That is, g = b 10

x ROE where: 11

g = expected growth rate in earnings/dividends 12

b = expected retention ratio 13

ROE = expected return on book equity 14

15

As described below, I am not a proponent of this method because it is 16

inherently circular, for it requires an estimate of the projected ROE, which 17

is the very quantity we are trying to determine in this case. 18

19

Q. Please describe your reservations in regards to the sustainable growth 20

method. 21

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A. First, the sustainable growth method of predicting growth is only accurate 1

under the assumptions that the return on book equity (ROE) is constant 2

over time and that no new common stock is issued by the company, or if 3

so, it is sold at book value. Second, and more importantly, the sustainable 4

growth method contains a logic trap: the method requires an estimate of 5

ROE to be implemented. But if the ROE input required by the model 6

differs from the recommended return on equity, a fundamental 7

contradiction in logic follows. Third, the empirical finance literature 8

demonstrates that the sustainable growth method of determining growth is 9

not as significantly correlated to measures of value, such as stock price and 10

price/earnings ratios, as are other measures of growth. Other proxies for 11

growth, such as analysts' growth forecasts, outperform retention growth 12

estimates. A summary of this literature is available in The New Regulatory 13

Finance, Chapter 9. 14

15

Q. Did you consider using analysts’ forecasts of dividend growth in 16

applying the DCF model? 17

A. No, not at this time. This is because it is widely expected that some 18

utilities will continue to lower their dividend payout ratio over the next 19

several years in response to heightened business risk and the need to fund 20

very large construction programs over the next decade. In other words, 21

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earnings and dividends are not expected to grow at the same rate in the 1

future. 2

3

Whenever the dividend payout ratio is expected to change, the 4

intermediate growth rate in dividends cannot equal the long-term growth 5

rate, because dividend/earnings growth must adjust to the changing payout 6

ratio. The assumptions of constant perpetual growth and constant payout 7

ratio are clearly not met. Thus, the implementation of the standard DCF 8

model is of questionable relevance in this circumstance. 9

10

Dividend growth rates are unlikely to provide a meaningful guide to 11

investors’ growth expectations for utilities in general. This is because 12

utilities’ dividend policies have become increasingly conservative as 13

business risks in the industry have intensified steadily. Dividend growth 14

has remained largely stagnant in past years as utilities are increasingly 15

conserving financial resources in order to hedge against rising business 16

risks. As a result, investors’ attention has shifted from dividends to 17

earnings. Therefore, earnings growth provides a more meaningful guide 18

to investors’ long-term growth expectations. Indeed, it is growth in 19

earnings that will support future dividends and share prices. 20

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Moreover, as a practical matter, while earnings growth forecasts are 1

widely available, there are very few dividend growth forecasts. 2

3

Q. Dr. Morin, are you aware that the Commission has employed 4

forecasts of dividend growth in determining the DCF-derived cost of 5

equity in past cases? 6

A. Yes. I am. For the reasons described above, I disagree. In fact, as 7

displayed on the table below, the current and projected dividend payout of 8

the electric utility industry is declining. Utility dividend policies have, 9

and will continue to be, increasingly conservative in response to growing 10

needs of internal financing that are in turn driven by massive capital 11

expenditure budgets over the next decade. 12

13

Composite Statistics: Electric Utility Industry 2009 2010 2012-2014 Div'ds to Profit 65% 59% 56% Source: Value Line 12/209

14

Q. Is there any empirical evidence documenting the importance of 15

earnings in evaluating investors' expectations? 16

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A. Yes, there is an abundance of evidence attesting to the importance of 1

earnings in assessing investors’ expectations. First, the sheer volume of 2

earnings forecasts available from the investment community relative to the 3

scarcity of dividend forecasts attests to their importance. To illustrate, 4

Value Line, Zacks Investment, First Call Thompson, Reuters, Yahoo 5

Finance, and Multex provide comprehensive compilations of investors’ 6

earnings forecasts. The fact that these investment information providers 7

focus on growth in earnings rather than growth in dividends indicates that 8

the investment community regards earnings growth as a superior indicator 9

of future long-term growth. Second, Value Line’s principal investment 10

rating assigned to individual stocks, Timeliness Rank, is based primarily 11

on earnings, which accounts for 65% of the ranking. 12

13

DCF Estimates 14

Q. What DCF results did you obtain for the combination utilities group? 15

A. Exhibit __ (RAM-5) provides the DCF results for the proxy group of 16

combination utilities using the average long-term growth forecast obtained 17

from Value Line. No growth projection was available for Pepco, and 18

ALLETE was eliminated from the computation on account of its negative 19

growth rate. As shown on Column 2 of Exhibit __ (RAM-5), the average 20

long-term growth forecast obtained from Value Line is 6.6% for this 21

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group. Adding this growth rate to the average expected dividend yield of 1

5.2% shown in Column 3 produces an estimate of equity costs of 11.9% 2

for the group. Recognition of flotation costs brings the cost of equity 3

estimate to 12.2%, shown in Column 5. Using the median instead of the 4

average, the estimate of equity costs is 11.8% for the group. 5

6

Exhibit __ (RAM-6) presents the DCF results using the Zacks growth 7

forecast for each company. Using the Zacks analysts’ consensus forecast 8

of long-term earnings instead of the Value Line forecast, the cost of equity 9

for the group is 10.9% unadjusted for flotation costs. Recognition of 10

flotation costs brings the cost of equity estimate to 11.2%, shown in 11

Column 5 of Exhibit __ (RAM-6). Using the median instead of the 12

average, the cost of equity estimate for the group is 10.9%. 13

14

Q. What DCF results did you obtain for the S&P utility index group? 15

A. Exhibit __ (RAM-7) displays the DCF analysis using Value Line growth 16

projections for the electric utilities that make up Standard & Poor’s Utility 17

Index. As shown on Column 2 of Exhibit __ (RAM-7), the average long-18

term growth forecast obtained from Value Line is 5.6% for this group. 19

Coupling this growth rate with the average expected dividend yield of 20

5.2% shown in Column 3 for each company produces an estimate of 21

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equity costs of 10.8% for the group, unadjusted for flotation costs. 1

Adding an allowance for flotation costs to the results of Column 4 brings 2

the cost of equity estimate to 11.1%, as shown in Column 5. The median 3

estimate is 10.9%. If we limit the sample to those companies with a 4

majority of their revenues that are regulated utility operations, the median 5

cost of equity estimate is 10.6%. This analysis is shown on Exhibit __ 6

(RAM-8). 7

8

Using the consensus analysts’ growth forecast from Zacks instead of the 9

Value Line growth forecast, the median cost of equity estimate for the 10

entire S&P group is 11.7%. This analysis is displayed on Exhibit __ 11

(RAM-9). If we limit the sample to those companies with a majority of 12

their revenues that are regulated utility operations, the median cost of 13

equity estimate is 11.6%. This analysis is shown on Exhibit __ (RAM-14

10). 15

16

Q. Please summarize your DCF estimates. 17

A. The table below summarizes the DCF estimates: 18

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1

DCF STUDY ROE

Comb. Elec. & Gas Utilities Value Line Growth 11.8% Comb. Elec. & Gas Utilities Zacks Growth 10.9% S&P Electric Utilities Value Line Growth 10.6% S&P Electric Utilities Zacks Growth 11.6%

2

B. CAPM and Risk Premium Estimates 3

Q. Dr. Morin, please provide an overview of your risk premium analyses. 4

A. In order to quantify the risk premium for Niagara Mohawk, I performed 5

three risk premium studies. The first two studies deal with aggregate 6

stock market risk premium evidence using two versions of the CAPM 7

method and the third study deals directly with the utility industry. 8

9

CAPM Estimates 10

Q. Please describe your application of the CAPM risk premium 11

approach. 12

A. My first two risk premium estimates are based on the CAPM and on 13

ECAPM, an empirical approximation to the CAPM. The CAPM is a 14

fundamental paradigm of finance. The fundamental idea underlying the 15

CAPM is that risk-averse investors demand higher returns for assuming 16

additional risk, and higher-risk securities are priced to yield higher 17

expected returns than lower-risk securities. The CAPM quantifies the 18

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additional return, or risk premium, required for bearing incremental risk. 1

It provides a formal risk-return relationship anchored on the basic idea that 2

only market risk matters, as measured by beta (β). 3

4

According to the CAPM, securities are priced such that: 5

Expected Return = Risk-Free Rate + Risk Premium 6

7

Denoting the risk-free rate by RF and the return on the market as a whole 8

by RM, the CAPM is stated as follows: 9

K = RF + β(RM - RF) 10

11

This is the seminal CAPM expression, which states that the return required 12

by investors is made up of a risk-free component, RF, plus a risk premium 13

given by β times the market risk premium (RM - RF). The latter bracketed 14

expression is known as the market risk premium (MRP). To derive the 15

CAPM risk premium estimate, three quantities are required: the risk-free 16

rate (RF), beta (β), and the MRP, (RM - RF). For the risk-free rate, I used 17

4.7%, based on current and projected interest rates on long-term U.S. 18

Treasury bonds. For beta, I used 0.74, and for the MRP I used 6.5%. 19

These inputs to the CAPM are explained below. 20

21

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Q. How did you derive the risk free rate of 4.7%? 1

A. To implement the CAPM and Risk Premium methods, an estimate of the 2

risk-free return is required as a benchmark. As a proxy for the risk-free 3

rate, I have relied on the current yields of 30-year Treasury bonds. The 4

yields on interest-bearing and zero-coupon U.S. Treasury 30-year long-5

term bonds prevailing in December 2009 as reported in Value Line are 6

4.6% and 4.8%, respectively. Moreover, it is widely expected that interest 7

rates will rise in 2010 in response to the recovering economy and record-8

high federal deficits. Value Line’s quarterly economic forecast dated 9

November 27th, 2009, calls for an increase of 40 basis points on long-term 10

Treasury bonds at the end of 2010 and higher still in 2011. Bloomberg 11

calls for a similar increase. Based on all these considerations, I use 4.7% 12

as my estimate of the risk-free rate component of the CAPM. 13

14

The appropriate proxy for the risk-free rate in the CAPM is the return on 15

the longest term Treasury bond possible, which is the 30-year Treasury 16

bond. This is because common stocks are very long-term instruments 17

more akin to very long-term bonds rather than to short-term or 18

intermediate-term Treasury notes. In a risk premium model, the ideal 19

estimate for the risk-free rate has a term to maturity equal to the security 20

being analyzed. Common stock is a very long-term investment because 21

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the cash flows to investors in the form of dividends last indefinitely. 1

Accordingly, the yield on the longest-term possible government bonds, 2

that is, the yield on 30-year Treasury bonds, is the best measure of the 3

risk-free rate for use in the CAPM. The expected common stock return is 4

based on very long-term cash flows, regardless of an individual’s holding 5

time period. Moreover, utility asset investments generally have very long-6

term useful lives and should correspondingly be matched with very long-7

term maturity financing instruments. 8

9

While long-term Treasury bonds are potentially subject to interest rate 10

risk, this is only true if the bonds are sold prior to maturity. A substantial 11

fraction of bond market participants, usually institutional investors with 12

long-term liabilities (pension funds, insurance companies), in fact hold 13

bonds until they mature, and therefore are not subject to interest rate risk. 14

Moreover, institutional bondholders neutralize the impact of interest rate 15

changes by matching the maturity of a bond portfolio with the investment 16

planning period, or by engaging in hedging transactions in the financial 17

futures markets. The merits and mechanics of such immunization 18

strategies are well documented by both academicians and practitioners. 19

20

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Another reason for utilizing the longest maturity Treasury bond possible is 1

that common equity has an infinite life span, and the inflation expectations 2

embodied in its market-required rate of return will therefore be equal to 3

the inflation rate anticipated to prevail over the very long-term. The same 4

expectation should be embodied in the risk free rate used in applying the 5

CAPM model. It stands to reason that the actual yields on 30-year 6

Treasury bonds will more closely incorporate within their yield the 7

inflation expectations that influence the prices of common stocks than do 8

short-term or intermediate-term U.S. Treasury notes. 9

10

Q. Dr. Morin, are there other reasons why you reject short-term interest 11

rates as a proxies for the risk-free rate in implementing the CAPM? 12

A. Yes. Short-term rates are volatile, fluctuate widely, and are subject to 13

more random disturbances than are long-term rates. Short-term rates are 14

largely administered rates. For example, as was seen recently in an 15

attempt to combat the weak economy, Treasury bills are used by the 16

Federal Reserve as a policy vehicle to stimulate the economy and to 17

control the money supply, and are used by foreign governments, 18

companies, and individuals as a temporary safe-house for money. 19

20

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As a practical matter, it makes no sense to match the return on common 1

stock to the yield on 90-day Treasury Bills. This is because short-term 2

rates, such as the yield on 90-day Treasury Bills, fluctuate widely, leading 3

to volatile and unreliable equity return estimates. 4

5

As a conceptual matter, short-term Treasury Bill yields reflect the impact 6

of factors different from those influencing the yields on long-term 7

securities such as common stock. For example, the premium for expected 8

inflation embedded into 90-day Treasury Bills is likely to be far different 9

than the inflationary premium embedded into long-term securities yields. 10

On grounds of stability and consistency, the yields on long-term Treasury 11

bonds match more closely with common stock returns. 12

13

Q. Dr. Morin, are you aware that the commission has in the past relied 14

on an average of 10-year and 30-year treasury bond yields over a 15

three-month period as a proxy for the risk-free rate in the CAPM? 16

A. Yes, I am. 17

18

Q. Do you agree with this procedure? 19

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A. Not quite, for two reasons. First, yield estimates computed over a three-1

month period are stale. I discussed this issue earlier. Second, only the 2

yields on 30-year bonds are relevant proxies in the CAPM. 3

4

The Commission’s rationale for effectively assigning equal weight to both 5

the 10-year and 30-year bond yield is that some investors may have a 10-6

year investment horizon. The expected common stock return is based on 7

very long-term cash flows, regardless of an investor's holding time period. 8

This is fundamentally different than an investor’s expected return on a 9

debt security which is, in part, depended upon the amount of time that 10

investor chooses to loan money to a borrower. Thus, in contrast to a debt 11

investor, an equity investor will require a return that reflects the risk of the 12

stock, irrespective of holding period, whether it is one month, ten years, 13

thirty years, or fifty years. It is a well known fact that the DCF model is 14

insensitive to holding period because it is based on a uniform discount of 15

expected future cash flows. The latter point is formally demonstrated in 16

Chapter 8 of my latest book, The New Regulatory Finance. The important 17

point is that common stock is a very long-term investment, and 18

accordingly, the yield on the longest-term possible government bonds is 19

the best proxy for the risk-free rate for use in the CAPM. Because utility 20

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asset investments have very long-term useful lives, they should be 1

matched with very long-term financing instruments. 2

3

Q. Dr. Morin, if one were to rely on an average of 10-year and 30-year 4

treasury bond yields over a three-month period as a proxy for the 5

risk-free rate in the CAPM, what would that estimate be? 6

A. The average risk-free rate would be 3.9% using the procedure on which 7

the Commission has relied upon in the past. This estimate compares with 8

the current yield of 4.7% on 30-year Treasury Bonds, and is clearly stale 9

and unrepresentative of current capital market conditions. 10

11

Q. How did you select the beta for your CAPM analysis? 12

A. A major thrust of modern financial theory as embodied in the CAPM is 13

that perfectly diversified investors can eliminate the company-specific 14

component of risk, and that only market risk remains. The latter is 15

technically known as “beta”, or “systematic risk”. The beta coefficient 16

measures change in a security's return relative to that of the market. The 17

beta coefficient states the extent and direction of movement in the rate of 18

return on a stock relative to the movement in the rate of return on the 19

market as a whole. The beta coefficient indicates the change in the rate of 20

return on a stock associated with a one percentage point change in the rate 21

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of return on the market, and thus measures the degree to which a particular 1

stock shares the risk of the market as a whole. Modern financial theory 2

has established that beta incorporates several economic characteristics of a 3

corporation that are reflected in investors' return requirements. 4

5

Niagara Mohawk is not publicly traded and, therefore, proxies must be 6

used for Niagara Mohawk. In the earlier discussion of DCF estimates, I 7

developed two samples of comparable companies. As shown on Exhibit 8

__ (RAM-11) and Exhibit __ (RAM-12), the average beta for the 9

combination gas and electric group and the S&P Electric Utility Index 10

group are 0.72 and 0.75, respectively. Removing the companies with less 11

than the majority of their revenues from regulated electric operations, the 12

average beta is 0.74. 13

14

Based on these results, I shall use the average beta of the two groups, 0.74, 15

as an estimate for the beta applicable to the electric utility industry 16

business. It is important to note that betas are estimated on five-year 17

historical periods and, therefore, do not fully capture the increase in 18

capital costs that have occurred since the commencement of the financial 19

crisis in October 2008. 20

21

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Q. What MRP estimate did you use in your capm analysis? 1

A. For the MRP, I used 6.5%. This estimate was based on the results of 2

historical studies of long-term risk premiums, and on the general findings 3

of the academic literature on the subject. First, the Morningstar (formerly 4

Ibbotson Associates) study, Stocks, Bonds, Bills, and Inflation, 2009 5

Yearbook, compiling historical returns from 1926 to 2008, shows that a 6

broad market sample of common stocks outperformed long-term U. S. 7

Treasury bonds by 5.6%. The historical MRP over the income component 8

of long-term Treasury bonds rather than over the total return is 6.5%. 9

Morningstar recommends the use of the latter as a more reliable estimate 10

of the historical MRP, and I concur with this viewpoint. The historical 11

MRP should be computed using the income component of bond returns 12

because the intent, even using historical data, is to identify an expected 13

MRP. This is because the income component of total bond return (i.e., the 14

coupon rate) is a far better estimate of expected return than the total return 15

(i.e., the coupon rate + capital gain), as realized capital gains/losses are 16

largely unanticipated by bond investors. The long-horizon (1926-2008) 17

MRP (based on income returns, as required) is specifically calculated to be 18

6.5% rather than 5.6%. 19

20

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Q. On what maturity bond does the Morningstar historical risk premium 1

data rely? 2

A. Because 30-year bonds were not always traded or even available 3

throughout the entire 1926-2008 period covered in the Morningstar Study 4

of historical returns, the latter study relied on bond return data based on 5

20-year Treasury bonds. Because the yield curve is virtually flat above 6

maturities of 20 years over most of the period covered in the Morningstar 7

study, the difference in yield is not material. 8

9

Q. Why did you use long time periods in arriving at your historical MRP 10

estimate? 11

A. Because realized returns can be substantially different from prospective 12

returns anticipated by investors when measured over short time periods, it 13

is important to employ returns realized over long time periods rather than 14

returns realized over more recent time periods when estimating the MRP 15

with historical returns. Therefore, a risk premium study should consider 16

the longest possible period for which data are available. Short-run periods 17

during which investors earned a lower risk premium than they expected 18

are offset by short-run periods during which investors earned a higher risk 19

premium than they expected. Only over long time periods will investor 20

return expectations and realizations converge. 21

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I have therefore ignored realized risk premiums measured over short time 1

periods. Instead, I relied on results over periods of enough length to 2

smooth out short-term aberrations, and to encompass several business and 3

interest rate cycles. The use of the entire study period in estimating the 4

appropriate MRP minimizes subjective judgment and encompasses many 5

diverse regimes of inflation, interest rate cycles, and economic cycles. 6

7

To the extent that the estimated historical equity risk premium follows 8

what is known in statistics as a random walk, one should expect the equity 9

risk premium to remain at its historical mean. Since I found no evidence 10

that the MRP in common stocks has changed over time, that is, no 11

significant serial correlation in the Morningstar study, it is reasonable to 12

assume that these quantities will remain stable in the future. 13

14

Q. Did you base your MRP estimate on any other source? 15

A. Yes, I did. I examined a 2003 comprehensive article published in 16

Financial Management, Harris, Marston, Mishra, and O’Brien (HMMO) 17

that provides estimates of the ex ante expected returns for S&P 500 18

companies over the period 1983-19981. HMMO measure the expected 19

1 Harris, R. S., Marston, F. C., Mishra, D. R., and O’Brien, T. J., “Ex Ante Cost of Equity Estimates of S&P 500 Firms: The Choice Between Global and Domestic CAPM,” Fin’l Mgt., Fall 2003, pp. 51-66.

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rate of return (cost of equity) of each dividend-paying stock in the S&P 1

500 for each month from January 1983 to August 1998 by using the 2

constant growth DCF model. The prevailing risk-free rate for each year 3

was then subtracted from the expected rate of return for the overall market 4

to arrive at the MRP for that year. The average MRP estimate for the 5

overall period is 7.2%, which is reasonably close to the historical estimate 6

of 6.5% and almost identical to the historical estimate of 7.1% if the 7

disastrous performance of the capital markets during 2008 is excluded 8

from the historical average. 9

10

Q. Dr. Morin, is your MRP estimate of 6.5% consistent with the 11

academic literature on the subject? 12

A. Yes, it is. In their authoritative corporate finance textbook, Professors 13

Brealey, Myers, and Allen2 conclude from their review of the fertile 14

literature on the MRP that a range of 5% to 8% is reasonable for the MRP 15

in the United States. My own survey of the MRP literature, which appears 16

in Chapter 5 of my latest textbook, The New Regulatory Finance, is also 17

quite consistent with this range. Moreover, I deem my MRP estimate of 18

2 Richard A. Brealey, Stewart C. Myers, and Paul Allen, Principles of Corporate Finance,

8th Edition, Irwin McGraw-Hill, 2006.

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6.5% conservative, given the unsettled conditions in the equity market 1

following the financial crisis that commenced in 2008. 2

3

Q. Are you familiar with the methodology for determining the MRP 4

component of the CAPM used by the commission in recent cases? 5

A. Yes, I am. In the past, the Commission has relied on Merrill Lynch’s 6

estimate of the MRP, which has generally been in the 7% - 9% range. 7

This range is higher than historical estimates as a result of the financial 8

crisis that began in October 2008. If we were to duplicate the 9

Commission’s approach of specifying the MRP, that estimate would be 10

8%, that is, the current Merrill Lynch forecast market return of 11.95% 11

minus the Commission risk-free rate proxy of 3.9%. I anticipate a 12

reversion to historical MRP levels as the financial crisis subsides, and 13

view my own estimate as very conservative at this time. 14

15

Q. What is your risk premium estimate of the Company’s cost of equity 16

using the CAPM approach? 17

A. Inserting those input values in the CAPM equation, namely a risk-free rate 18

of 4.7%, a beta of 0.74, and a MRP 6.5%, the CAPM estimate of the cost 19

of common equity is: 4.7% + 0.74 x 6.5% = 9.5%. This estimate 20

becomes 9.8% with flotation costs, discussed later in my testimony. 21

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Q. What is your risk premium estimate using the empirical version of the 1

CAPM? 2

A. With respect to the empirical validity of the plain vanilla CAPM, there 3

have been numerous empirical tests of the CAPM to determine to what 4

extent security returns and betas are related in the manner predicted by the 5

CAPM. This literature is summarized in Chapter 6 of my latest book, The 6

New Regulatory Finance, published by Public Utilities Report Inc. The 7

results of the tests support the idea that beta is related to security returns, 8

that the risk-return tradeoff is positive, and that the relationship is linear. 9

The contradictory finding is that the risk-return tradeoff is not as steeply 10

sloped as the CAPM would predict. That is, empirical research has long 11

shown that low-beta securities earn returns somewhat higher than the 12

CAPM would predict, and high-beta securities earn less than predicted. 13

14

A CAPM-based estimate of cost of capital underestimates the return 15

required from low-beta securities and overstates the return required from 16

high-beta securities, based on the empirical evidence. This is one of the 17

most well-known results in finance, and it is displayed graphically below. 18

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1

A number of variations on the original CAPM theory have been 2

proposed to explain this finding. The ECAPM makes use of these 3

empirical findings. The ECAPM estimates the cost of capital with the 4

equation: 5

K = RF + α + β x ( M R P - α ) 6

where the symbol alpha, α , represents the “constant” of the risk-return 7

line, MRP is the market risk premium (RM – RF), and the other symbols 8

are defined as usual. 9

10

Inserting the long-term risk-free rate as a proxy for the risk-free rate, an 11

alpha in the range of 1% - 2%, and reasonable values of beta and the 12

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MRP in the above equation produces results that are indistinguishable 1

from the following more tractable ECAPM expression: 2

K = RF + 0.25 (RM - RF) + 0.75 β (RM - RF) 3

4

An alpha range of 1% - 2% is somewhat lower than that estimated 5

empirically. The use of a lower value for alpha leads to a lower 6

estimate of the cost of capital for low-beta stocks such as regulated 7

utilities. This is because the use of a long-term risk-free rate rather than 8

a short-term risk-free rate already incorporates some of the desired effect 9

of using the ECAPM. In other words, the long-term risk-free rate 10

version of the CAPM has a higher intercept and a flatter slope than the 11

short-term risk-free version that has been tested. This is also because 12

the use of adjusted betas rather than the use of raw betas also 13

incorporates some of the desired effect of using the ECAPM3. Thus, it 14

is reasonable to apply a conservative alpha adjustment. 15

16

3 The regression tendency of betas to converge to 1.0 over time is very well known and widely

discussed in the financial literature. As a result of this beta drift, several commercial beta producers adjust their forecasted betas toward 1.00 in an effort to improve their forecasts. Value Line, Bloomberg, and Merrill Lynch betas are adjusted for their long-term tendency to regress toward 1.0 by giving approximately 66% weight to the measured raw beta and approximately 33% weight to the prior value of 1.0 for each stock:

βadjusted = 0.33 + 0.66 βraw

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Appendix A contains a full discussion of the ECAPM, including its 1

theoretical and empirical underpinnings. In short, the following equation 2

provides a viable approximation to the observed relationship between risk 3

and return, and provides the following cost of equity capital estimate: 4

K = RF + 0.25 (RM - RF) + 0.75 β (RM - RF) 5

6

Inserting 4.7% for the risk-free rate RF, an MRP of 6.5% for (RM - RF) and 7

a beta of 0.74 in the above equation, the return on common equity is 9.9%. 8

This estimate becomes 10.2% with flotation costs, discussed later in my 9

testimony. 10

11

Q. Please summarize your CAPM estimates. 12

A. The table below summarizes the common equity estimates obtained from 13

the CAPM studies. 14

CAPM Method % ROE Traditional CAPM 9.8% Empirical CAPM 10.2%

15

Q. How do your CAPM estimates compare with those derived from the 16

Commission’s approach? 17

A. Using the Commission’s approach to estimating the risk-free rate 18

component (3.9%) and MRP component (8%) of the CAPM/ECAPM, the 19

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estimates would be 9.9% and 10.4% without flotation costs, coincidentally 1

almost identical to my own estimates of 9.8% and 10.2%. 2

3

C. Historical Risk Premium Estimate 4

Q. What is currently happening in the debt and equity markets? 5

A. Since the financial crisis began in 2008, the financial markets, both in the 6

U.S. and abroad, have become extremely volatile, unpredictable, and have 7

displayed unusual behavior. In light of a fundamental structural upward 8

shift in risk aversion as capital markets are re-pricing risk, equity capital 9

has become, and will continue to be, more expensive for all market 10

participants, including utilities, relative to government bond yields. 11

12

Q. Dr. Morin, given the current state of the capital markets at this time, 13

is a historical risk premium analysis using government bond yields 14

appropriate? 15

A. No, I do not believe it is. Trends in utility cost of capital are not directly 16

captured by a risk premium estimate tied to government bond yields. 17

Because a utility’s cost of capital is determined by its business and financial 18

risks, it is reasonable to surmise that its cost of equity will track its cost of 19

debt more closely than it will track the government bond yield. Therefore, 20

in contrast to past testimonies prior to the financial crisis, I have performed a 21

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historical premium analysis using the utility bond yield instead of the 1

government bond yield. 2

3

Q. Please describe your historical risk premium analysis of the electric 4

utility industry using utility bond yields. 5

A. A historical risk premium for the electric utility industry was estimated 6

with an annual time series analysis applied to the utility industry as a 7

whole over the 1930-2007 period, using Standard and Poor’s Utility Index 8

as an industry proxy. The analysis is depicted on Exhibit __ (RAM-13). 9

The risk premium was estimated by computing the actual realized return 10

on equity capital for the S&P Utility Index for each year, using the actual 11

stock prices and dividends of the index, and then subtracting the long-term 12

utility bond return for that year. As the average Moody’s bond rating in 13

the electric utility industry is Baa, the analysis was performed using the 14

yields on utility bonds rated Baa by Moody’s. 15

16

As shown on Exhibit __ (RAM-13), the average risk premium over the 17

period was 4.1% over historical long-term utility bond returns and 4.5% 18

over long-term utility bond yields. Given that the current yield on Baa-19

rated utility bonds is 6.6%, and using the historical estimate of 4.1%, the 20

implied cost of equity for the average risk utility from this particular 21

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method is 6.6% + 4.1% = 10.7% without flotation costs and 11.0% with 1

the flotation cost allowance. The need for a flotation cost allowance is 2

discussed at length later in my testimony. 3

4

Q. Dr. Morin, are risk premium studies widely used? 5

A. Yes, they are. Although the Commission has not relied on this approach 6

in the past, risk premium analyses of the type I am describing here are 7

widely used by analysts, investors, economists, and expert witnesses. Most 8

college-level corporate finance and/or investment management texts, 9

including Investments by Bodie, Kane, and Marcus, McGraw-Hill Irwin, 10

2002, which is a recommended textbook for Chartered Financial Analyst 11

certification and examination, contain detailed conceptual and empirical 12

discussion of the risk premium approach. The latter is typically 13

recommended as one of the three leading methods of estimating the cost of 14

capital. Professor Brigham’s best-selling corporate finance textbook, for 15

example, Corporate Finance: A Focused Approach, 3rd ed., South-16

Western, 2008, recommends the use of risk premium studies, among 17

others. Techniques of risk premium analysis are widespread in investment 18

community reports. Professional certified financial analysts are certainly 19

well versed in the use of this method. 20

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Q. Are you concerned about the realism of the assumptions that underlie 1

the historical risk premium method? 2

A. No, I am not, for they are no more restrictive than the assumptions that 3

underlie the DCF model or the CAPM. While it is true that the method 4

looks backward in time and assumes that the risk premium is constant over 5

time, these assumptions are not necessarily restrictive. By employing 6

returns realized over long time periods rather than returns realized over 7

more recent time periods, investor return expectations and realizations 8

converge. Realized returns can be substantially different from prospective 9

returns anticipated by investors, especially when measured over short time 10

periods. By ensuring that the risk premium study encompasses the longest 11

possible period for which data are available, short-run periods during 12

which investors earned a lower risk premium than they expected are offset 13

by short-run periods during which investors earned a higher risk premium 14

than they expected. Only over long time periods will investor return 15

expectations and realizations converge; otherwise, investors would never 16

invest any money. 17

18

Q Dr. Morin, the Commission has criticized the historical risk premium 19

approach in recent cases. How do you respond? 20

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A. The Commission has stated in the past that the historical risk premium 1

approach is inappropriate because New York electric utilities may be more 2

or less risky than the companies that make up the S&P Electric Utility Index 3

over the 1926-2006 period. I disagree. Over most of the long period that 4

covers my historical risk premium study, 1926-2007, the electric utility was 5

relatively homogenous in risk and under the umbrella of regulatory 6

protection for all of its functions (power generation, transmission, 7

distribution). 8

9

The Commission also critiqued the risk premium method on the grounds 10

that the method assumes that the risk premium is constant over time, that 11

is, that the risk premium has remained at the same level relative to the 12

risks of the electric utility stocks. This criticism is unwarranted. To the 13

extent that the historical equity risk premium estimated follows what is 14

known in statistics as a random walk, one should expect the equity risk 15

premium to remain at its historical mean. The best estimate of the future 16

risk premium is the historical mean. This approach is no different than 17

using long term historical earning results to calculate the market risk 18

premium used in the CAPM analyses. 19

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As discussed earlier, the Risk Premium approach is conceptually sound and 1

firmly rooted in the conceptual framework of Capital Market Theory. It is 2

widely used by analysts, investors, and expert witnesses. 3

4

D. Flotation Cost Adjustment 5

Q. Please describe the need for a flotation cost allowance. 6

A. All the market-based estimates reported above include an adjustment for 7

flotation costs. Common equity capital is not free, and flotation costs 8

associated with stock issues are similar to the flotation costs associated 9

with bonds and preferred stocks. Flotation costs are not expensed at the 10

time of issue, and therefore must be recovered via a rate of return 11

adjustment. This is done routinely for bond and preferred stock issues by 12

most regulatory boards, including the Commission. Clearly, the common 13

equity capital accumulated by the Company is not cost-free. The flotation 14

cost allowance to the cost of common equity capital is discussed and 15

applied in most corporate finance textbooks; it is unreasonable to ignore 16

the need for such an adjustment. 17

18

Flotation costs are very similar to the closing costs on a home mortgage. 19

In the case of issues of new equity, flotation costs represent the discounts 20

that must be provided to place the new securities. Flotation costs have a 21

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direct and an indirect component. The direct component is the 1

compensation to the security underwriter for marketing/consulting 2

services, for the risks involved in distributing the issue, and for any 3

operating expenses associated with the issue (printing, legal, prospectus, 4

etc.). The indirect component represents the downward pressure on the 5

stock price as a result of the increased supply of stock from the new issue. 6

The latter component is frequently referred to as “market pressure.” 7

8

Investors must be compensated for flotation costs on an ongoing basis to 9

the extent that such costs have not been expensed in the past, and therefore 10

the adjustment must continue for the entire time that these initial funds are 11

retained in the firm. Appendix B discusses flotation costs in detail, and 12

shows: (1) why it is necessary to apply an allowance of 5% to the dividend 13

yield component of equity cost by dividing that yield by 0.95 (100% - 5%) 14

to obtain the fair return on equity capital; (2) why the flotation adjustment 15

is permanently required to avoid confiscation even if no further stock 16

issues are contemplated; and (3) that flotation costs are only recovered if 17

the rate of return is applied to total equity, including retained earnings, in 18

all future years. 19

20

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Q. Would you provide an example to illustrate the flotation cost 1

allowance concept? 2

A. Yes. Assume a stock is sold for $100, and investors require a 10% return, 3

that is, $10 of earnings. But if flotation costs are 5%, the Company nets 4

$95 from the issue, and its common equity account is credited by $95. In 5

order to generate the same $10 of earnings to the shareholders, from a 6

reduced equity base, it is clear that a return in excess of 10% must be 7

allowed on this reduced equity base, here 10.52%. 8

9

According to the empirical finance literature discussed in Appendix B, 10

total flotation costs amount to 4% for the direct component and 1% for the 11

market pressure component, for a total of 5% of gross proceeds. This in 12

turn amounts to approximately 30 basis points, depending on the 13

magnitude of the dividend yield component. To illustrate, dividing the 14

average expected dividend yield of around 5.0% for utility stocks by 0.95 15

yields 5.3%, which is 30 basis points higher. 16

17

Sometimes, the argument is made that flotation costs are real and should 18

be recognized in calculating the fair return on equity, but only at the time 19

when the expenses are incurred. In other words, the flotation cost 20

allowance should not continue indefinitely, but should be made in the year 21

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in which the sale of securities occurs, with no need for continuing 1

compensation in future years. This argument is valid only if the Company 2

has already been compensated for these costs. If not, the argument is 3

without merit. My own recommendation is that investors be compensated 4

for flotation costs on an on-going basis rather than through expensing, and 5

that the flotation cost adjustment continue for the entire time that these 6

initial funds are retained in the firm. 7

8

There are several sources of equity capital available to a firm including: 9

common equity issues, conversions of convertible preferred stock, 10

dividend reinvestment plan, employees’ savings plan, warrants, and stock 11

dividend programs. Each carries its own set of administrative costs and 12

flotation cost components, including discounts, commissions, corporate 13

expenses, offering spread, and market pressure. The flotation cost 14

allowance is a composite factor that reflects the historical mix of sources 15

of equity. The allowance factor is a build-up of historical flotation cost 16

adjustments associated and traceable to each component of equity at its 17

source. It is impractical and prohibitively costly to start from the 18

inception of a company and determine the source of all present equity. A 19

practical solution is to identify general categories and assign one factor to 20

each category. My recommended flotation cost allowance is a weighted 21

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average cost factor designed to capture the average cost of various equity 1

vintages and types of equity capital raised by the Company. 2

3

Q. Is a flotation cost adjustment required for an operating subsidiary 4

like Niagara Mohawk that does not trade publicly? 5

A. Yes, it is. It is sometimes alleged that a flotation cost allowance is 6

inappropriate if the utility is a subsidiary whose equity capital is obtained 7

from its ultimate parent, in this case, National Grid. This objection is 8

unfounded since the parent-subsidiary relationship does not eliminate the 9

costs of a new issue, but merely transfers them to the parent. It would be 10

unfair and discriminatory to subject parent shareholders to dilution while 11

individual shareholders are absolved from such dilution. Fair treatment 12

must consider that, if the utility-subsidiary had gone to the capital markets 13

directly, flotation costs would have been incurred. 14

15

Q. What flotation cost treatment does the Commission rely upon? 16

A. The Commission has only provided for recovery of flotation costs when a 17

public common issuance is planned during the rate year. The standard 18

flotation cost allowance used in my direct testimony is designed to recover 19

the flotation costs associated with all past issues that were not expensed, 20

but rather written off against common equity. 21

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By analogy, in the case of a debt issue, flotation costs are amortized over 1

the life of the debt, and the annual amortization charge usually is 2

embedded in the cost of debt for ratemaking purposes. This is done 3

whether the company intends to issue debt in the future or not. The 4

recovery of debt flotation expense continues year after year irrespective of 5

whether the company issues new debt capital until recovery is complete, in 6

the same way that the recovery of past investments in plant and equipment 7

through depreciation allowances continues in the future even if no new 8

construction is contemplated. Unlike the case of bonds, common stock 9

has no finite life so that flotation costs cannot be amortized and must 10

therefore be recovered via an upward adjustment to the allowed return on 11

equity. As in the case of bonds, the recovery continues year after year 12

regardless of whether the utility raises new equity capital until the 13

recovery process is terminated. 14

15

To the extent that Niagara Mohawk’s flotation costs associated with past 16

common equity issues have not been recovered, the only recovery 17

mechanism available for the recovery of such costs is an upward 18

adjustment to the return on equity. 19

20

21

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IV. Summary and Cost of Equity Recommendation 1

Q. Can you summarize your results and recommendation? 2

A. To arrive at my final recommendation, I performed three risk premium 3

analyses. For the first two risk premium studies, I applied the CAPM and 4

an empirical approximation of the CAPM using current market data. The 5

other risk premium analysis was performed on historical data from electric 6

utility industry aggregate data, using the yield on long-term utility bonds. 7

I also performed DCF analyses on two surrogates for Niagara Mohawk: a 8

group of investment-grade dividend-paying combination electric and gas 9

utilities, and a group of electric utilities that make up the S&P Utility 10

Index. The results are summarized in the table below. 11

12

STUDY ROE 13 CAPM 9.80% Empirical CAPM 10.20% Hist. Risk Premium Elec Utility Industry 11.00% DCF Comb. Elec & Gas Utilities Value Line Growth 11.80% DCF Comb. Elec & Gas Utilities Zacks Growth 10.90% DCF S&P Elec Utilities Value Line Growth 10.60% DCF S&P Elec Utilities Zacks Growth 11.60%

14

The results range from 9.8% to 11.8% with a midpoint of 10.8%. The 15

overall average result is 10.8% and the truncated mean is 10.9%. From 16

these results, I conclude that a ROE of 10.85% is reasonable. 17

18

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Q. Dr. Morin, if you were to rely on weighting of 2/3 for the DCF results 1

and 1/3 for the CAPM results, what would be Niagara Mohawk’s cost 2

of common equity estimate? 3

A. From the above table, the average CAPM result is 10.0%. The average 4

DCF result is 11.2%. Giving one-third weight to the CAPM result of 5

10.0% and two-thirds weight to the DCF result of 11.2%, the weighted 6

average result is 10.82%, which is almost identical to the average result 7

reported in the above summary table. 8

9

Q. Did you adjust your proxy group cost of equity results to reflect the 10

risk differential between the proxy group and the Company? 11

A. No, I did not. The Company’s investment risk is average in my view. 12

13

Because the cost of equity estimates derived from the various comparable 14

groups reflect the risk of the average investment grade utility and because 15

Niagara Mohawk’s investment risks are broadly comparable to those of 16

the industry, the expected equity returns developed above are applicable to 17

Niagara Mohawk. 18

19

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Q. Did you consider the impact of the Company’s proposal to implement 1

a revenue decoupling mechanism (RDM) on the Company’s cost of 2

equity? 3

A. No, I did not. Any risk-mitigating impact such mechanisms may have on 4

the Company’s risk profile is largely reflected in the capital market data of 5

the comparable companies. RDMs or similar margin adjustment 6

mechanisms are becoming increasingly commonplace in the energy utility 7

industry. A number of electric companies in my comparable groups 8

possess some form of revenue decoupling and/or similar margin 9

adjustment rider mechanism. At the same time, revenue decoupling, 10

depending on how it is implemented, might not reduce risk for certain 11

companies in my comparable group that do not have such mechanisms and 12

serve growing markets. Such utilities depend on increases in revenue to 13

offset increases in cost of service and this may be less risky without a 14

RDM. For all these reasons, it is unnecessary to account for the impact a 15

RDM has on the Company’s ROE. 16

17

Q. Did you include a return adjustment to your results to account for any 18

credit rating differential between the proxy group and the Company? 19

A. No, I did not. This is because credit ratings and debt rate differentials are 20

not directly related to required equity returns. As shown on the graph 21

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below, there is no correlation between the DCF results for the companies 1

in my two sample groups and the bond ratings of these companies. 2

3

4

Moreover, the table below displays the DCF results for each bond rating 5

category. There is no positive relationship between return and declining 6

credit quality for these companies, which are all investment grade. I also 7

point out that there is no correlation between equity risk as measured by 8

beta and the credit ratings of the companies in the two sample groups as 9

evidenced by the data in the last column in the table below. 10

Bond DCF Beta Rating Estimates Estimates Aa3 10.87% 0.65

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A2 11.69% 0.70 A3 10.70% 0.60 Baa1 10.31% 0.71 Baa2 10.67% 0.70 Baa3 10.22% 0.76

1

Q. Why isn’t it logical to assume that an entity with a higher credit 2

rating and therefore a lower cost of debt will not have a lower cost of 3

equity as well? 4

A. The primary reason is that credit ratings are intended to reflect an estimate 5

of the likelihood that a company will fulfill its debt obligations. Such 6

ratings do not attempt to estimate the likelihood of whether an equity 7

investor will realize the appropriate return on equity. Moreover, for 8

companies that are considered investment grade, as an entity takes steps to 9

increase its credit quality, it may create additional risks for equity 10

investors. For example, one of the actions that a company can undertake 11

in order to increase credit quality is to reduce the amount of debt as a 12

percentage of its total capital. However, as long term debt becomes less 13

risky, it is quite possible that a further equity investment becomes 14

somewhat riskier. My point here is not that an entity with better credit 15

quality will experience an increase in the cost of equity, but that there is 16

no evidence that improvements in credit quality necessarily reduce the 17

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cost of equity for investment grade utilities. Thus, it is inappropriate to 1

apply a credit quality adjustment to the cost of equity results in this case. 2

3

Q. Dr. Morin, do you consider your recommendation conservative? 4

A. Yes, I do. Yields on 20-year Treasury bonds are projected to increase by 5

50 basis points (0.5%) by December 2010. Value Line’s Quarterly 6

Economic Review dated August 2009 also projects the yields on 10-year 7

Treasury bonds to increase by 50 basis points in 2010. Because long-term 8

interest rates generally move in unison, an increase (decrease) in the yield 9

on 10/20-year Treasury bonds should be accompanied by a parallel 10

increase (decrease) in the yield on 30-year bonds. A projected increase in 11

interest rates, if materialized, would clearly increase my CAPM and Risk 12

Premium estimates, and therefore ROE. I therefore view my ROE 13

recommendation as conservative. 14

15

Q. Dr. Morin, what capital structure assumption underlies your 16

recommended ROE for Niagara Mohawk? 17

A. My recommended ROE for Niagara Mohawk is predicated on the adoption 18

of a rate year capital structure consisting of 50% common equity capital. 19

. 20

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Q. Did you examine the reasonableness of the Company’s capital 1

structure? 2

A. Yes, I did. I have compared Niagara Mohawk’s rate year capital structure 3

with: 1) the capital structures adopted by regulators for electric utilities, 4

and 2) the actual capital structures of electric utilities. 5

6

The October 2009 edition of SNL Energy’s (formerly Regulatory 7

Research Associates) “Regulatory Focus: Major Rate Case Decisions” 8

reports an average percentage of common equity in the adopted capital 9

structure of 48.4% for electric utilities for 2008 and 48% for 2009, which 10

is quite close to the Company’s proposed common equity ratio in this 11

case. I have also examined the actual capital structures of my comparable 12

group of combination electric and as utilities as reported by Value Line. 13

As shown on Exhibit __ (RAM-14), the average common equity ratio for 14

the group is 47%, which is very close to the Company’s proposal. I 15

conclude that the Company’s requested common equity ratio is reasonable 16

for ratemaking purposes. 17

18

Q. Dr. Morin, what is your final conclusion regarding Niagara 19

Mohawk’s cost of common equity capital? 20

A. Based on the results of all my analyses, the application of my professional 21

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judgment, and the risk circumstances of Niagara Mohawk, it is my opinion 1

that a just and reasonable return on the common equity capital of Niagara 2

Mohawk’s electric utility operations is 10.85%. My recommended rate of 3

return reflects the application of my professional judgment to the results in 4

light of the indicated returns from my Risk Premium, CAPM, and DCF 5

analyses. My recommended ROE assumes the approval of the Company’s 6

rate year capital structure. 7

8

Q. Would you now discuss the implications for the allowed ROE of a 9

stayout for Niagara Mohawk? 10

A. The Company has informed me that it is proposing a three-year rate plan. 11

This exposes Niagara Mohawk to the risk that the cost of equity may go 12

up during the course of the rate plan, without the Company having an 13

opportunity to reset the allowed return to reflect such an increase. I am 14

informed that in the past, the Commission has used the differential 15

between 3-year and 1-year Treasury securities to provide guidance as to 16

what the “stayout premium” in such circumstances should be. More 17

specifically, I am informed that the Commission has used one-half of the 18

five-year average differentials between (1) a Treasury security reflecting 19

the length of the rate plan and (2) a 1-year Treasury security. The five-20

year average differential, through the end of October 2009, between 3-year 21

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and 1-year Treasury securities is approximately 50 basis points, excluding 1

those months where the differential was negative, that is, when the yield 2

curve was negative. Half of this differential is about 25 basis points. Thus, 3

a stayout premium in the neighborhood of 25 basis points would be 4

reasonable for Niagara Mohawk, and that brings my recommended ROE 5

to 11.1%. 6

7

Q. Finally, Dr. Morin, if capital market conditions change significantly 8

between the date of filing your prepared testimony and the date your 9

oral testimony is presented, would this cause you to revise your 10

estimated cost of equity? 11

A. Yes. Interest rates and security prices do change over time, and risk 12

premiums change also, although much more sluggishly. If substantial 13

changes were to occur between the filing date and the time my oral 14

testimony is presented, I will update my testimony accordingly. 15

16

Q. Does this complete your direct testimony? 17

A. Yes, it does.18

78

Appendix A Page 1 of 16

APPENDIX A

CAPM, EMPIRICAL CAPM

The Capital Asset Pricing Model (CAPM) is a fundamental paradigm of finance.

Simply put, the fundamental idea underlying the CAPM is that risk-averse investors

demand higher returns for assuming additional risk, and higher-risk securities are priced

to yield higher expected returns than lower-risk securities. The CAPM quantifies the

additional return, or risk premium, required for bearing incremental risk. It provides a

formal risk-return relationship anchored on the basic idea that only market risk matters,

as measured by beta. According to the CAPM, securities are priced such that their:

EXPECTED RETURN = RISK-FREE RATE + RISK PREMIUM

Denoting the risk-free rate by RF and the return on the market as a whole by RM,

the CAPM is:

K = RF + β(RM - RF) (1)

Equation 1 is the CAPM expression which asserts that an investor expects to earn

a return, K, that could be gained on a risk-free investment, RF, plus a risk premium for

assuming risk, proportional to the security's market risk, also known as beta, β, and the

market risk premium, (RM - RF), where RM is the market return . The market risk

premium (RM - RF) can be abbreviated MRP so that the CAPM becomes:

K = RF + β x MRP (2)

The CAPM risk-return relationship is depicted in the figure below and is typically labeled

as the Security Market Line (SML) by the investment community.

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CAPM and Risk - Return in Capital Markets

TreasuryBills

CorporateBonds

AverageStock Beta Risk

Return

AverageStock

Market Risk Premium

Rf

Rf = Risk-free rate

SML

UtilityStock

A myriad empirical tests of the CAPM have shown that the risk-return tradeoff is

not as steeply sloped as that predicted by the CAPM, however. That is, low-beta

securities earn returns somewhat higher than the CAPM would predict, and high-beta

securities earn less than predicted. In other words, the CAPM tends to overstate the

actual sensitivity of the cost of capital to beta: low-beta stocks tend to have higher

returns and high-beta stocks tend to have lower risk returns than predicted by the

CAPM. The difference between the CAPM and the type of relationship observed in

the empirical studies is depicted in the figure below. This is one of the most widely

known empirical findings of the finance literature. This extensive literature is

summarized in Chapter 13 of Dr. Morin’s book [Regulatory Finance, Public Utilities

Report Inc., Arlington, VA, 1994].

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Risk vs ReturnTheory vs. Practice

Return

Risk-Free

Theory

Practice

BetaBeta = 1.0

Average Return

CAPM lower than Empirical Line forlow Beta Stocks

Beta < 1.0

Market Risk Premium

A number of refinements and expanded versions of the original CAPM theory

have been proposed to explain the empirical findings. These revised CAPMs typically

produce a risk-return relationship that is flatter than the standard CAPM prediction. The

following equation makes use of these empirical findings by flattening the slope of the

risk-return relationship and increasing the intercept:

K = RF + α + β ( M R P - α ) (3)

where α is the "alpha" of the risk-return line, a constant determined empirically, and

the other symbols are defined as before. Alternatively, Equation 3 can be written as

follows:

K = RF + a MRP + (1-a) β MRP (4)

where a is a fraction to be determined empirically. Comparing Equations 3 and 4, it is

easy to see that alpha equals ‘a’ times MRP, that is, α = a x MRP

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Theoretical Underpinnings

The obvious question becomes what would produce a risk return relationship

which is flatter than the CAPM prediction, or in other words, how do you explain the

presence of “alpha” in the above equation. The exclusion of variables aside from beta

would produce this result. Three such variables are noteworthy: dividend yield,

skewness, and hedging potential.

The dividend yield effects stem from the differential taxation on corporate

dividends and capital gains. The standard CAPM does not consider the regularity of

dividends received by investors. Utilities generally maintain high dividend payout ratios

relative to the market, and by ignoring dividend yield, the CAPM provides biased cost of

capital estimates. To the extent that dividend income is taxed at a higher rate than capital

gains, investors will require higher pre-tax returns in order to equalize the after-tax

returns provided by high-yielding stocks (e.g. utility stocks) with those of low-yielding

stocks. In other words, high-yielding stocks must offer investors higher pre-tax returns.

Even if dividends and capital gains are undifferentiated for tax purposes, there is still a

tax bias in favor of earnings retention (lower dividend payout), as capital gains taxes are

paid only when gains are realized.

Empirical studies by Litzenberger and Ramaswamy (1979) and Litzenberger et al.

(1980) find that security returns are positively related to dividend yield as well as to beta.

These results are consistent with after-tax extensions of the CAPM developed by Breenan

(1973) and Litzenberger and Ramaswamy (1979) and suggest that the relationship

between return, beta, and dividend yield should be estimated and employed to calculate

the cost of equity capital.

As far as skewness is concerned, investors are more concerned with losing money

than with total variability of return. If risk is defined as the probability of loss, it appears

more logical to measure risk as the probability of achieving a return which is below the

expected return. The traditional CAPM provides downward-biased estimates of cost of

capital to the extent that these skewness effects are significant. As shown by Kraus and

Litzenberger (1976), expected return depends on both on a stock's systematic risk (beta)

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and the systematic skewness. Empirical studies by Kraus and Litzenberger (1976),

Friend, Westerfield, and Granito (1978), and Morin (1981) found that, in addition to beta,

skewness of returns has a significant negative relationship with security returns. This

result is consistent with the skewness version of the CAPM developed by Rubinstein

(1973) and Kraus and Litzenberger (1976).

This is particularly relevant for public utilities whose future profitability is

constrained by the regulatory process on the upside and relatively unconstrained on the

downside in the face of socio-political realities of public utility regulation. The process

of regulation, by restricting the upward potential for returns and responding sluggishly on

the downward side, may impart some asymmetry to the distribution of returns, and is

more likely to result in utilities earning less, rather than more, than their cost of capital.

The traditional CAPM provides downward-biased estimates of cost of capital to the

extent that these skewness effects are significant.

As far as hedging potential is concerned, investors are exposed to another kind of

risk, namely, the risk of unfavorable shifts in the investment opportunity set. Merton

(1973) shows that investors will hold portfolios consisting of three funds: the risk-free

asset, the market portfolio, and a portfolio whose returns are perfectly negatively

correlated with the riskless asset so as to hedge against unforeseen changes in the future

risk-free rate. The higher the degree of protection offered by an asset against unforeseen

changes in interest rates, the lower the required return, and conversely. Merton argues

that low beta assets, like utility stocks, offer little protection against changes in interest

rates, and require higher returns than suggested by the standard CAPM.

Another explanation for the CAPM's inability to fully explain the process

determining security returns involves the use of an inadequate or incomplete market

index. Empirical studies to validate the CAPM invariably rely on some stock market

index as a proxy for the true market portfolio. The exclusion of several asset categories

from the definition of market index mis-specifies the CAPM and biases the results found

using only stock market data. Kolbe and Read (1983) illustrate the biases in beta

estimates which result from applying the CAPM to public utilities. Unfortunately, no

comprehensive and easily accessible data exist for several classes of assets, such as

83


mortgages and business investments, so that the exact relation between return and stock

betas predicted by the CAPM does not exist. This suggests that the empirical relationship

between returns and stock betas is best estimated empirically (ECAPM) rather than by

relying on theoretical and elegant CAPM models expanded to include missing assets

effects. In any event, stock betas may be highly correlated with the true beta measured

with the true market index.

Yet another explanation for the CAPM's inability to fully explain the observed

risk-return tradeoff involves the possibility of constraints on investor borrowing that run

counter to the assumptions of the CAPM. In response to this inadequacy, several

versions of the CAPM have been developed by researchers. One of these versions is the

so-called zero-beta, or two-factor, CAPM which provides for a risk-free return in a

market where borrowing and lending rates are divergent. If borrowing rates and lending

rates differ, or there is no risk-free borrowing or lending, or there is risk-free lending but

no risk-free borrowing, then the CAPM has the following form:

K = RZ + β(Rm - RF)

The model, christened the zero-beta model, is analogous to the standard CAPM,

but with the return on a minimum risk portfolio which is unrelated to market returns, RZ,

replacing the risk-free rate, RF. The model has been empirically tested by Black, Jensen,

and Scholes (1972), who found a flatter than predicted CAPM, consistent with the model

and other researchers' findings.

The zero-beta CAPM cannot be literally employed in cost of capital projections,

since the zero-beta portfolio is a statistical construct difficult to replicate.

Empirical Evidence

A summary of the empirical evidence on the magnitude of alpha is provided in

the table below.

84


Empirical Evidence on the Alpha Factor

Author Range of alpha Period relied

Black (1993) -3.6% to 3.6% 1931-1991

Black, Jensen and Scholes (1972) -9.61% to 12.24% 1931-1965

Fama and McBeth (1972) 4.08% to 9.36% 1935-1968

Fama and French (1992) 10.08% to 13.56% 1941-1990

Litzenberger and Ramaswamy (1979) 5.32% to 8.17%

Litzenberger, Ramaswamy and Sosin (1980) 1.63% to 5.04% 1926-1978

Pettengill, Sundaram and Mathur (1995) 4.6%

Morin (1994) 2.0% 1926-1984

Harris, Marston, Mishra, and O’Brien (2003) 2.0% 1983-1998

Given the observed magnitude of alpha, the empirical evidence indicates that the

risk-return relationship is flatter than that predicted by the CAPM. Typical of the

empirical evidence is the findings cited in Morin (1989) over the period 1926-1984

indicating that the observed expected return on a security is related to its risk by the

following equation:

K = .0829 + .0520 β

Given that the risk-free rate over the estimation period was approximately 6

percent, this relationship implies that the intercept of the risk-return relationship is higher

than the 6 percent risk-free rate, contrary to the CAPM's prediction. Given that the

average return on an average risk stock exceeded the risk-free rate by about 8.0 percent in

that period, that is, the market risk premium (RM - RF) = 8 percent, the intercept of the

observed relationship between return and beta exceeds the risk-free rate by about 2

percent, suggesting an alpha factor of 2 percent.

Most of the empirical studies cited in the above table utilize raw betas rather than

Value Line adjusted betas because the latter were not available over most of the time

85


periods covered in these studies. A study of the relationship between return and adjusted

beta is reported on Table 6-7 in Ibbotson Associates Valuation Yearbook 2001. If we

exclude the portfolio of very small cap stocks from the relationship due to significant size

effects, the relationship between the arithmetic mean return and beta for the remaining

portfolios is flatter than predicted and the intercept slightly higher than predicted by the

CAPM, as shown on the graph below. It is noteworthy that the Ibbotson study relies on

adjusted betas as stated on page 95 of the aforementioned study.

0.00 0.50 1.00 1.50 2.00

Beta

5

10

15

20

25

Ret

urn Observed

FittedCAPM

Return vs Risk 2002NYSE Stocks

CAPM vs ECAPM

Another study by Morin in May 2002 provides empirical support for the ECAPM.

All the stocks covered in the Value Line Investment Survey for Windows for which betas

and returns data were available were retained for analysis. There were nearly 2000 such

stocks. The expected return was measured as the total shareholder return (“TSR”)

reported by Value Line over the past ten years. The Value Line adjusted beta was also

retrieved from the same data base. The nearly 2000 companies for which all data were

available were ranked in ascending order of beta, from lowest to highest. In order to

palliate measurement error, the nearly 2000 securities were grouped into ten portfolios of

86


approximately 180 securities for each portfolio. The average returns and betas for each

portfolio were as follows:

It is clear from the graph below that the observed relationship between DCF

returns and Value Line adjusted betas is flatter than that predicted by the plain vanilla

CAPM. The observed intercept is higher than the prevailing risk-free rate of 5.7 percent

while the slope is less than equal to the market risk premium of 7.7 percent predicted by

the plain vanilla CAPM for that period.

0.00 0.50 1.00 1.50 2.00Beta

5

10

15

20

25

Ret

urn Observe d

Fitte dCAPM

Return vs Risk 2002NYSE Stocks

In an article published in Financial Management, Harris, Marston, Mishra, and

O’Brien (“HMMO”) estimate ex ante expected returns for S&P 500 companies over the

Portfolio # Beta Return

portfolio 1 0.41 10.87 portfolio 2 0.54 12.02 portfolio 3 0.62 13.50 portfolio 4 0.69 13.30 portfolio 5 0.77 13.39 portfolio 6 0.85 13.07 portfolio 7 0.94 13.75 portfolio 8 1.06 14.53 portfolio 9 1.19 14.78 portfolio 10 1.48 20.78

87


period 1983-19981. HMMO measure the expected rate of return (cost of equity) of each

dividend-paying stock in the S&P 500 for each month from January 1983 to August 1998

by using the constant growth DCF model. They then investigate the relation between the

risk premium (expected return over the 20-year U.S. Treasury Bond yield) estimates for

each month to equity betas as of that same month (5-year raw betas).

The table below, drawn from HMMO Table 4, displays the average estimate

prospective risk premium (Column 2) by industry and the corresponding beta estimate for

that industry, both in raw form (Column 3) and adjusted form (Column 4). The latter

were calculated with the traditional Value Line – Merrill Lynch – Bloomberg adjustment

methodology by giving 1/3 weight of to a beta estimate of 1.00 and 2/3 weight to the raw

beta estimate.

Table A-1 Risk Premium and Beta Estimates by Industry

Raw Adjusted Industry DCF Risk Premium Industry Beta Industry Beta (1) (2) (3) (4)

1 Aero 6.63 1.15 1.10 2 Autos 5.29 1.15 1.10 3 Banks 7.16 1.21 1.14 4 Beer 6.60 0.87 0.91 5 BldMat 6.84 1.27 1.18 6 Books 7.64 1.07 1.05 7 Boxes 8.39 1.04 1.03 8 BusSv 8.15 1.07 1.05 9 Chems 6.49 1.16 1.11

10 Chips 8.11 1.28 1.19 11 Clths 7.74 1.37 1.25 12 Cnstr 7.70 1.54 1.36 13 Comps 9.42 1.19 1.13 14 Drugs 8.29 0.99 0.99 15 ElcEq 6.89 1.08 1.05 16 Energy 6.29 0.88 0.92 17 Fin 8.38 1.76 1.51 18 Food 7.02 0.86 0.91 19 Fun 9.98 1.19 1.13 20 Gold 4.59 0.57 0.71 21 Hlth 10.40 1.29 1.19 22 Hsld 6.77 1.02 1.01

1 Harris, R. S., Marston, F. C., Mishra, D. R., and O’Brien, T. J., “Ex Ante Cost of Equity Estimates of S&P

500 Firms: The Choice Between Global and Domestic CAPM,” Financial Management, Autumn 2003, pp. 51-66.

88


Raw Adjusted Industry DCF Risk Premium Industry Beta Industry Beta (1) (2) (3) (4)

23 Insur 7.46 1.03 1.02 24 LabEq 7.31 1.10 1.07 25 Mach 7.32 1.20 1.13 26 Meals 7.98 1.06 1.04 27 MedEq 8.80 1.03 1.02 28 Pap 6.14 1.13 1.09 29 PerSv 9.12 0.95 0.97 30 Retail 9.27 1.12 1.08 31 Rubber 7.06 1.22 1.15 32 Ships 1.95 0.95 0.97 33 Stee 4.96 1.13 1.09 34 Telc 6.12 0.83 0.89 35 Toys 7.42 1.24 1.16 36 Trans 5.70 1.14 1.09 37 Txtls 6.52 0.95 0.97 38 Util 4.15 0.57 0.71 39 Whlsl 8.29 0.92 0.95

MEAN 7.19

The observed statistical relationship between expected return and adjusted beta is shown

in the graph below along with the CAPM prediction:

0.60 0.70 0.80 0.90 1.00 1.10 1.20 1.30 1.40 1.50 1.60

Beta

3

4

5

6

7

8

9

10

11

12

DC

F R

isk

Pre

miu

m

ObservedCAPM

DCF Risk Premium vs Beta

89


If the plain vanilla version of the CAPM is correct, then the intercept of the graph

should be zero, recalling that the vertical axis represents returns in excess of the risk-free

rate. Instead, the observed intercept is approximately 2 percent, that is approximately

equal to 25 percent of the expected market risk premium of 7.2 percent shown at the

bottom of Column 2 over the 1983-1998 period, as predicted by the ECAPM. The same

is true for the slope of the graph. If the plain vanilla version of the CAPM is correct, then

the slope of the relationship should equal the market risk premium of 7.2 percent.

Instead, the observed slope of close to 5 percent is approximately equal to 75 percent of

the expected market risk premium of 7.2 percent, as predicted by the ECAPM.

In short, the HMMO empirical findings are quite consistent with the predictions

of the ECAPM.

Practical Implementation of the ECAPM

The empirical evidence reviewed above suggests that the expected return on a

security is related to its risk by the following relationship:

K = RF + α + β ( M R P - α ) (5)

or, alternatively by the following equivalent relationship:

K = RF + a MRP + (1-a) β MRP (6)

The empirical findings support values of α from approximately 2 percent to 7

percent. If one is using the short-term U.S. Treasury Bills yield as a proxy for the

risk-free rate, and given that utility stocks have lower than average betas, an alpha in

the lower range of the empirical findings, 2 percent - 3 percent is reasonable, albeit

conservative.

Using the long-term U.S. Treasury yield as a proxy for the risk-free rate, a

lower alpha adjustment is indicated. This is because the use of the long-term U.S.

90


Treasury yield as a proxy for the risk-free rate partially incorporates the desired effect

of using the ECAPM2. An alpha in the range of 1 percent - 2 percent is therefore

reasonable.

To illustrate, consider a utility with a beta of 0.80. The risk-free rate is 5

percent, the MRP is 7 percent, and the alpha factor is 2 percent. The cost of capital is

determined as follows:

K = RF + α + β ( M R P - α )

K = 5% + 2% + 0.80(7% - 2%)

= 11%

A practical alternative is to rely on the second variation of the ECAPM:

K = RF + a MRP + (1-a) β MRP

With an alpha of 2 percent, a MRP in the 6 percent - 8 percent range, the ‘a”

coefficient is 0.25, and the ECAPM becomes3:

K = RF + 0.25 MRP + 0.75 β MRP

Returning to the numerical example, the utility’s cost of capital is:

K = 5% + 0.25 x 7% + 0.75 x 0.80 x 7%

= 11%

For reasonable values of beta and the MRP, both renditions of the ECAPM

2 The Security Market Line (SML) using the long-term risk-free rate has a higher intercept and a flatter slope than the SML using the short-term risk-free rate 3 Recall that alpha equals ‘a’ times MRP, that is, alpha = a MRP, and therefore a = alpha/MRP. If alpha is

2 percent, then a = 0.25

91


produce results that are virtually identical4.

4 In the Morin (1994) study, the value of “a” was actually derived by systematically varying the constant

"a" in equation 6 from 0 to 1 in steps of 0.05 and choosing that value of 'a' that minimized the mean square error between the observed relationship between return and beta: K = 0.0829 + .0520 β The value of a that best explained the observed relationship was 0.25.

92


REFERENCES

Black, Fischer, "Beta and Return," The Journal of Portfolio Management, Fall 1993, 8-18. Black, Fischer, Michael C. Jensen and Myron Scholes, "The Capital Asset Pricing Model: Some Empirical Tests, from Jensen, M. (ed.) Studies in the Theory of Capital Markets, Praeger, New York, 1972, 79-121. Breenan, M. (1973) “Taxes, Market Valuation, and Corporate Financial Policy,” National Tax Journal, 23, 417-427. Fama, Eugene F. and James D. MacBeth, "Risk, Returns and Equilibrium: Empirical Tests," Journal of Political Economy, September 1972, pp. 607-636. Fama, Eugene F. and Kenneth R. French, "The Cross-Section of Expected Stock Returns," Journal of Finance, Vol. 47, June 1992, pp. 427-465. Friend, I., Westerfield, R., and Granito, M. (1978) “New Evidence on the Capital Asset Pricing Model, Journal of Finance, 23, 903-916. Harris, R. S., Marston, F. C., Mishra, D. R., and O’Brien, T. J., “Ex Ante Cost of Equity Estimates of S&P 500 Firms: The Choice Between Global and Domestic CAPM,” Financial Management, Autumn 2003, pp. 51-66. Kraus, A. and Litzenberger, R.H. (1976) “Skewness Preference and the Valuation of Risk Assets, Journal of Finance, 31, 1085-99. Litzenberger, R. H. and Ramaswamy, K. "The Effect of Personal Taxes and Dividends on Capital Asset Prices: Theory and Empirical Evidence." Journal of Financial Economics, June 1979, 163-196. Litzenberger, R. H., Ramaswamy, K. and Sosin, H. (1980) "On the CAPM Approach to the Estimation of a Public Utility’s Cost of Equity Capital, Journal of Finance, 35, May 1980, 369-83. Merton, R.C. (1973) “An Intertemporal Capital Asset Pricing Model”, Econometrica, 41, 867-887. Morin, R.A. (1981) "Intertemporal Market-Line Theory: An Empirical Test," Financial Review, Proceedings of the Eastern Finance Association, 1981. Morin, R.A. (1989) Arizona Corporation Commission, Rebuttal Testimony of Dr. Ra. Morin on behalf of US West Communications, Appendix B, 1989.

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Pettengill, Glenn N., Sridhar Sundaram and Ike Mathur, "The Conditional Relation between Beta and Returns," Journal of Financial and Quantitative Analysis, Vol. 30, No. 1, March 1995, pp. 101-116. Rubinstein, M.E. (1973) “A Mean-Variance Synthesis of Corporate Financial Theory, Journal of Financial Economics, March 1973, 167-82.

94

Appendix B Page 1 of 9

APPENDIX B

FLOTATION COST ALLOWANCE

To obtain the final cost of equity financing from the investors' expected rate of return, it

is necessary to make allowance for underpricing, which is the sum of market pressure, costs of

flotation, and underwriting fees associated with new issues. Allowance for market pressure

should be made because large blocks of new stock may cause significant pressure on market

prices even in stable markets. Allowance must also be made for company costs of flotation

(including such items as printing, legal and accounting expenses) and for underwriting fees.

1. MAGNITUDE OF FLOTATION COSTS

According to empirical studies, underwriting costs and expenses average at least 4% of

gross proceeds for utility stock offerings in the U.S. (See Logue & Jarrow: "Negotiations vs.

Competitive Bidding in the Sale of Securities by Public Utilities", Financial Management, Fall

1978.) A study of 641 common stock issues by 95 electric utilities identified a flotation cost

allowance of 5.0%. (See Borum & Malley: "Total Flotation Cost for Electric Company Equity

Issues", Public Utilities Fortnightly, Feb. 20, 1986.)

Empirical studies suggest an allowance of 1% for market pressure in U.S. studies. Logue

and Jarrow found that the absolute magnitude of the relative price decline due to market pressure

was less than 1.5%. Bowyer and Yawitz examined 278 public utility stock issues and found an

average market pressure of 0.72%. (See Bowyer & Yawitz, "The Effect of New Equity Issues on

Utility Stock Prices", Public Utilities Fortnightly, May 22, 1980.)

Eckbo & Masulis ("Rights vs. Underwritten Stock Offerings: An Empirical Analysis",

University of British Columbia, Working Paper No. 1208, Sept., 1987) found an average

flotation cost of 4.175% for utility common stock offerings. Moreover, flotation costs increased

progressively for smaller size issues. They also found that the relative price decline due to

market pressure in the days surrounding the announcement amounted to slightly more than 1.5%.

In a classic and monumental study published in the prestigious Journal of Financial Economics

by a prominent scholar, a market pressure effect of 3.14% for industrial stock issues and 0.75%

95


for utility common stock issues was found (see Smith, C.W., "Investment Banking and the

Capital Acquisition Process," Journal of Financial Economics 15, 1986). Other studies of market

pressure are reported in Logue ("On the Pricing of Unseasoned Equity Offerings, Journal of

Financial and Quantitative Analysis, Jan. 1973), Pettway ("The Effects of New Equity Sales

Upon Utility Share Prices," Public Utilities Fortnightly, May 10 1984), and Reilly and Hatfield

("Investor Experience with New Stock Issues," Financial Analysts' Journal, Sept.- Oct. 1969). In

the Pettway study, the market pressure effect for a sample of 368 public utility equity sales was

in the range of 2% to 3%. Adding the direct and indirect effects of utility common stock issues,

the indicated total flotation cost allowance is above 5.0%, corroborating the results of earlier

studies.

As shown in the table below, a comprehensive empirical study by Lee, Lochhead, Ritter,

and Zhao, “The Costs of Raising Capital,” Journal of Financial Research, Vol. XIX, NO. 1,

Spring 1996, shows average direct flotation costs for equity offerings of 3.5% - 5% for stock

issues between $60 and $500 million. Allowing for market pressure costs raises the flotation

cost allowance to well above 5%.

96


FLOTATION COSTS: RAISING EXTERNAL CAPITAL

(Percent of Total Capital Raised) Amount Raised Average Flotation Average Flotation in $ Millions Cost: Common Stock Cost: New Debt $ 2 - 9. 99 13.28% 4.39% 10 - 19. 99 8.72 2.76 20 - 39. 99 6.93 2.42 40 - 59. 99 5.87 1.32 60 - 79. 99 5.18 2.34 80 - 99. 99 4.73 2.16 100 - 199. 99 4.22 2.31 200 - 499. 99 3.47 2.19 500 and Up 3.15 1.64 Note: Flotation costs for IPOs are about 17 percent of the value of common stock issued if the amount raised is less than $10 million and about 6 percent if more than $500 million is raised. Flotation costs are somewhat lower for utilities than others. Source: Lee, Inmoo, Scott Lochhead, Jay Ritter, and Quanshui Zhao, “The Costs of Raising Capital,” The Journal of Financial Research, Spring 1996.

Therefore, based on empirical studies, total flotation costs including market pressure

amount to approximately 5% of gross proceeds. I have therefore assumed a 5% gross total

flotation cost allowance in my cost of capital analyses.

2. APPLICATION OF THE FLOTATION COST ADJUSTMENT

The section below shows: 1) why it is necessary to apply an allowance of 5% to the

dividend yield component of equity cost by dividing that yield by 0.95 (100% - 5%) to obtain the

fair return on equity capital, and 2) why the flotation adjustment is permanently required to avoid

confiscation even if no further stock issues are contemplated. Flotation costs are only recovered

97


if the rate of return is applied to total equity, including retained earnings, in all future years.

Flotation costs are just as real as costs incurred to build utility plant. Fair regulatory

treatment absolutely must permit the recovery of these costs. An analogy with bond issues is

useful to understand the treatment of flotation costs in the case of common stocks.

In the case of a bond issue, flotation costs are not expensed but are rather amortized over

the life of the bond, and the annual amortization charge is embedded in the cost of service. This

is analogous to the process of depreciation, which allows the recovery of funds invested in utility

plant. The recovery of bond flotation expense continues year after year, irrespective of whether

the company issues new debt capital in the future, until recovery is complete. In the case of

common stock that has no finite life, flotation costs are not amortized. Therefore, the recovery

of flotation cost requires an upward adjustment to the allowed return on equity. Roger A. Morin,

Regulatory Finance, Public Utilities Reports Inc., Arlington, Va., 1994, provides numerical

illustrations that show that even if a utility does not contemplate any additional common stock

issues, a flotation cost adjustment is still permanently required. Examples there also demonstrate

that the allowance applies to retained earnings as well as to the original capital.

From the standard DCF model, the investor's required return on equity capital is

expressed as:

K = D1/Po + g

If Po is regarded as the proceeds per share actually received by the company from which

dividends and earnings will be generated, that is, Po equals Bo, the book value per share, then the

company's required return is:

r = D1/Bo + g

Denoting the percentage flotation costs 'f', proceeds per share Bo are related to market

price Po as follows:

P - fP = Bo

P(1 - f) = Bo

98


Substituting the latter equation into the above expression for return on equity, we obtain:

r = D1/P(1-f) + g

that is, the utility's required return adjusted for underpricing. For flotation costs of 5%, dividing

the expected dividend yield by 0.95 will produce the adjusted cost of equity capital. For a

dividend yield of 6% for example, the magnitude of the adjustment is 32 basis points: .06/.95 =

.0632.

In deriving DCF estimates of fair return on equity, it is therefore necessary to apply a

conservative after-tax allowance of 5% to the dividend yield component of equity cost.

Even if no further stock issues are contemplated, the flotation adjustment is still

permanently required to keep shareholders whole. Flotation costs are only recovered if the rate

of return is applied to total equity, including retained earnings, in all future years, even if no

future financing is contemplated. This is demonstrated by the numerical example contained in

pages 7-9 of this Appendix. Moreover, even if the stock price, hence the DCF estimate of equity

return, fully reflected the lack of permanent allowance, the company always nets less than the

market price. Only the net proceeds from an equity issue are used to add to the rate base on

which the investor earns. A permanent allowance for flotation costs must be authorized in order

to insure that in each year the investor earns the required return on the total amount of capital

actually supplied.

The example shown on pages 7-9 shows the flotation cost adjustment process using

illustrative, yet realistic, market data. The assumptions used in the computation are shown on

page 7. The stock is selling in the market for $25, investors expect the firm to pay a dividend of

$2.25 that will grow at a rate of 5% thereafter. The traditional DCF cost of equity is thus k =

D/P + g = 2.25/25 + .05 = 14%. The firm sells one share stock, incurring a flotation cost of

5%. The traditional DCF cost of equity adjusted for flotation cost is thus ROE = D/P(1-f) + g

= .09/.95 + .05 = 14.47%.

The initial book value (rate base) is the net proceeds from the stock issue, which are

$23.75, that is, the market price less the 5% flotation costs. The example demonstrates that only

99


if the company is allowed to earn 14.47% on rate base will investors earn their cost of equity of

14%. On page 8, Column 1 shows the initial common stock account, Column 2 the cumulative

retained earnings balance, starting at zero, and steadily increasing from the retention of earnings.

Total equity in Column 3 is the sum of common stock capital and retained earnings. The stock

price in Column 4 is obtained from the seminal DCF formula: D1/(k - g). Earnings per share in

Column 6 are simply the allowed return of 14.47% times the total common equity base.

Dividends start at $2.25 and grow at 5% thereafter, which they must do if investors are to earn a

14% return. The dividend payout ratio remains constant, as per the assumption of the DCF

model. All quantities, stock price, book value, earnings, and dividends grow at a 5% rate, as

shown at the bottom of the relevant columns. Only if the company is allowed to earn 14.47% on

equity do investors earn 14%. For example, if the company is allowed only 14%, the stock price

drops from $26.25 to $26.13 in the second year, inflicting a loss on shareholders. This is shown

on page 9. The growth rate drops from 5% to 4.53%. Thus, investors only earn 9% + 4.53% =

13.53% on their investment. It is noteworthy that the adjustment is always required each and

every year, whether or not new stock issues are sold in the future, and that the allowed return on

equity must be earned on total equity, including retained earnings, for investors to earn the cost

of equity.

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ASSUMPTIONS: ISSUE PRICE = $25.00 FLOTATION COST = 5.00% DIVIDEND YIELD = 9.00% GROWTH = 5.00% EQUITY RETURN = 14.00% (D/P + g) ALLOWED RETURN ON EQUITY = 14.47% (D/P(1-f) + g)

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MARKET/

COMMON RETAINED TOTAL STOCK BOOK STOCK EARNINGS EQUITY PRICE RATIO EPS DPS PAYOUT

Yr (1) (2) (3) (4) (5) (6) (7) (8) -------- -------- -------- -------- -------- -------- -------- -------- --------

1 $23.75 $0.000 $23.750 $25.000 1.0526 $3.438 $2.250 65.45% 2 $23.75 $1.188 $24.938 $26.250 1.0526 $3.609 $2.363 65.45% 3 $23.75 $2.434 $26.184 $27.563 1.0526 $3.790 $2.481 65.45% 4 $23.75 $3.744 $27.494 $28.941 1.0526 $3.979 $2.605 65.45% 5 $23.75 $5.118 $28.868 $30.388 1.0526 $4.178 $2.735 65.45% 6 $23.75 $6.562 $30.312 $31.907 1.0526 $4.387 $2.872 65.45% 7 $23.75 $8.077 $31.827 $33.502 1.0526 $4.607 $3.015 65.45% 8 $23.75 $9.669 $33.419 $35.178 1.0526 $4.837 $3.166 65.45% 9 $23.75 $11.340 $35.090 $36.936 1.0526 $5.079 $3.324 65.45% 10 $23.75 $13.094 $36.844 $38.783 1.0526 $5.333 $3.490 65.45%

5.00% 5.00% 5.00% 5.00%

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MARKET/ COMMON RETAINED TOTAL STOCK BOOK STOCK EARNINGS EQUITY PRICE RATIO EPS DPS PAYOUT

Yr (1) (2) (3) (4) (5) (6) (7) (8) ------ -------- -------- -------- -------- -------- -------- -------- --------

1 $23.75 $0.000 $23.750 $25.000 1.0526 $3.325 $2.250 67.67% 2 $23.75 $1.075 $24.825 $26.132 1.0526 $3.476 $2.352 67.67% 3 $23.75 $2.199 $25.949 $27.314 1.0526 $3.633 $2.458 67.67% 4 $23.75 $3.373 $27.123 $28.551 1.0526 $3.797 $2.570 67.67% 5 $23.75 $4.601 $28.351 $29.843 1.0526 $3.969 $2.686 67.67% 6 $23.75 $5.884 $29.634 $31.194 1.0526 $4.149 $2.807 67.67% 7 $23.75 $7.225 $30.975 $32.606 1.0526 $4.337 $2.935 67.67% 8 $23.75 $8.627 $32.377 $34.082 1.0526 $4.533 $3.067 67.67% 9 $23.75 $10.093 $33.843 $35.624 1.0526 $4.738 $3.206 67.67% 10 $23.75 $11.625 $35.375 $37.237 1.0526 $4.952 $3.351 67.67%

4.53% 4.53% 4.53% 4.53%

103

Exhibit __ (RA

M-1)


Exhibit __ (RAM-1)

104

Exhibit __ (RAM-1) Page 1 of 20

RESUME OF ROGER A. MORIN

(Fall 2009) NAME: Roger A. Morin ADDRESS: 9 King Ave. Jekyll Island, GA 31527, USA 87 Paddys Head Rd Peggy’s Cove Hway Nova Scotia, Canada B3A 3N6 TELEPHONE: (912) 635-3233 business office (912) 635-3233 business fax (404) 229-2857 cellular (902) 823-0000 summer office E-MAIL ADDRESS: [email protected] DATE OF BIRTH: 3/5/1945 PRESENT EMPLOYER: Georgia State University Robinson College of Business Atlanta, GA 30303 RANK: Emeritus Professor of Finance HONORS: Professor of Finance for Regulated Industry Director Center for the Study of Regulated Industry, Robinson College of Business, Georgia State University. EDUCATIONAL HISTORY - Bachelor of Electrical Engineering, McGill University, Montreal, Canada, 1967. - Master of Business Administration, McGill University, Montreal, Canada, 1969. - PhD in Finance & Econometrics, Wharton School of Finance, University of Pennsylvania, 1976.

105


EMPLOYMENT HISTORY - Lecturer, Wharton School of Finance, Univ. of Pennsylvania, 1972-3 - Assistant Professor, University of Montreal School of Business, 1973-1976. - Associate Professor, University of Montreal School of Business, 1976-1979. - Professor of Finance, Georgia State University, 1979-2008

- Professor of Finance for Regulated Industry and Director, Center for the Study of Regulated Industry, Robinson College of Business, Georgia State University, 1985-2008 - Visiting Professor of Finance, Amos Tuck School of Business, Dartmouth College, Hanover, N.H., 1986 - Emeritus Professor of Finance, Georgia State University, 2007-9 OTHER BUSINESS ASSOCIATIONS - Communications Engineer, Bell Canada, 1962-1967. - Member of the Board of Directors, Financial Research Institute of Canada, 1974-1980. - Co-founder and Director Canadian Finance Research Foundation, 1977. - Vice-President of Research, Garmaise-Thomson & Associates, Investment Management Consultants, 1980-1981. - Executive Visions Inc., Board of Directors, Member - Board of External Advisors, College of Business, Georgia State University, Member 1987-1991

106


PROFESSIONAL CLIENTS

AGL Resources

AT & T Communications

Alagasco - Energen

Alaska Anchorage Municipal Light & Power

Alberta Power Ltd.

Allete

Ameren

American Water Works Company

Ameritech

Arkansas Western Gas

Baltimore Gas & Electric – Constellation Energy

Bangor Hydro-Electric

B.C. Telephone

B C GAS

Bell Canada

Bellcore

Bell South Corp.

Bruncor (New Brunswick Telephone)

Burlington-Northern

C & S Bank

Cajun Electric

Canadian Radio-Television & Telecomm. Commission

Canadian Utilities

Canadian Western Natural Gas

Cascade Natural Gas

Centel

Centra Gas

Central Illinois Light & Power Co

Central Telephone

Central & South West Corp.

107


Chattanoogee Gas Company

Cincinnatti Gas & Electric

Cinergy Corp.

Citizens Utilities

City Gas of Florida

CN-CP Telecommunications

Commonwealth Telephone Co.

Columbia Gas System

Consolidated Natural Gas

Constellation Energy

Delmarva Power & Light Co

Deerpath Group

Detroit Edison Company

DTE Energy

Edison International

Edmonton Power Company

Elizabethtown Gas Co.

Emera

Energen

Engraph Corporation

Entergy Corp.

Entergy Arkansas Inc.

Entergy Gulf States, Inc.

Entergy Louisiana, Inc.

Entergy Mississippi Power

Entergy New Orleans, Inc.

First Energy

Florida Water Association

Fortis

Garmaise-Thomson & Assoc., Investment Consultants

Gaz Metropolitain

108


General Public Utilities

Georgia Broadcasting Corp.

Georgia Power Company

GTE California - Verizon

GTE Northwest Inc. - Verizon

GTE Service Corp. - Verizon

GTE Southwest Incorporated - Verizon

Gulf Power Company

Havasu Water Inc.

Hawaiian Electric Company

Hawaiian Elec & Light Co

Heater Utilities – Aqua - America

Hope Gas Inc.

Hydro-Quebec

ICG Utilities

Illinois Commerce Commission

Island Telephone

Jersey Central Power & Light

Kansas Power & Light

KeySpan Energy

Manitoba Hydro

Maritime Telephone

Maui Electric Co.

Metropolitan Edison Co.

Minister of Natural Resources Province of Quebec

Minnesota Power & Light

Mississippi Power Company

Missouri Gas Energy

Mountain Bell

National Grid PLC

Nevada Power Company

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New Brunswick Power

Newfoundland Power Inc. - Fortis Inc.

New Market Hydro

New Tel Enterprises Ltd.

New York Telephone Co.

Niagara Mohawk Power Corp

Norfolk-Southern

Northeast Utilities

Northern Telephone Ltd.

Northwestern Bell

Northwestern Utilities Ltd.

Nova Scotia Power

Nova Scotia Utility and Review Board

NUI Corp.

NYNEX

Oklahoma G & E

Ontario Telephone Service Commission

Orange & Rockland

PNM Resources

Pacific Northwest Bell

People's Gas System Inc.

People's Natural Gas

Pennsylvania Electric Co.

Pepco Holdings

Potomac Electric Power Co.

Price Waterhouse

PSI Energy

Public Service Electric & Gas

Public Service of New Hampshire

Public Service of New Mexico

Puget Sound Energy

110


Quebec Telephone

Regie de l’Energie du Quebec

Rockland Electric

Rochester Telephone

SNL Center for Financial Execution

San Diego Gas & Electric

SaskPower

Sierra Pacific Power Company

Sierra Pacific Resources

Southern Bell

Southern States Utilities

Southern Union Gas

South Central Bell

Sun City Water Company

TECO Energy

The Southern Company

Touche Ross and Company

TransEnergie

Trans-Quebec & Maritimes Pipeline

TXU Corp

US WEST Communications

Union Heat Light & Power

Utah Power & Light

Vermont Gas Systems Inc.

111


MANAGEMENT DEVELOPMENT AND PROFESSIONAL EXECUTIVE EDUCATION

- Canadian Institute of Marketing, Corporate Finance, 1971-73 - Hydro-Quebec, "Capital Budgeting Under Uncertainty,” 1974-75 - Institute of Certified Public Accountants, Mergers & Acquisitions, 1975-78 - Investment Dealers Association of Canada, 1977-78 - Financial Research Foundation, bi-annual seminar, 1975-79 - Advanced Management Research (AMR), faculty member, 1977-80 - Financial Analysts Federation, Educational chapter: "Financial Futures Contracts" seminar - Exnet Inc. a.k.a. The Management Exchange Inc., faculty member 1981-2008: National Seminars: Risk and Return on Capital Projects Cost of Capital for Regulated Utilities Capital Allocation for Utilities Alternative Regulatory Frameworks Utility Directors’ Workshop Shareholder Value Creation for Utilities Fundamentals of Utility Finance in a Restructured Environment Contemporary Issues in Utility Finance - SNL Center for Financial Education. faculty member 2008-2009. National Seminars: Essentials of Utility Finance - Georgia State University College of Business, Management Development Program, faculty member, 1981-1994.

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EXPERT TESTIMONY & UTILITY CONSULTING AREAS OF EXPERTISE

Corporate Finance

Rate of Return

Capital Structure

Generic Cost of Capital

Costing Methodology

Depreciation

Flow-Through vs Normalization

Revenue Requirements Methodology

Utility Capital Expenditures Analysis

Risk Analysis

Capital Allocation

Divisional Cost of Capital, Unbundling

Incentive Regulation & Alternative Regulatory Plans

Shareholder Value Creation

Value-Based Management REGULATORY BODIES

Alabama Public Service Commission

Alaska Public Utility Commission

Alberta Public Service Board

Arizona Corporation Commission

Arkansas Public Service Commission

British Columbia Board of Public Utilities

California Public Service Commission

Canadian Radio-Television & Telecommunications Comm.

Colorado Public Utilities Board

Delaware Public Utility Commission

District of Columbia Public Service Commission

Federal Communications Commission

113


Federal Energy Regulatory Commission

Florida Public Service Commission

Georgia Public Service Commission

Georgia Senate Committee on Regulated Industries

Hawaii Public Service Commission

Illinois Commerce Commission

Indiana Utility Regulatory Commission

Iowa Board of Public Utilities

Louisiana Public Service Commission

Maine Public Service Commission

Manitoba Board of Public Utilities

Michigan Public Service Commission

Minnesota Public Utilities Commission

Mississippi Public Service Commission

Missouri Public Service Commission

Montana Public Service Commission

National Energy Board of Canada

Nevada Public Service Commission

New Brunswick Board of Public Commissioners

New Hampshire Public Utility Commission

New Jersey Board of Public Utilities

New Mexico Public Regulatory Commission

New Orleans City Council

New York Public Service Commission

Newfoundland Board of Commissioners of Public Utilities

North Carolina Utilities Commission

Ohio Public Utilities Commission

Oklahoma State Board of Equalization

Ontario Telephone Service Commission

Ontario Energy Board

Pennsylvania Public Service Commission

114


Quebec Natural Gas Board

Quebec Regie de l’Energie

Quebec Telephone Service Commission

South Carolina Public Service Commission

Tennessee Regulatory Authority

Texas Public Utility Commission

Utah Public Service Commission

Virginia Public Service Commission

Washington Utilities & Transportation Commission

West Virginia Public Service Commission

SERVICE AS EXPERT WITNESS

Southern Bell, So. Carolina PSC, Docket #81-201C

Southern Bell, So. Carolina PSC, Docket #82-294C

Southern Bell, North Carolina PSC, Docket #P-55-816

Metropolitan Edison, Pennsylvania PUC, Docket #R-822249

Pennsylvania Electric, Pennsylvania PUC, Docket #R-822250

Georgia Power, Georgia PSC, Docket # 3270-U, 1981



Georgia Power, F.E.R.C., Docket # ER 80-326, 80-327



Bell Canada, CRTC 1987

Northern Telephone, Ontario PSC

GTE-Quebec Telephone, Quebec PSC, Docket 84-052B

Newtel., Nfld. Brd of Public Commission PU 11-87

CN-CP Telecommunications, CRTC

Quebec Northern Telephone, Quebec PSC

Edmonton Power Company, Alberta Public Service Board

115


Kansas Power & Light, F.E.R.C., Docket # ER 83-418

NYNEX, FCC generic cost of capital Docket #84-800

Bell South, FCC generic cost of capital Docket #84-800

American Water Works - Tennessee, Docket #7226

Burlington-Northern - Oklahoma State Board of Taxes

Georgia Power, Georgia PSC, Docket # 3549-U

GTE Service Corp., FCC Docket #84-200

Mississippi Power Co., Miss. PSC, Docket U-4761

Citizens Utilities, Ariz. Corp. Comm., Docket U2334-86020

Quebec Telephone, Quebec PSC, 1986, 1987, 1992

Newfoundland L & P, Nfld. Brd. Publ Comm. 1987, 1991

Northwestern Bell, Minnesota PSC, Docket P-421/CI-86-354

GTE Service Corp., FCC Docket #87-463

Anchorage Municipal Power & Light, Alaska PUC, 1988

New Brunswick Telephone, N.B. PUC, 1988

Trans-Quebec Maritime, Nat'l Energy Brd. of Cda, '88-92

Gulf Power Co., Florida PSC, Docket #88-1167-EI

Mountain States Bell, Montana PSC, #88-1.2

Mountain States Bell, Arizona CC, #E-1051-88-146

Georgia Power, Georgia PSC, Docket # 3840-U, l989

Rochester Telephone, New York PSC, Docket # 89-C-022

Noverco - Gaz Metro, Quebec Natural Gas PSC, #R-3164-89

GTE Northwest, Washington UTC, #U-89-3031

Orange & Rockland, New York PSC, Case 89-E-175

Central Illinois Light Company, ICC, Case 90-0127

Peoples Natural Gas, Pennsylvania PSC, Case

Gulf Power, Florida PSC, Case # 891345-EI

ICG Utilities, Manitoba BPU, Case 1989

New Tel Enterprises, CRTC, Docket #90-15

Peoples Gas Systems, Florida PSC

Jersey Central Pwr & Light, N.J. PUB, Case ER 89110912J

116


Alabama Gas Co., Alabama PSC, Case 890001

Trans-Quebec Maritime Pipeline, Cdn. Nat'l Energy Board

Mountain Bell, Utah PSC,

Mountain Bell, Colorado PUB

South Central Bell, Louisiana PS

Hope Gas, West Virginia PSC

Vermont Gas Systems, Vermont PSC

Alberta Power Ltd., Alberta PUB

Ohio Utilities Company, Ohio PSC

Georgia Power Company, Georgia PSC

Sun City Water Company

Havasu Water Inc.

Centra Gas (Manitoba) Co.

Central Telephone Co. Nevada

AGT Ltd., CRTC 1992

BC GAS, BCPUB 1992

California Water Association, California PUC 1992

Maritime Telephone 1993

BCE Enterprises, Bell Canada, 1993

Citizens Utilities Arizona gas division 1993

PSI Resources 1993-5

CILCORP gas division 1994

GTE Northwest Oregon 1993

Stentor Group 1994-5

Bell Canada 1994-1995

PSI Energy 1993, 1994, 1995, 1999

Cincinnati Gas & Electric 1994, 1996, 1999, 2004

Southern States Utilities, 1995

CILCO 1995, 1999, 2001

Commonwealth Telephone 1996

Edison International 1996, 1998

117


Citizens Utilities 1997

Stentor Companies 1997

Hydro-Quebec 1998

Entergy Gulf States Louisiana 1998, 1999, 2001, 2002, 2003

Detroit Edison, 1999, 2003

Entergy Gulf States, Texas, 2000, 2004

Hydro Quebec TransEnergie, 2001, 2004

Sierra Pacific Company, 2000, 2001, 2002, 2007

Nevada Power Company, 2001

Mid American Energy, 2001, 2002

Entergy Louisiana Inc. 2001, 2002, 2004

Mississippi Power Company, 2001, 2002, 2007

Oklahoma Gas & Electric Company, 2002 -2003

Public Service Electric & Gas, 2001, 2002

NUI Corp (Elizabethtown Gas Company), 2002

Jersey Central Power & Light, 2002

San Diego Gas & Electric, 2002

New Brunswick Power, 2002

Entergy New Orleans, 2002

Hydro-Quebec Distribution 2002

PSI Energy 2003

Fortis – Newfoundland Power & Light 2002

Emera – Nova Scotia Power 2004

Hydro-Quebec TransEnergie 2004

Hawaiian Electric 2004

Missouri Gas Energy 2004

AGL Resources 2004

Arkansas Western Gas 2004

Public Service of New Hampshire 2005

Hawaiian Electric Company 2005, 2008

Delmarva Power & Light Company 2005, 2009

118


Union Heat Power & Light 2005

Puget Sound Energy 2006, 2007, 2009

Cascade Natural Gas 2006

Entergy Arkansas 2006-7

Bangor Hydro 2006-7

Delmarva 2006, 2007, 2009

Potomac Electric Power Co. 2006, 2007, 2009

Duke Energy Ohio, 2007, 2008, 2009

Duke Energy Kentucky 2009

PROFESSIONAL AND LEARNED SOCIETIES

- Engineering Institute of Canada, 1967-1972

- Canada Council Award, recipient 1971 and 1972

- Canadian Association Administrative Sciences, 1973-80

- American Association of Decision Sciences, 1974-1978

- American Finance Association, 1975-2002

- Financial Management Association, 1978-2002 ACTIVITIES IN PROFESSIONAL ASSOCIATIONS AND MEETINGS

- Chairman of meeting on "New Developments in Utility Cost of Capital", Southern Finance Association, Atlanta, Nov. 1982

- Chairman of meeting on "Public Utility Rate of Return", Southeastern Public Utility Conference, Atlanta, Oct. 1982 - Chairman of meeting on "Current Issues in Regulatory Finance", Financial Management Association, Atlanta, Oct. 1983 - Chairman of meeting on "Utility Cost of Capital", Financial Management Association, Toronto, Canada, Oct. 1984. - Committee on New Product Development, FMA, 1985 - Discussant, "Tobin's Q Ratio", paper presented at Financial Management Association, New York, N.Y., Oct. 1986 - Guest speaker, "Utility Capital Structure: New

119


Developments", National Society of Rate of Return Analysts 18th Financial Forum, Wash., D.C. Oct. 1986 - Opening address, "Capital Expenditures Analysis: Methodology vs Mythology," Bellcore Economic Analysis Conference, Naples Fla., 1988.

- Guest speaker, "Mythodology in Regulatory Finance", Society of Utility Rate of Return Analysts (SURFA), Annual Conference, Wash., D.C. February 2007.

PAPERS PRESENTED:

"An Empirical Study of Multi-Period Asset Pricing," annual meeting of Financial Management Assoc., Las Vegas Nevada, 1987. "Utility Capital Expenditures Analysis: Net Present Value vs Revenue Requirements", annual meeting of Financial Management Assoc., Denver, Colorado, October 1985. "Intervention Analysis and the Dynamics of Market Efficiency", annual meeting of Financial Management Assoc., San Francisco, Oct. 1982 "Intertemporal Market-Line Theory: An Empirical Study," annual meeting of Eastern Finance Assoc., Newport, R.I. 1981 "Option Writing for Financial Institutions: A Cost-Benefit Analysis", 1979 annual meeting Financial Research Foundation "Free-lunch on the Toronto Stock Exchange", annual meeting of Financial Research Foundation of Canada, l978. "Simulation System Computer Software SIMFIN", HP International Business Computer Users Group, London, 1975. "Inflation Accounting: Implications for Financial Analysis." Institute of Certified Public Accountants Symposium, 1979.

120


OFFICES IN PROFESSIONAL ASSOCIATIONS

- President, International Hewlett-Packard Business Computers Users Group, 1977 - Chairman Program Committee, International HP Business Computers Users Group, London, England, 1975

- Program Coordinator, Canadian Assoc. of Administrative Sciences, 1976

- Member, New Product Development Committee, Financial Management Association, 1985-1986

- Reviewer: Journal of Financial Research Financial Management Financial Review Journal of Finance

PUBLICATIONS "Risk Aversion Revisited", Journal of Finance, Sept. 1983 "Hedging Regulatory Lag with Financial Futures," Journal of Finance, May 1983. (with G. Gay, R. Kolb) "The Effect of CWIP on Cost of Capital," Public Utilities Fortnightly, July 1986. "The Effect of CWIP on Revenue Requirements" Public Utilities Fortnightly, August 1986. "Intervention Analysis and the Dynamics of Market Efficiency," Time-Series Applications, New York: North Holland, 1983. (with K. El-Sheshai) "Market-Line Theory and the Canadian Equity Market," Journal of Business Administration, Jan. l982, M. Brennan, editor

"Efficiency of Canadian Equity Markets," International Management Review, Feb. 1978. "Intertemporal Market-Line Theory: An Empirical Test," Financial Review, Proceedings of the Eastern Finance Association, 1981.

121


BOOKS Utilities' Cost of Capital, Public Utilities Reports Inc., Arlington, Va., 1984. Regulatory Finance, Public Utilities Reports Inc., Arlington, Va., 2004 Driving Shareholder Value, McGraw-Hill, January 2001. The New Regulatory Finance, Public Utilities Reports Inc., Arlington, Va., 2006.

MONOGRAPHS

Determining Cost of Capital for Regulated Industries, Public Utilities Reports, Inc., and The Management Exchange Inc., 1982 - 1993. (with V.L. Andrews) Alternative Regulatory Frameworks, Public Utilities Reports, Inc., and The Management Exchange Inc., 1993. (with V.L. Andrews) Risk and Return in Capital Projects, The Management Exchange Inc., 1980. (with B. Deschamps) Utility Capital Expenditure Analysis, The Management Exchange Inc., 1983. Regulation of Cable Television: An Econometric Planning Model, Quebec Department of Communications, 1978. “An Economic & Financial Profile of the Canadian Cablevision Industry,” Canadian Radio-Television & Telecommunication Commission (CRTC), 1978. Computer Users' Manual: Finance and Investment Programs, University of Montreal Press, 1974, revised 1978. Fiber Optics Communications: Economic Characteristics, Quebec Department of Communications, 1978. "Canadian Equity Market Inefficiencies", Capital Market Research Memorandum, Garmaise & Thomson Investment Consultants, 1979.

122


MISCELLANEOUS CONSULTING REPORTS “Operational Risk Analysis: California Water Utilities,” Calif. Water Association, 1993. "Cost of Capital Methodologies for Independent Telephone Systems", Ontario Telephone Service Commission, March 1989. "The Effect of CWIP on Cost of Capital and Revenue Requirements", Georgia Power Company, 1985. "Costing Methodology and the Effect of Alternate Depreciation and Costing Methods on Revenue Requirements and Utility Finances", Gaz Metropolitan Inc., 1985. "Simulated Capital Structure of CN-CP Telecommunications: A Critique", CRTC, 1977. "Telecommunications Cost Inquiry: Critique,” CRTC, 1977. "Social Rate of Discount in the Public Sector", CRTC Policy Statement, 1974. "Technical Problems in Capital Projects Analysis", CRTC Policy Statement, 1974.

RESEARCH GRANTS "Econometric Planning Model of the Cablevision Industry," International Institute of Quantitative Economics, CRTC. "Application of the Averch-Johnson Model to Telecommunications Utilities,” Canadian Radio-Television Commission. (CRTC) "Economics of the Fiber Optics Industry", Quebec Dept. of Communications. "Intervention Analysis and the Dynamics of Market Efficiency", Georgia State Univ. College of Business, 1981. "Firm Size and Beta Stability", Georgia State University College of Business, 1982.

123


"Risk Aversion and the Demand for Risky Assets", Georgia State University College of Business, 1981. Chase Econometrics, Interactive Data Corp., Research Grant, $50,000 per annum, 1986-1989.

124

Exhibit __ (R

AM

-2)


Exhibit __ (RAM-2)

125

Exhibit __ (RAM-2)Page 1 of 1

COMBINATION GAS & ELEC UTILITIES DCF ANALYSIS: VALUE LINE GROWTH PROJECTIONS

Company % Current Proj EPSDivid GrowthYield

(1) (2)

1 ALLETE 5.5 -1.02 Alliant Energy 5.7 4.53 Ameren Corp. 6.1 1.04 Avista Corp. 4.7 6.55 CMS Energy Corp. 4.2 10.06 Consol. Edison 5.6 3.07 DTE Energy 5.3 7.58 Duke Energy 6.1 5.09 Empire Dist. Elec. 7.0 6.0

10 Entergy Corp. 3.9 6.011 Exelon Corp. 4.5 4.512 MGE Energy 4.2 4.013 Northeast Utilities 4.2 8.014 NorthWestern Corp 5.5 8.715 NSTAR 5.0 8.016 Pepco Holdings 7.017 PG&E Corp. 4.3 6.518 Public Serv. Enterprise 4.6 7.519 TECO Energy 5.5 4.520 UniSource Energy 3.9 17.021 Wisconsin Energy 3.4 8.022 Xcel Energy Inc. 5.0 6.5

Notes: Column 1, 2: Value Line Investment Analyzer, 11/2009 No growth forecast available for Pepco Holdings

126

Exhibit __ (RA

M-3)


Exhibit __ (RAM-3)

127


S&P UTILITY INDEX ELECTRIC UTILITIES DCF ANALYSIS: VALUE LINE GROWTH PROJECTIONS

Company % Current Proj EPSDivid GrowthYield

(1) (2)

1 Allegheny Energy 2.7 7.02 Ameren Corp. 6.1 1.03 CenterPoint Energy 6.2 3.04 CMS Energy Corp. 4.2 10.05 Consol. Edison 5.6 3.06 Dominion Resources 5.1 8.07 DTE Energy 5.3 7.58 Duke Energy 6.1 5.09 Edison Int'l 3.8 4.510 Entergy Corp. 3.9 6.011 Exelon Corp. 4.5 4.512 FirstEnergy Corp. 5.2 3.013 FPL Group 3.9 6.014 Integrys Energy 7.1 5.515 Pepco Holdings 7.016 PG&E Corp. 4.3 6.517 Pinnacle West Capital 6.2 3.018 PPL Corp. 5.2 7.519 Progress Energy 6.5 6.020 Public Serv. Enterprise 4.6 7.521 Sempra Energy 3.2 5.522 Southern Co. 5.7 5.023 TECO Energy 5.5 4.524 Wisconsin Energy 3.4 8.025 Xcel Energy Inc. 5.0 6.5

Notes: Column 1, 2: Value Line Investment Analyzer, 11/2009 No growth forecast available for Pepco Holdings

128

Exhibit __ (R

AM

-4)


Exhibit __ (RAM-4)

129


Exhibit RAM-4 Electric Utility Industry Historical Growth Rates

(2) (3)Earnings Dividend

Line Growth GrowthNo. Company Name 5-Year 5-Year

1 Allegheny Energy -24.52 ALLETE3 Alliant Energy 7.0 -5.04 Amer. Elec. Power -6.05 Ameren Corp. -1.56 Avista Corp. 4.0 5.07 Black Hills -8.0 3.58 Cen. Vermont Pub. Serv. 3.5 1.09 CenterPoint Energy -2.0 -7.510 CH Energy Group -1.511 Cleco Corp. 0.5 0.512 CMS Energy Corp. -26.013 Consol. Edison 1.5 1.014 Constellation Energy 3.5 16.015 Dominion Resources 5.5 2.516 DPL Inc. 7.0 2.017 DTE Energy -2.5 0.518 Duke Energy19 Edison Int'l 13.520 El Paso Electric 13.521 Empire Dist. Elec. 3.522 Entergy Corp. 10.5 13.023 Evergreen Energy Inc24 Exelon Corp. 10.5 15.025 FirstEnergy Corp. 12.5 6.526 FPL Group 9.5 7.027 G't Plains Energy -4.528 Hawaiian Elec. -6.029 IDACORP Inc. 1.5 -8.030 Integrys Energy -1.5 3.531 ITC Holdings32 Maine & Maritimes Corp -14.533 MGE Energy 6.0 1.034 Northeast Utilities 3.0 8.535 NorthWestern Corp36 NSTAR 4.0 6.037 NV Energy Inc. -3.538 OGE Energy 11.0 0.539 Otter Tail Corp. -1.5 2.040 Pepco Holdings -2.0 17.541 PG&E Corp. 26.542 Pinnacle West Capital -1.0 5.043 PNM Resources -11.5 6.544 Portland General45 PPL Corp. 7.5 12.546 Progress Energy -6.5 2.047 Public Serv. Enterprise 5.5 2.048 SCANA Corp. 3.5 6.549 Sempra Energy 10.0 3.550 Southern Co. 4.0 3.051 TECO Energy -5.0 -9.052 U.S. Energy Sys Inc53 UIL Holdings54 UniSource Energy -1.5 12.555 UNITIL Corp. 1.556 Vectren Corp. 2.5 3.557 Westar Energy 21.5 -0.558 Wisconsin Energy 6.0 4.559 Xcel Energy Inc. 1.0 -4.0

61 AVERAGE 3.2 2.0

Source: Value Line Investment Analyzer 11/2009

AVERAGE w/o negative growt 5.1 3.6

(1)

130

Exhibit (R

AM

-5)


Exhibit __ (RAM-5)

131


COMBINATION GAS & ELEC UTILITIES DCF ANALYSIS: VALUE LINE GROWTH PROJECTIONS

Company % Current Proj EPS % Expected Cost of ROEDivid Growth Divid EquityYield Yield

(1) (2) (3) (4) (5)

1 Alliant Energy 5.7 4.5 5.9 10.4 10.72 Ameren Corp. 6.1 1.0 6.1 7.1 7.53 Avista Corp. 4.7 6.5 5.0 11.5 11.74 CMS Energy Corp. 4.2 10.0 4.6 14.6 14.85 Consol. Edison 5.6 3.0 5.8 8.8 9.16 DTE Energy 5.3 7.5 5.7 13.2 13.57 Duke Energy 6.1 5.0 6.4 11.4 11.78 Empire Dist. Elec. 7.0 6.0 7.5 13.5 13.99 Entergy Corp. 3.9 6.0 4.1 10.1 10.310 Exelon Corp. 4.5 4.5 4.7 9.2 9.511 MGE Energy 4.2 4.0 4.4 8.4 8.612 Northeast Utilities 4.2 8.0 4.6 12.6 12.813 NorthWestern Corp 5.5 8.7 6.0 14.6 15.014 NSTAR 5.0 8.0 5.4 13.4 13.715 PG&E Corp. 4.3 6.5 4.5 11.0 11.316 Public Serv. Enterprise 4.6 7.5 4.9 12.4 12.717 TECO Energy 5.5 4.5 5.8 10.3 10.618 UniSource Energy 3.9 17.0 4.6 21.6 21.919 Wisconsin Energy 3.4 8.0 3.6 11.6 11.820 Xcel Energy Inc. 5.0 6.5 5.3 11.8 12.1

22 AVERAGE 4.9 6.6 5.2 11.9 12.223 MEDIAN 11.8

Notes: Column 1, 2: Value Line Investment Analyzer, 11/2009 Column 3 = Column 1 times (1 + Column 2/100) Column 4 = Column 3 + Column 2 Column 5 = (Column 3 /0.95) + Column 2 No growth forecast available for Pepco

132

Exhibit __ (RA

M-6)


Exhibit __ (RAM-6)

133



(1) (2) (3) (4) (5)

1 ALLETE 5.5 4.0 5.7 9.7 10.02 Alliant Energy 5.7 4.5 5.9 10.4 10.73 Ameren Corp. 6.1 4.0 6.3 10.3 10.64 Avista Corp. 4.7 5.0 4.9 9.9 10.15 CMS Energy Corp. 4.2 7.0 4.4 11.4 11.76 Consol. Edison 5.6 3.3 5.8 9.1 9.47 DTE Energy 5.3 4.0 5.5 9.5 9.88 Duke Energy 6.1 4.5 6.4 10.9 11.29 Empire Dist. Elec. 7.0 6.0 7.5 13.5 13.910 Entergy Corp. 3.9 6.0 4.1 10.1 10.311 Exelon Corp. 4.5 2.0 4.6 6.6 6.912 MGE Energy 4.2 5.0 4.4 9.4 9.613 Northeast Utilities 4.2 8.5 4.6 13.1 13.314 NorthWestern Corp 5.5 7.7 5.9 13.6 13.915 NSTAR 5.0 6.0 5.3 11.3 11.616 Pepco Holdings 7.0 5.0 7.3 12.3 12.717 PG&E Corp. 4.3 7.5 4.6 12.1 12.318 Public Serv. Enterpris 4.6 3.5 4.7 8.2 8.519 TECO Energy 5.5 11.0 6.1 17.1 17.520 UniSource Energy 3.9 5.0 4.1 9.1 9.421 Wisconsin Energy 3.4 8.5 3.7 12.2 12.322 Xcel Energy Inc. 5.0 5.5 5.3 10.7 11.0

24 AVERAGE 5.0 5.6 5.3 10.9 11.225 MEDIAN 10.9

Notes:

COMBINATION GAS & ELECTRIC UTILITIES DCF ANALYSIS: ANALYSTS' GROWTH FORECASTS

Column 5 = (Column 3 /0.95) + Column 2

Column 1: Value Line Investment Analyzer, 11/2009 Column 2: Zacks long-term earnings growth forecast, 11/200 Column 3 = Column 1 times (1 + Column 2/10 Column 4 = Column 3 + Column

134

Exhibit __ (R

AM

-7)


Exhibit __ (RAM-7)

135



Company % Current Proj EPS% Expected Cost of ROEDivid Growth Divid EquityYield Yield

(1) (2) (3) (4) (5)

1 Allegheny Energy 2.7 7.0 2.9 9.9 10.12 Ameren Corp. 6.1 1.0 6.1 7.1 7.53 CenterPoint Energy 6.2 3.0 6.4 9.4 9.74 CMS Energy Corp. 4.2 10.0 4.6 14.6 14.85 Consol. Edison 5.6 3.0 5.8 8.8 9.16 Dominion Resources 5.1 8.0 5.5 13.5 13.87 DTE Energy 5.3 7.5 5.7 13.2 13.58 Duke Energy 6.1 5.0 6.4 11.4 11.79 Edison Int'l 3.8 4.5 4.0 8.5 8.710 Entergy Corp. 3.9 6.0 4.1 10.1 10.311 Exelon Corp. 4.5 4.5 4.7 9.2 9.512 FirstEnergy Corp. 5.2 3.0 5.4 8.4 8.713 FPL Group 3.9 6.0 4.2 10.2 10.414 Integrys Energy 7.1 5.5 7.5 13.0 13.415 PG&E Corp. 4.3 6.5 4.5 11.0 11.316 Pinnacle West Capital 6.2 3.0 6.3 9.3 9.717 PPL Corp. 5.2 7.5 5.6 13.1 13.418 Progress Energy 6.5 6.0 6.9 12.9 13.319 Public Serv. Enterprise 4.6 7.5 4.9 12.4 12.720 Sempra Energy 3.2 5.5 3.4 8.9 9.121 Southern Co. 5.7 5.0 6.0 11.0 11.322 TECO Energy 5.5 4.5 5.8 10.3 10.623 Wisconsin Energy 3.4 8.0 3.6 11.6 11.824 Xcel Energy Inc. 5.0 6.5 5.3 11.8 12.1

26 AVERAGE 5.0 5.6 5.2 10.8 11.127 MEDIAN 10.9

Notes: Column 1, 2: Value Line Investment Analyzer, 11/2009 Column 3 = Column 1 times (1 + Column 2/100) Column 4 = Column 3 + Column 2 Column 5 = (Column 3 /0.95) + Column 2No Growth Forecast For PEPCO

136

Exhibit __ (RA

M-8)


Exhibit __ (RAM-8)

137



Companies With More Than 50% Regulated Revenues

Company % Current Proj EPS% Expected Cost of ROEDivid Growth Divid EquityYield Yield

(1) (2) (3) (4) (5)

1 Allegheny Energy 2.7 7.0 2.9 9.9 10.12 Ameren Corp. 6.1 1.0 6.1 7.1 7.53 CMS Energy Corp. 4.2 10.0 4.6 14.6 14.84 Consol. Edison 5.6 3.0 5.8 8.8 9.15 DTE Energy 5.3 7.5 5.7 13.2 13.56 Duke Energy 6.1 5.0 6.4 11.4 11.77 Edison Int'l 3.8 4.5 4.0 8.5 8.78 Entergy Corp. 3.9 6.0 4.1 10.1 10.39 Exelon Corp. 4.5 4.5 4.7 9.2 9.5

10 FirstEnergy Corp. 5.2 3.0 5.4 8.4 8.711 FPL Group 3.9 6.0 4.2 10.2 10.412 PG&E Corp. 4.3 6.5 4.5 11.0 11.313 Pinnacle West Capita 6.2 3.0 6.3 9.3 9.714 Progress Energy 6.5 6.0 6.9 12.9 13.315 Public Serv. Enterpris 4.6 7.5 4.9 12.4 12.716 Southern Co. 5.7 5.0 6.0 11.0 11.317 TECO Energy 5.5 4.5 5.8 10.3 10.618 Wisconsin Energy 3.4 8.0 3.6 11.6 11.819 Xcel Energy Inc. 5.0 6.5 5.3 11.8 12.1

21 AVERAGE 4.9 5.5 5.1 10.6 10.922 MEDIAN 10.6 `

Notes: Column 1, 2: Value Line Investment Analyzer, 11/2009 Column 3 = Column 1 times (1 + Column 2/100) Column 4 = Column 3 + Column 2 Column 5 = (Column 3 /0.95) + Column 2 No growth forecast available for Pepco Holdings `

138

Exhibit __ (R

AM

-9)


Exhibit __ (RAM-9)

139


S&P UTILITY INDEX ELECTRIC UTILITIES DCF ANALYSIS: ANALYSTS' GROWTH PROJECTIONS


(1) (2) (3) (4) (5)

1 Allegheny Energy 2.7 16.0 3.1 19.1 19.32 Ameren Corp. 6.1 4.0 6.3 10.3 10.63 CenterPoint Energy 6.2 18.0 7.3 25.3 25.74 CMS Energy Corp. 4.2 7.0 4.4 11.4 11.75 Consol. Edison 5.6 3.3 5.8 9.1 9.46 Dominion Resources 5.1 5.0 5.3 10.3 10.67 DTE Energy 5.3 4.0 5.5 9.5 9.88 Duke Energy 6.1 4.5 6.4 10.9 11.29 Edison Int'l 3.8 5.0 4.0 9.0 9.210 Entergy Corp. 3.9 6.0 4.1 10.1 10.311 Exelon Corp. 4.5 2.0 4.6 6.6 6.912 FirstEnergy Corp. 5.2 7.0 5.6 12.6 12.913 FPL Group 3.9 8.4 4.3 12.7 12.914 Integrys Energy 7.1 26.2 8.9 35.1 35.615 Pepco Holdings 7.0 5.0 7.3 12.3 12.716 PG&E Corp. 4.3 7.5 4.6 12.1 12.317 Pinnacle West Capita 6.2 8.0 6.6 14.6 15.018 PPL Corp. 5.2 10.0 5.7 15.7 16.019 Progress Energy 6.5 4.3 6.8 11.1 11.520 Public Serv. Enterpris 4.6 3.5 4.7 8.2 8.521 Sempra Energy 3.2 7.0 3.4 10.4 10.622 Southern Co. 5.7 8.5 6.2 14.7 15.023 TECO Energy 5.5 11.0 6.1 17.1 17.524 Wisconsin Energy 3.4 8.5 3.7 12.2 12.325 Xcel Energy Inc. 5.0 5.5 5.3 10.7 11.0

27 AVERAGE 5.0 7.8 5.4 13.3 13.528 MEDIAN 11.7

Notes: Column 1: Value Line Investment Analyzer, 11/2009 Column 2: Zacks Investment Research, 11/2009 Column 3 = Column 1 times (1 + Column 2/100) Column 4 = Column 3 + Column 2 Column 5 = (Column 3 /0.95) + Column 2

140

Exhibit __ (R

AM

-10)


Exhibit __ (RAM-10)

141


S&P UTILITY INDEX ELECTRIC UTILITIES DCF ANALYSIS: ANALYSTS' GROWTH PROJECTIONS

Companies With More Than 50% Regulated Revenues


(1) (2) (3) (4) (5)

1 Allegheny Energy 2.7 16.0 3.1 19.1 19.32 Ameren Corp. 6.1 4.0 6.3 10.3 10.63 CMS Energy Corp. 4.2 7.0 4.4 11.4 11.74 Consol. Edison 5.6 3.3 5.8 9.1 9.45 DTE Energy 5.3 4.0 5.5 9.5 9.86 Duke Energy 6.1 4.5 6.4 10.9 11.27 Edison Int'l 3.8 5.0 4.0 9.0 9.28 Entergy Corp. 3.9 6.0 4.1 10.1 10.39 Exelon Corp. 4.5 2.0 4.6 6.6 6.910 FirstEnergy Corp. 5.2 7.0 5.6 12.6 12.911 FPL Group 3.9 8.4 4.3 12.7 12.912 Pepco Holdings 7.0 5.0 7.3 12.3 12.713 PG&E Corp. 4.3 7.5 4.6 12.1 12.314 Pinnacle West Capita 6.2 8.0 6.6 14.6 15.015 Progress Energy 6.5 4.3 6.8 11.1 11.516 Public Serv. Enterpris 4.6 3.5 4.7 8.2 8.517 Southern Co. 5.7 8.5 6.2 14.7 15.018 TECO Energy 5.5 11.0 6.1 17.1 17.519 Wisconsin Energy 3.4 8.5 3.7 12.2 12.320 Xcel Energy Inc. 5.0 5.5 5.3 10.7 11.0

22 AVERAGE 5.0 6.4 5.3 11.7 12.023 MEDIAN 11.6

Notes: Column 1: Value Line Investment Analyzer, 11/2009 Column 2: Zacks Investment Research, 11/2009 Column 3 = Column 1 times (1 + Column 2/100) Column 4 = Column 3 + Column 2 Column 5 = (Column 3 /0.95) + Column 2

Companies with less than 50% regulated revenues:CenterPoint, Dominion, Integrys, PPL, Sempra.

142

Exhibit __ (RA

M-11)


Exhibit __ (RAM-11)

143


COMBINATION ELEC & GAS UTILITIES BETA ESTIMATES

Company Name Beta

1 ALLETE 0.702 Alliant Energy 0.703 Ameren Corp. 0.804 Avista Corp. 0.705 CMS Energy Corp. 0.806 Consol. Edison 0.657 DTE Energy 0.758 Duke Energy 0.659 Empire Dist. Elec. 0.75

10 Entergy Corp. 0.7011 Exelon Corp. 0.8512 MGE Energy 0.6513 Northeast Utilities 0.7014 NorthWestern Corp 0.7015 NSTAR 0.6516 Pepco Holdings 0.8017 PG&E Corp. 0.5518 Public Serv. Enterprise 0.8019 TECO Energy 0.8520 UniSource Energy 0.7021 Wisconsin Energy 0.6522 Xcel Energy Inc. 0.65

AVERAGE 0.72

Source: VLIA 11/2009

144

Exhibit __ (R

AM

-12)


Exhibit __ (RAM-12)

145


S&P UTILITY INDEX ELECTRIC UTILITIES BETA ESTIMATES

Company Name Beta Beta(1) (2) (3)

1 Allegheny Energy 0.95 0.952 Ameren Corp. 0.80 0.803 CenterPoint Energy 0.804 CMS Energy Corp. 0.80 0.805 Consol. Edison 0.65 0.656 Dominion Resources 0.707 DTE Energy 0.75 0.758 Duke Energy 0.65 0.659 Edison Int'l 0.80 0.80

10 Entergy Corp. 0.70 0.7011 Exelon Corp. 0.85 0.8512 FirstEnergy Corp. 0.80 0.8013 FPL Group 0.75 0.7514 Integrys Energy 0.9515 Pepco Holdings 0.80 0.8016 PG&E Corp. 0.55 0.5517 Pinnacle West Capital 0.75 0.7518 PPL Corp. 0.7019 Progress Energy 0.65 0.6520 Public Serv. Enterprise 0.80 0.8021 Sempra Energy 0.8522 Southern Co. 0.55 0.5523 TECO Energy 0.85 0.8524 Wisconsin Energy 0.65 0.6525 Xcel Energy Inc. 0.65 0.65

AVERAGE 0.75 0.74

Source: VLIA 11/2009

Notes: Column (3) Betas of companies with >50% Regulated Revenues

146

Exhibit __ (RA

M-13)


Exhibit __ (RAM-13)

147


Utility Industry Historical Risk Premium(1) (2) (3) (4) (5) (6) (7) (8)

Utlity 20 year S&P Equity EquityBaa-Rated Maturity Bond Utility Risk Risk

Bond Bond Total Index Premium PremiumLine No. Year Yield Value Gain/Loss Interest Return Return Over Bond Returns Over Bond Yields

1 1931 7.62% 1,000.002 1932 9.20% 856.68 -143.32 76.20 -6.71% -0.54% 6.17% -9.74%3 1933 7.76% 1,145.09 145.09 92.00 23.71% -21.87% -45.58% -29.63%4 1934 6.32% 1,162.20 162.20 77.60 23.98% -20.41% -44.39% -26.73%5 1935 5.75% 1,067.23 67.23 63.20 13.04% 76.63% 63.59% 70.88%6 1936 4.77% 1,125.42 125.42 57.50 18.29% 20.69% 2.40% 15.92%7 1937 5.03% 967.45 -32.55 47.70 1.51% -37.04% -38.55% -42.07%8 1938 5.80% 909.55 -90.45 50.30 -4.01% 22.45% 26.46% 16.65%9 1939 4.96% 1,105.79 105.79 58.00 16.38% 11.26% -5.12% 6.30%

10 1940 4.75% 1,026.92 26.92 49.60 7.65% -17.15% -24.80% -21.90%11 1941 4.33% 1,055.82 55.82 47.50 10.33% -31.57% -41.90% -35.90%12 1942 4.28% 1,006.67 6.67 43.30 5.00% 15.39% 10.39% 11.11%13 1943 3.91% 1,051.01 51.01 42.80 9.38% 46.07% 36.69% 42.16%14 1944 3.61% 1,042.47 42.47 39.10 8.16% 18.03% 9.87% 14.42%15 1945 3.29% 1,046.62 46.62 36.10 8.27% 53.33% 45.06% 50.04%16 1946 3.05% 1,035.74 35.74 32.90 6.86% 1.26% -5.60% -1.79%17 1947 3.24% 972.19 -27.81 30.50 0.27% -13.16% -13.43% -16.40%18 1948 3.47% 967.03 -32.97 32.40 -0.06% 4.01% 4.07% 0.54%19 1949 3.42% 1,007.20 7.20 34.70 4.19% 31.39% 27.20% 27.97%20 1950 3.24% 1,026.34 26.34 34.20 6.05% 3.25% -2.80% 0.01%21 1951 3.41% 975.50 -24.50 32.40 0.79% 18.63% 17.84% 15.22%22 1952 3.52% 984.30 -15.70 34.10 1.84% 19.25% 17.41% 15.73%23 1953 3.73% 970.58 -29.42 35.20 0.58% 7.85% 7.27% 4.12%24 1954 3.51% 1,031.43 31.43 37.30 6.87% 24.72% 17.85% 21.21%25 1955 3.53% 997.15 -2.85 35.10 3.22% 11.26% 8.04% 7.73%26 1956 3.88% 951.62 -48.38 35.30 -1.31% 5.06% 6.37% 1.18%27 1957 4.71% 893.23 -106.77 38.80 -6.80% 6.36% 13.16% 1.65%28 1958 4.73% 997.43 -2.57 47.10 4.45% 40.70% 36.25% 35.97%29 1959 5.05% 960.00 -40.00 47.30 0.73% 7.49% 6.76% 2.44%30 1960 5.19% 982.71 -17.29 50.50 3.32% 20.26% 16.94% 15.07%31 1961 5.08% 1,013.71 13.71 51.90 6.56% 29.33% 22.77% 24.25%32 1962 5.02% 1,007.52 7.52 50.80 5.83% -2.44% -8.27% -7.46%33 1963 4.86% 1,020.32 20.32 50.20 7.05% 12.36% 5.31% 7.50%34 1964 4.83% 1,003.82 3.82 48.60 5.24% 15.91% 10.67% 11.08%35 1965 4.87% 994.92 -5.08 48.30 4.32% 4.67% 0.35% -0.20%36 1966 5.67% 905.02 -94.98 48.70 -4.63% -4.48% 0.15% -10.15%37 1967 6.23% 936.47 -63.53 56.70 -0.68% -0.63% 0.05% -6.86%38 1968 6.94% 923.84 -76.16 62.30 -1.39% 10.32% 11.71% 3.38%39 1969 7.81% 912.67 -87.33 69.40 -1.79% -15.42% -13.63% -23.23%40 1970 9.11% 881.32 -118.68 78.10 -4.06% 16.56% 20.62% 7.45%41 1971 8.56% 1,052.23 52.23 91.10 14.33% 2.41% -11.92% -6.15%42 1972 8.16% 1,039.12 39.12 85.60 12.47% 8.15% -4.32% -0.01%43 1973 8.24% 992.22 -7.78 81.60 7.38% -18.07% -25.45% -26.31%44 1974 9.50% 888.09 -111.91 82.40 -2.95% -21.55% -18.60% -31.05%45 1975 10.61% 908.61 -91.39 95.00 0.36% 44.49% 44.13% 33.88%46 1976 9.75% 1,075.06 75.06 106.10 18.12% 31.81% 13.69% 22.06%47 1977 8.97% 1,071.92 71.92 97.50 16.94% 8.64% -8.30% -0.33%48 1978 9.49% 953.78 -46.22 89.70 4.35% -3.71% -8.06% -13.20%49 1979 10.69% 901.73 -98.27 94.90 -0.34% 13.58% 13.92% 2.89%50 1980 13.67% 797.49 -202.51 106.90 -9.56% 15.08% 24.64% 1.41%51 1981 16.04% 859.00 -141.00 136.70 -0.43% 11.74% 12.17% -4.30%52 1982 16.11% 995.85 -4.15 160.40 15.63% 26.52% 10.89% 10.41%53 1983 13.55% 1,175.20 175.20 161.10 33.63% 20.01% -13.62% 6.46%54 1984 14.19% 957.80 -42.20 135.50 9.33% 26.04% 16.71% 11.85%55 1985 12.72% 1,105.76 105.76 141.90 24.77% 33.05% 8.28% 20.33%56 1986 10.39% 1,194.68 194.68 127.20 32.19% 28.53% -3.66% 18.14%57 1987 10.58% 984.33 -15.67 103.90 8.82% -2.92% -11.74% -13.50%58 1988 10.83% 979.72 -20.28 105.80 8.55% 18.27% 9.72% 7.44%59 1989 10.18% 1,055.09 55.09 108.30 16.34% 47.80% 31.46% 37.62%60 1990 10.36% 984.93 -15.07 101.80 8.67% -2.57% -11.24% -12.93%61 1991 9.80% 1,048.71 48.71 103.60 15.23% 14.61% -0.62% 4.81%62 1992 8.98% 1,075.55 75.55 98.00 17.36% 8.10% -9.26% -0.88%63 1993 7.93% 1,104.46 104.46 89.80 19.43% 14.41% -5.02% 6.48%64 1994 8.62% 934.76 -65.24 79.30 1.41% -7.94% -9.35% -16.56%65 1995 8.20% 1,040.95 40.95 86.20 12.72% 42.15% 29.43% 33.95%66 1996 8.05% 1,014.79 14.79 82.00 9.68% 3.14% -6.54% -4.91%67 1997 7.86% 1,019.00 19.00 80.50 9.95% 24.69% 14.74% 16.83%

148


Utility Industry Historical Risk Premium(1) (2) (3) (4) (5) (6) (7) (8)

Utlity 20 year S&P Equity EquityBaa-Rated Maturity Bond Utility Risk Risk

Bond Bond Total Index Premium PremiumLine No. Year Yield Value Gain/Loss Interest Return Return Over Bond Returns Over Bond Yields

68 1998 7.22% 1,067.19 67.19 78.60 14.58% 14.82% 0.24% 7.60%69 1999 7.87% 935.05 -64.95 72.20 0.72% -8.85% -9.57% -16.72%70 2000 8.36% 952.78 -47.22 78.70 3.15% 59.70% 56.55% 51.34%71 2001 7.95% 1,040.73 40.73 83.60 12.43% -30.41% -42.84% -38.36%72 2002 7.80% 1,015.07 15.07 79.50 9.46% -30.04% -39.50% -37.84%73 2003 6.77% 1,111.97 111.97 78.00 19.00% 26.11% 7.11% 19.34%74 2004 6.39% 1,042.57 42.57 67.70 11.03% 24.22% 13.19% 17.83%75 2005 6.06% 1,037.96 37.96 63.90 10.19% 16.79% 6.60% 10.73%76 2006 6.48% 953.29 -46.71 60.60 1.39% 20.95% 19.56% 14.47%77 2007 6.33% 1,016.88 16.88 64.80 8.17% 19.36% 11.19% 13.03%7879 Mean 4.1% 4.5%

Source: Bloomberg Web site: Standard & Poors Utility Stock Index % Annual Change, Dec. to Dec.Bond yields from Bloomberg

149

Exhibit __ (R

AM

-14)


Exhibit __ (RAM-14)

150


Company Name % Com Equity

1 ALLETE 58.42 Alliant Energy 58.63 Ameren Corp. 50.84 Avista Corp. 51.95 CMS Energy Corp. 27.46 Consol. Edison 51.27 DTE Energy 43.68 Duke Energy 61.39 Empire Dist. Elec. 46.4

10 Entergy Corp. 40.211 Exelon Corp. 46.612 MGE Energy 63.713 Northeast Utilities 38.114 NorthWestern Corp 53.215 NSTAR 42.816 Pepco Holdings 43.817 PG&E Corp. 46.518 Public Serv. Enterprise 49.019 TECO Energy 38.520 UniSource Energy 27.121 Wisconsin Energy 44.822 Xcel Energy Inc. 47.1

24 AVERAGE 46.9

COMMON EQUITY RATIOS COMBINATION ELECTRIC & GAS UTILITIES

Source: Value Line Investment Analyzer 11/2009

151

Testim

ony of

Andrew

E. Dinkel

Before the Public Service Commission

NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRID

Direct Testimony

of

Andrew E. Dinkel III

Director of Cost of Capital

Dated: January 29, 2010

152

Testimony of Andrew E. Dinkel III

Page 1 of 25

Q. Please state your name and business address. 1

A. My name is Andrew E. Dinkel III. I am the Director of Cost of Capital of 2

the U.S. Regulation and Pricing Organization of National Grid USA, Inc. 3

My business address is 1 MetroTech Center, Brooklyn, NY 11201. 4

5

Q. Please describe your educational and professional background. 6

A. I received a Bachelor of Science degree in Electrical Engineering from the 7

Polytechnic Institute of Brooklyn in 1975. In 1983, I successfully 8

completed the Power System Engineering Course given by General 9

Electric. In addition, I have attended various industry seminars addressing 10

advanced engineering economics and financial and accounting issues. I 11

joined the Long Island Lighting Company as an engineer in the 12

Distribution Engineering Section in 1977. Since then I have held various 13

managerial positions within LILCO and its successor companies KeySpan 14

Corporation (“KeySpan”) and National Grid plc (“National Grid”), 15

including Manager of the Financial Analysis Division and later, Manager 16

of Financial Planning. In September 2001, I became Director of Financial 17

Strategy at KeySpan reporting to the Assistant Treasurer. In 2006, I 18

transferred to the position of Director of Revenue Requirements in the 19

Regulation and Pricing – Gas Distribution organization. In May 2009, I 20

became the Director of Cost of Capital in the U.S. Regulation and Pricing 21

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organization of National Grid’s United States-based operations. In my 1

current position, I am familiar with the financing of Niagara Mohawk 2

Power Corporation d/b/a National Grid (“Niagara Mohawk” or “the 3

Company”) 4

5

Q. Have you previously testified or submitted prepared testimony in a 6

regulatory proceeding? 7

A. Yes, I have previously testified and submitted testimony before the New 8

York Public Service Commission (“Commission”) in Cases 28252, 29029, 9

29484, 89-G-030, 90-E-1185, 91-G-0112, 91-G-1328, 93-G-002, 93-E-10

1123 and 96-E-0132, presenting the Long Island Lighting Company’s 11

historic and projected rate year cost of capital, capitalization, financial 12

statistics, ratemaking principles and quality indicators. More recently, I 13

testified before the Commission in Case 08-G-0609 presenting Niagara 14

Mohawk’s historic and projected rate year cost of capital, capitalization 15

and financial statistics. I have also submitted testimony before the Federal 16

Energy Regulatory Commission in Docket Nos. ER04-112-000 and ER09-17

628 on issues pertaining to National Grid Generation LLC’s cost of 18

service and cost of capital. 19

20

Q. What is the purpose of your testimony? 21

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A. In support of Niagara Mohawk’s electric base rate filing, the purpose of 1

my testimony is to present the Company’s proposed capital structure and 2

overall cost of capital in this proceeding. My testimony provides 3

information for both the historic test or base year ending September 30, 4

2009 and the forecast rate years ending December 31, 2011, December 31, 5

2012 and December 31, 2013. All forecast material has been developed 6

from the historical base. Also, due to the continuing turmoil in the debt 7

auction markets, I am recommending that a variable rate debt true-up 8

mechanism applicable to the Company’s variable rate pollution control 9

revenue bonds issued through the New York State Energy Research and 10

Development Authority (“NYSERDA”) be implemented for variable rate 11

debt interest expense and associated fees allocated to the Company’s 12

electric operations. Under this mechanism, the Company would fully 13

reconcile its actual interest costs, insurance premiums and remarketing 14

fees associated with the NYSERDA auction rate debt to the corresponding 15

costs, premiums and fees that are reflected in the Company’s electric 16

revenue requirements in this proceeding. Cost increases or decreases 17

compared to the levels reflected in the revenue requirement would be 18

deferred and included in the Electric Delivery Adjustment Mechanism to 19

be recovered from or passed back to customers as explained in the 20

testimony of the Revenue Requirements Panel. 21

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Q. Do you sponsor any exhibits as part of your testimony in this 1

proceeding? 2

A. Yes. I sponsor the following exhibits, which were prepared or compiled 3

under my supervision and direction: (i) Exhibit __ (AED-1), entitled 4

“Niagara Mohawk Power Corporation – Capitalization And Weighted 5

Average Cost Of Capital;” Exhibit __ (AED-2) which are the workpapers 6

supporting Exhibit __ (AED-1); and (iii) Exhibit __ (AED-3), which 7

consists of the most recent evaluations of Niagara Mohawk by Standard & 8

Poor’s (“S&P”) and Moody’s Investors Service (“Moody’s”). 9

10

Q. Please describe Exhibit ___ (AED-1). 11

A. Schedule 1 of Exhibit __ (AED-1) sets forth Niagara Mohawk’s historic 12

cost of long-term debt and preferred stock. Schedule 2 contains the 13

projected capitalization and weighted average cost of capital that I am 14

proposing be adopted for Niagara Mohawk in this proceeding. Schedule 3 15

sets forth a forecast Sources and Uses of Funds statement and projected 16

financial statistics for the rate years ending December 31, 2011, 2012 and 17

2013, respectively. Workpapers supporting this Exhibit have been 18

provided as Exhibit __ (AED-2). 19

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Q. What are the weighted average costs of capital that you are proposing 1

be adopted for Niagara Mohawk for each of the three rate years in 2

this proceeding? 3

A. The Company’s proposal in this case is to establish rates for three years, 4

the calendar years ending 2011, 2012 and 2013. The Weighted Average 5

Costs of Capital that I am proposing, as shown on Schedule 2, Pages 5, 6 6

and 7 of Exhibit __ (AED-1) are 8.03% for the 2011 rate year, 8.27% for 7

the 2012 rate year and 8.50% for the 2013 rate year. These overall rates of 8

return are based on the following capitalization ratios and cost rates: 9

10

NIAGARA MOHAWK OVERALL COST OF CAPITAL

2011 2012 2013 Capitalization Cost Weighted Capitalization Cost Weighted Capitalization Cost Weighted Ratio (%) Rate (%) Cost (%) Ratio (%) Rate (%) Cost (%) Ratio (%) Rate (%) Cost (%)

Long-Term Debt 48.0 5.03 2.42 46.9 5.58 2.62 44.8 6.12 2.74Short-Term Debt 0.8 2.21 0.02 1.9 3.28 0.06 4.2 4.28 0.18Customer Deposits 0.6 2.45 0.02 0.6 2.45 0.02 0.6 2.45 0.01Preferred Stock 0.5 3.62 0.02 0.5 3.62 0.02 0.5 3.62 0.02Common Equity 50.0 11.10 5.55 50.0 11.10 5.55 50.0 11.10 5.55Total 100.1 8.03 100.0 8.27 100.0 8.50 11

In calculating the capitalization ratios shown above, all of the goodwill 12

recorded on Niagara Mohawk’s books was excluded from the Company’s 13

total capitalization and common equity balances. 14

15

Q. How did you determine Niagara Mohawk’s capitalization ratios? 16

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A. Niagara Mohawk’s weighted average cost of capital for each of the three 1

rate years reflects a capital structure comprising 50% common equity 2

exclusive of goodwill. This approximates Niagara Mohawk’s current 3

capital structure and is the targeted structure that the Company plans on 4

maintaining going forward to minimize its overall cost of capital, maintain 5

the Company’s current “A” range credit/bond rating, and provide it with 6

ready access to the financial markets at a reasonable cost. 7

8

Q. Has the Company modified its capital structure since its acquisition 9

by National Grid in 2002? 10

A. Yes. Since its acquisition by National Grid in 2002, the Company’s 11

common equity ratio exclusive of goodwill has increased from 12

approximately 25% at the end of the first quarter immediately following 13

the transaction, to approximately 50% as of September 30, 2009. This 14

significant achievement was accomplished by using virtually all of the 15

Company’s cash earnings and other sources of internally generated cash to 16

increase the Company’s common equity balance, pay down debt and fund 17

construction expenditures. Since the acquisition, the Company has 18

increased its common equity exclusive of goodwill by $1.0 billion and 19

reduced its total debt outstanding by $2.3 billion. 20

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Q. Has the improvement in the Company’s capital structure since its 1

acquisition by National Grid improved Niagara Mohawk’s credit 2

ratings? 3

A. Yes. The steady and continuing reduction in the Company’s leverage that 4

has occurred since its acquisition by National Grid has been one of the key 5

factors that has prompted Moody’s to upgrade Niagara Mohawk’s 6

corporate credit rating twice; from Baa3 prior to the acquisition to Baa1 in 7

October 2004, and from Baa1 to A3 in November 2007. In its February 1, 8

2008 Credit Opinion on the Company, Moody’s stated that the significant 9

reduction in debt levels that Niagara Mohawk was able to achieve over the 10

past three years and the corresponding favorable improvements in key 11

credit metrics that resulted were major factors in its decision to upgrade 12

the Company’s credit rating from Baa1 to A3 in November 2007. 13

Furthermore, in announcing the upgrade to A3 in November 2007, 14

Moody’s also stated that in addition to the improvement in the Company’s 15

financial profile that has occurred, the rating action was also premised on 16

Moody’s belief that this trend could be sustained and the fact that the 17

Company agreed to adopt a version of the regulatory financial protections 18

that apply to KeySpan’s New York-based utility subsidiaries. In a more 19

recent Credit Opinion on the Company issued on July 22, 2009, Moody’s 20

again points out that the Company’s use of its free cash flow to 21

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significantly reduce its debt level over the last several years has 1

contributed to corresponding favorable improvements in key credit 2

metrics. Moody’s also states in this Opinion that they view the financial 3

protections put in place at Niagara Mohawk as a “credit positive.” 4

5

Q. Please outline the financial protections you just alluded to. 6

A. When it was acquired by National Grid in 2002, the Company agreed to a 7

number of financial protections that were adopted by the Commission 8

when it approved the Merger Joint Proposal in Case 01-M-0075. These 9

protections are designed to financially insulate or “ring fence” Niagara 10

Mohawk from National Grid and its other affiliates. Except for its 11

participation as a borrower or lender in the corporate money pool, these 12

protections prohibit the Company from providing any financial assistance 13

to its affiliates through loans, loan guarantees, letters of credit or other 14

commitments, as well as using its assets to collateralize affiliate debt. 15

These protections also prohibit the Company from paying dividends under 16

certain circumstances. More recently, in approving the merger between 17

National Grid and KeySpan, the Commission ordered that the Company 18

adopt additional protections to further insulate it from National Grid and 19

its affiliates. One of these new protections is that there can be no cross 20

default provisions that would require Niagara Mohawk to indemnify any 21

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lender, supplier or other counter-party for or as a result of a default of any 1

affiliate. Also, if any cross default provisions currently exist that cannot 2

be eliminated, National Grid is required to obtain indemnification from an 3

investment grade entity that fully protects Niagara Mohawk from the 4

effects of such existing cross default provisions, the cost of which will not 5

be borne by customers. In addition, the Company will modify its 6

certificate of incorporation to establish a golden share to prevent a 7

bankruptcy of National Grid, National Grid USA or any affiliate from 8

automatically triggering a bankruptcy of Niagara Mohawk without the 9

approval of the holder of the golden share, an entity that is charged with 10

acting in accordance with the best interests of New York. These new 11

protections also require that National Grid create separate regulated and 12

unregulated money pools and further require that the regulated money 13

pool expressly prohibit its participants from directly or indirectly loaning 14

or transferring funds borrowed from the money pool to National Grid 15

USA, National Grid and all non-participants in the regulated money pool. 16

Another new restriction prohibits the Company from paying common 17

dividends without Commission approval if its or National Grid’s bond 18

rating on their least secure form of debt falls below investment grade as 19

determined by one or more U.S. nationally recognized rating agencies, or 20

either entity’s bond rating falls to the lowest investment grade rating and is 21

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on negative watch or review for a further downgrade. Finally, no debt 1

associated with the KeySpan merger may be reflected as an obligation of 2

Niagara Mohawk or on its regulatory or US GAAP books and records. 3

4

Q. Since the acquisition by National Grid has Niagara Mohawk’s credit 5

rating from Standard & Poor’s (“S&P”) also improved? 6

A. Yes. Just prior to the acquisition, Niagara Mohawk’s credit rating from 7

S&P was BBB. Today, it is A-. 8

9

Q. Is the maintenance of a low “A” credit rating consistent with the 10

results of the so-called “Generic Financing Proceeding” that is often 11

referred to by the Commission in determining the cost of capital for 12

utilities in New York? 13

A. Yes. The so-called “Generic Financing Proceeding” – Case 91-M-0509 – 14

resulted in a 1994 recommended decision that, although never acted upon 15

by the Commission, has often been referred to by it when determining the 16

cost of capital to be used in setting rates. In that proceeding, the electric 17

and gas group, which included utilities, Commission Staff, the Consumer 18

Protection Board and Multiple Intervenors, agreed that while a “BBB” 19

rating was most often the least costly on a purely quantitative basis, the 20

cost of a slip from “BBB” to “BB” was substantial, while the increased 21

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cost of achieving an “A” rating was only slightly greater than that of a 1

“BBB” rating. Thus, the group concluded that the “A” rating goal was the 2

more cost effective, when qualitative factors were added to the equation. 3

The recommended decision in the “General Financing Proceeding” 4

proposed that the Commission continue to offer utilities ratemaking 5

support for an “A” rating. 6

7

Q. Is there other evidence that supports the use of the Company’s stand-8

alone capital structure for the purposes of setting electric rates in this 9

proceeding? 10

A. Yes. Exhibit __ (AED-3) sets forth the most recent evaluations of Niagara 11

Mohawk by S&P and Moody’s. The fact that these evaluations reflect 12

higher unsecured debt ratings for Niagara Mohawk than National Grid 13

demonstrates that these rating agencies take into account Niagara 14

Mohawk’s credit quality on a stand-alone basis, separate and distinct from 15

National Grid. If the credit rating agencies determine that the Company 16

on a standalone basis is significantly less risky because of ring fencing, 17

stronger credit metrics and/or other factors, they will rate the Company 18

higher than its parent, National Grid. 19

20

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Q. Does Niagara Mohawk have higher unsecured debt ratings than 1

National Grid? 2

A. Yes. The Company’s senior unsecured debt ratings assigned to it by 3

Moody’s and S&P are both one notch higher those assigned to National 4

Grid. The Company’s senior unsecured debt is currently rated A3 by 5

Moody’s and A- by S&P whereas National Grid’s ratings are Baa1 and 6

BBB+, respectively. Also, the issuer rating assigned to the Company by 7

Moody’s is one notch higher than that assigned to National Grid. The 8

current issuer ratings of Niagara Mohawk and National Grid are A3 and 9

Baa1, respectively. As will be discussed below, the Company’s standalone 10

credit strength, which has contributed to its higher credit ratings compared 11

to National Grid has provided significant benefits to customers in terms of 12

lower financing costs. 13

14

Q. Under certain circumstances, the Commission has used the capital 15

structure of the parent company in determining the overall cost of 16

capital for utilities under its jurisdiction that are owned by holding 17

companies. Do you believe it is appropriate for the Commission to use 18

National Grid’s capital structure to set rates for Niagara Mohawk in 19

this proceeding? 20

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A. No, I do not. National Grid’s common equity ratio under Generally 1

Accepted Accounting Principles recognized in the United States (“US 2

GAAP”) for the fiscal year ending March 31, 2009 was 31.7%. The 3

capital structure of Niagara Mohawk bears no relationship to that of 4

National Grid, nor will it going forward. In addition, National Grid’s 5

capital structure has been significantly affected by several recent 6

transactions that have had no impact on the Company’s stand alone capital 7

structure. These transactions included the National Grid/KeySpan merger 8

that was consummated in August 2007, the sale of National Grid’s 9

wireless communications business that was completed in April 2007 and 10

the sale of the Ravenswood generating station that was completed in the 11

summer of 2008. National Grid’s US GAAP capital structure is 12

influenced by a variety of factors, including the nature of National Grid’s 13

international businesses and changes in foreign exchange rates that have 14

nothing to do with Niagara Mohawk or its standing in the financial 15

community. 16

17

In addition, the financial community recognizes that there is financial 18

separation between National Grid and Niagara Mohawk. The financial 19

protections that were adopted by the Commission when it approved the 20

National Grid/KeySpan merger prohibit the pushdown or assignment of 21

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responsibility of any merger-related debt to the Company. It would be 1

inappropriate for the Commission to reflect any impact of parent company 2

transactions in the Company’s revenue requirements through the 3

imputation of the parent company’s capital structure when it cannot be 4

demonstrated that these transactions have any bearing on the Company. It 5

is my understanding that in establishing the proper capital structure for 6

ratemaking purposes, the Commission seeks to determine the amount of 7

debt and equity capital that the Company is dedicating to public service in 8

order to be assured that customers are paying only the costs to support 9

regulated operations. The capital structure that I am proposing is one that 10

will ensure that Niagara Mohawk’s customers receive the benefits of the 11

Company’s improved financial profile and pay rates that reflect the capital 12

actually being used to support Niagara Mohawk’s regulated operations. 13

14

Q. Are there any other reasons that a capital structure other than that 15

proposed by the Company should not be used to set electric rates in 16

proceeding? 17

A. Yes. A capital structure with a common equity ratio of less than 50% 18

would contain a level of debt in excess of that required to support Niagara 19

Mohawk’s current credit rating based on the benchmarks used by S&P in 20

the credit rating process. According to S&P, Niagara Mohawk has an 21

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“excellent” business risk profile and a “significant” financial risk profile. 1

Based upon the business and financial risk matrix published by S&P that 2

is shown below, a company with “excellent” business and “significant” 3

financial risk scores would be assigned an A- rating. 4

Business Risk Profile Minimal Modest Intermediate Significant Aggressive Highly LeveragedExcellent AAA AA A A- BBB -Strong AA A A- BBB BB BB-Satisfactory A- BBB+ BBB BB+ BB- B+Fair - BBB- BB+ BB BB- BWeak - - BB BB- B+ B-

Financial Risk Profile

BUSINESS AND FINANCIAL RISK PROFILE MATRIX

And indeed, Niagara Mohawk has an A- corporate credit rating (“CCR”) 5

from S&P, which is compatible with an “excellent” business profile and a 6

“significant” financial profile. Niagara Mohawk’s unsecured debt 7

issuances are also rated “A-” by S&P. 8

9

Q. What is the degree of debt leverage that is associated with this rating 10

under S&P’s benchmark? 11

A. According to the indicative ratios expected by S&P for a company with a 12

“significant” financial risk score, the total debt, including short- and long-13

term debt, should be in the range of 45% to 50%. These indicative values 14

are shown below. 15

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Financial Risk Profile FFO/Debt (%) Debt/EBITDA (x) Debt/Capital (%)Minimal greater than 60 less than 1.5 less than 25Modest 45-60 1.5-2 25-35Intermediate 30-45 2-3 35-45Significant 20-30 3-4 45-50Aggressive 12-20 4-5 50-60

FINANCIAL RISK INDICATIVE RATIOS (CORPORATE)

FFO/Debt is the ratio of the Company’s funds from operations to its total debt. Debt/EBITDA is the ratio of total debt to earnings before interest, taxes, depreciation and amortizations. Debt/Capital is the ratio of total debt to total capital. Based upon the debt ratios shown above, equity ratios (including common 1

equity and preferred stock) for companies with A- credit ratings should be 2

within the range of 50% to 55%. This is one of the key parameters that 3

should be used to gauge the reasonableness of the common equity ratio 4

proposed in this case. The Company’s proposed common equity ratio of 5

50% is already at the low end of this range and anything lower would not 6

be consistent with its current credit rating. 7

8

Q. If the Commission wishes to consider whether to use National Grid’s 9

capital structure to set rates in this proceeding, how should the equity 10

component of its capital structure be determined? 11

A. As discussed more fully below, the effect of using National Grid’s capital 12

structure to set rates in this proceeding will be to jeopardize Niagara 13

Mohawk’s ability to maintain its current credit ratings. Moreover, there 14

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are a number of differences between National Grid and Niagara Mohawk 1

that must be recognized before the Commission can even consider using 2

National Grid’s capital structure. First, differences in the methodology 3

used to set rates for National Grid’s regulated businesses in the United 4

Kingdom (“UK”) compared to that used in New York make it 5

inappropriate to use National Grid’s capital structure as determined in 6

accordance with US GAAP to establish the Company’s revenue 7

requirements in this proceeding. The regulator of National Grid’s UK 8

businesses does not utilize the level of capital represented in its US GAAP 9

accounts when setting rates. These accounts, in turn, do not reflect the 10

value of the UK businesses on which the UK regulator allows them to earn 11

a return. In the UK, rates are set based on a Regulatory Asset Value 12

(“RAV”), rather than a rate base based on book value per US GAAP. 13

RAV has no direct relationship to the book value of these businesses and 14

was initially derived from a combination of replacement cost and market 15

value. In addition, under the UK regulatory framework, the RAV is 16

increased by inflation every year. Thus, the equity component as 17

determined in accordance with US GAAP must be adjusted to recognize 18

the difference between the RAV and the US GAAP book value of the UK 19

regulated businesses. This is necessary to ensure that National Grid’s 20

consolidated capital structure reflects the regulatory value of assets in both 21

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the US and UK on an equal and consistent basis. This adjustment 1

increases National Grid’s consolidated common equity ratio determined in 2

accordance with US GAAP by 6 percentage points from 31.7% to 37.8%. 3

4

Q. Are there any other factors that affect National Grid’s capital 5

structure which need to be taken into account if the Commission 6

wishes to consider using it to set rates in this proceeding? 7

A. Yes. Changes in currency exchange rates which are beyond the control of 8

the Company and National Grid can have a significant impact on National 9

Grid’s capital structure and thus its capitalization ratios as determined in 10

accordance with US GAAP. The reason for this is that approximately 11

two-thirds of National Grid’s outstanding debt has been issued in US 12

dollars and thus its weighting in the overall capital structure of National 13

Grid is heavily dependent on the currency exchange rate between the US 14

dollar and the British pound. Over the course of National Grid’s last fiscal 15

year ending March 31, 2009, the exchange rate from US dollars to British 16

pounds decreased by approximately 27% from 1.98 US dollars per British 17

pound at fiscal year end 2008 to 1.44 US dollars per British pound at fiscal 18

year-end 2009. Had the exchange rate remained the same as at fiscal year 19

end 2008, National Grid’s common equity ratio after adjusting for RAV 20

would have been 40.9% as compared to 37.8% as noted above. For 21

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comparative purposes, National Grid’s US GAAP common equity ratio at 1

fiscal year end 2008 after adjusting for RAV and based on the actual 2

exchange rate at that time of 1.98 US dollars per British pound was 43.7%. 3

Because the Company and National Grid cannot control currency 4

exchange rates it would be inappropriate for the Commission to consider a 5

common equity ratio of less than 40.9% for National Grid. 6

7

Q. Please outline the financing activity and dividend payment policy that 8

you used in developing Niagara Mohawk’s projected costs of capital 9

for the 2011, 2012 and 2013 rate years 10

A. Current projections indicate that the Company will need to issue $350 11

million of additional long-term debt in June 2010, $400 million in October 12

2012 and $500 million in June 2013 to fund its capital expenditure 13

program, redeem maturing long-term debt and maintain a capital structure 14

comprised of 50% common equity exclusive of goodwill. The projected 15

costs of capital for each of the three rate years assume that the Company 16

will issue this debt as 10-year senior unsecured debt at forecasted interest 17

rates of 5.0% in 2010, 5.6% in 2012 and 6.3% in 2013. It has been 18

assumed that the costs to issue this debt will be 1% of the principal 19

amounts issued and that these costs will be amortized over the lives of the 20

debt which effectively increases the interest rates on these securities by 10 21

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basis points. Pursuant to the Commission Order in Case 08-M-1352, the 1

Company currently has authorization to issue $750 million of this debt 2

through March 31, 2012. 3

4

Q. Have customers benefited from the Company’s higher senior 5

unsecured debt ratings compared to those of National Grid? 6

A. Yes. In the summer of 2009 the Company issued a total of $1.25 billion 7

of new long-term debt. The Company’s higher credit ratings resulting 8

from its stronger credit profile (its higher equity ratio and the financial 9

protections described above), coupled with the fact that the $1.25 billion 10

of new debt was issued by Niagara Mohawk and thus placed closest to the 11

assets it is funding, resulted in a lower cost to customers than would have 12

been the case if National Grid had issued comparable debt. Based on 13

interest rate spreads at the time of issuance, had National Grid issued the 14

$750 million of 10-year debt instead of Niagara Mohawk, it is estimated 15

that interest rate on this debt would have been about 50 basis points 16

higher. Similarly, the interest rate on the $500 million of 5 year debt 17

issued by the Company would have been about 40 basis points higher had 18

it been issued by National Grid. Thus, by having the Company issue the 19

$1.25 billion of new debt, customers will save an estimated total of $47.5 20

million in interest expense over the lives of the debt compared to its 21

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issuance by National Grid. This cost differential is a clear benefit of the 1

financial separation between the Company and National Grid. This 2

benefit justifies the use of Company’s stand alone capital structure for 3

ratemaking purposes in this proceeding. 4

5

Q. How were the projected cost rates of long-term debt for Niagara 6

Mohawk shown on Exhibit __ (AED-1) derived? 7

A. The long-term debt component of Niagara Mohawk’s capital structure 8

consists of long-term notes payable to Niagara Mohawk’s parent company 9

Niagara Mohawk Holdings, Inc., fixed rate taxable bonds and fixed and 10

variable rate tax-exempt bonds issued through NYSERDA that are 11

currently supporting electric and gas transmission and distribution 12

investments. Included in the costs of these bonds are the direct coupon 13

expense, as well as the amortization of debt discounts or premiums, and 14

the amortization of issuance costs where applicable. Furthermore, it was 15

assumed that the variable rate bonds would continue to be supported by 16

direct pay letter of credit facilities in order to obtain the most 17

advantageous interest rates for these bonds. The associated fees for these 18

letters of credit, the amortization of debt discounts or premiums, the 19

amortization of issuance costs, and the remarketing fees are added to the 20

direct interest expense when computing the cost of debt for these issues. 21

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Because of the ongoing turmoil in the auction rate bond markets caused by 1

the financial crisis that continues to cause numerous remarketing auctions 2

to fail, it is difficult at this time to make reliable projections of the interest 3

rates that the Company’s variable rate Pollution Control Revenue bonds 4

will pay during the rate years. Therefore, for the time being, I have 5

assumed that the interest rates on these bonds will be set at the rates they 6

would revert to if auctions continue to fail during the rate years. I propose 7

to update these rates if market conditions normalize by the time a decision 8

is about to be reached in this proceeding. 9

10

In the event that markets do not return to normal, I recommend that the 11

interest expense on auction rate debt that is allocated to electric operations 12

be fully reconciled whereby differences between the actual expense and 13

the level reflected in rates are deferred for future disposition by the 14

Commission. This true-up mechanism would be identical to that approved 15

by the Commission in Case 08-G-0609 for interest expense on the same 16

variable rate debt that is allocated to the Company’s gas operations. 17

18

Also included in the cost of the Company’s long-term debt are the 19

amortizations of call premiums and debt discounts and expenses (DD&E) 20

associated with several debt issues that were retired before maturity 21

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because it was economically advantageous to do so. These costs are being 1

amortized over the remaining life of the respective bonds as if they had 2

not been retired early. It is estimated that on a present value basis, the 3

early retirement of these bonds will save in excess of $75 million net of 4

the recovery of call premiums and unamortized DD&E. 5

6

Dividing the total interest, fee and amortization expense for the notes and 7

bonds by the average principal outstanding yields an effective rate of 8

5.03% for the long-term debt component of Niagara Mohawk’s 9

capitalization for the 2011 rate year, 5.58% for the 2012 rate year and 10

6.12% for the 2013 rate year. 11

12

Q. How were the projected cost rates of preferred stock and short-term 13

debt shown on Exhibit __ (AED-1) derived? 14

A. The Company currently has three perpetual issues of preferred stock that 15

will remain outstanding during the three proposed rate years. The total 16

annual dividend requirement for these three issues was divided by the total 17

average net proceeds outstanding during the rate years, yielding an 18

effective rate of 3.62% for the preferred stock component of Niagara 19

Mohawk’s capitalization. Also, during the rate years, it was assumed that 20

the Company would be charged National Grid’s commercial paper rate on 21

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the forecasted average balance of short-term debt borrowed from National 1

Grid’s regulated money pool. Those rates are projected to be 2.21% for 2

the 2011 rate year, 3.28% for the 2012 rate year and 4.28% for the 2013 3

rate year. 4

5

Q. How were the balances and the cost rate for customer deposits shown 6

on Exhibit __ (AED-1) determined? 7

A. Niagara Mohawk’s forecasted balances of customer deposits were 8

assumed to remain equal to the actual monthly balance as of September 9

30, 2009, the end of the test year. The cost rate is the customer deposit 10

interest rate currently mandated by the Commission in a memo on this 11

matter. 12

13

Q. Do you believe that it would be appropriate for the Company to 14

update its projections of both new debt issuances and cost rates later 15

in this proceeding? 16

A. Yes. Given the continuing uncertainty of the financial markets I believe 17

that it is in both the Company’s and its customers’ best interests for the 18

Company to update its filing to reflect the most recent information 19

available concerning both the Company’s financial plans and its cost 20

projections near the time of a Commission decision in this case. 21

176


Page 25 of 25

Q. What cost rate are you using for the common equity component of 1

Niagara Mohawk’s capital structure? 2

A. I am using a required rate of return of 11.1% as supported by Dr. Morin in 3

his testimony consistent with a 50% common equity ratio in the capital 4

structure. 5

6

Q. Does this conclude your direct testimony? 7

A. Yes. It does.8

177

Exhibits of

A

ndrew E. D

inkel

Index of Exhibits

Exhibit __ (AED-1) Capitalization and Weighted Average Cost of Capital Analysis

Exhibit __ (AED-2) Workpapers Supporting Exhibit __ (AED-1) Exhibit __ (AED-3) Standard & Poor’s and Moody’s Investors Service

Evaluations

178

Exhibit __ (A

ED-1)


Exhibit __ (AED-1)

Capitalization and Weighted Average Cost of Capital Analysis

179


Schedule 1

180

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182


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190


Schedule 3

191

Exhibit ___ (AED-1)Schedule 3Page 1 of 3

NIAGARA MOHAWK POWER CORPORATION d/b/a NATIONAL GRIDSources and Use of Funds Statement

And Financial Statistics($000)

Rate Year Sources of Funds Ending 12/31/11

Internal

Net Income 269,475

Depreciation & Amortization 497,208

Deferred Taxes (18,301)

Changes in Working Capital/Other (110,577)

Total Internal Sources 637,805

External Long-Term Debt 0 Money Pool Borrowings 372,664 Total External Sources 372,664

Total Sources of Funds 1,010,469

Uses of Funds

Capital Expenditures 760,409 Dividend Payments 250,060 Redemptions Long-Term Debt 0

Money Pool Debt 0

Total Uses of Funds 1,010,469

Pre-Tax Interest Coverage Ratio (x) 3.6

FFO Interest Coverage Ratio (x) 5.3

FFO/Debt 22.5%

Debt/EBITDA (x) 2.9

192





Internal

Net Income 271,992





External Long-Term Debt 400,000 Money Pool Borrowings 443,071 Total External Sources 843,071


Uses of Funds

Capital Expenditures 853,895 Dividend Payments 49,560 Redemptions Long-Term Debt 500,000

Money Pool Debt 0


Pre-Tax Interest Coverage Ratio 3.3

FFO Interest Coverage Ratio 4.1

FFO/Debt 18.9%

Debt/EBITDA (x) 2.9

193





Internal

Net Income 299,448





External Long-Term Debt 500,000 Money Pool Borrowings 0 Total External Sources 500,000


Uses of Funds

Capital Expenditures 899,786 Dividend Payments 1,060 Redemptions Long-Term Debt 45,600

Money Pool Debt 257,902


Pre-Tax Interest Coverage Ratio 3.6

FFO Interest Coverage Ratio 4.9

FFO/Debt 21.5%

Debt/EBITDA (x) 3.0

194

Exhibit __ (AED

-2)


Exhibit __ (AED-2)

Workpapers Supporting Exhibit __ (AED-1)

195

Exhibit __ (AED-2)Workpapers for Schedule 2Page 1 of 27

3m$ LIBOR

2009/2010 2010/2011 2011/2012 2012/2013 2013/2014Dec-09 0.30%Jan-10 0.30% Money Pool Interest RatesFeb-10 0.30% Calendar YearMar-10 0.35% 2011 2012 2013Apr-10 0.40% 2.21% 3.28% 4.28%May-10 0.50%Jun-10 0.50% Money pool interest rates are NationalJul-10 0.65% Grid's commercial paper rate which isAug-10 0.75% assumed to equal the 3 month LIBORSep-10 0.75% plus 40 basis points.Oct-10 1.00%Nov-10 1.25%Dec-10 1.25%Jan-11 1.50%Feb-11 1.50% Variable Rate Tax Exempt Debt Interest RatesMar-11 1.50% Calendar Year

2011 2012 2013Q1 1.50% 4.53% 7.19% 9.69%Q2 2.00%Q3 2.25% Rates assume debt auction marketsQ4 2.50% continue to fail. Under these

conditions, tax exempt debt rates areQ1 2.75% set at 2.5 times LIBORQ2 3.00%Q3 3.25%Q4 3.50%

Q1 3.75%Q2 4.00%Q3 4.25%Q4 4.50%

10-Year Long-Term Debt Interest Rates

June October June 2010 2012 2013

10-Year Treasury Interest Rate 3.54% 4.27% 4.91%

Spread Above Treasuries 126 BP 126 BP 126 BP

New Issuance Premium 10-15 BP 10-15 BP 10-15 BP

Approximate Total Spread 140 BP 140 BP 140 BP

10 Year Bond Coupon Rate 5.0% 5.6% 6.3%

196

Exhibit __ (AED-2) Workpapers for Schedule 2 Page 2 of 27

197


198


199


200

Exhibit __ (AED-2) Workpapers for Schedules 2 & 3 Page 6 of 27

Niagara Mohawk Power Corp Total Total TotalCalender Calender Calender

Income Statement 2011 2012 2013

Operating Revenue 3,772,478 3,737,186 3,683,574 Other Revenue 173,881 236,720 302,333 Total Revenue 3,946,359 3,973,905 3,985,907

Total Staff & Other Exp 1,318,767 1,343,579 1,333,614 Purchased Power - Electricity 973,009 973,004 973,002 Wheeling 342 352 377 Depreciation 240,878 254,500 270,225 Amortization 256,454 216,554 184,768 Purchased Gas 389,324 375,698 357,592 Operating Taxes 170,824 175,387 187,998 Total Operating Expenses 3,349,598 3,339,074 3,307,577

Operating Income 596,761 634,831 678,330

Net Interest Expense (144,743) (178,366) (178,204)

Current Taxes 200,844 305,432 217,879 Deferred Taxes (18,301) (120,959) (17,201) Total Taxes 182,543 184,472 200,678

Profit After Taxes 269,475 271,992 299,448

Preferred Dividends 1,060 1,060 1,060

Profit Attributed to Shareholders 268,415 270,932 298,388

Common Dividends 249,000 48,500 - Retained Profit 19,415 222,432 298,388

201

Exhibit __ (AED-2)Workpapers for Schedules 2 & 3Page 7 of 27

Niagara Mohawk Power Corp2011 Calendar 2012 Calendar 2013 Calendar

Cash Flow Statement Year Year Year

Operating Profit of Group 596,761 634,831 678,330

Total Depreciation and Amortization 497,208 470,927 454,863

Decrease/(increase) in stocks (8,115) (5,697) (3,636)

Decrease/(increase) in debtors 126,058 130,118 164,236

Increase/(decrease) in creditors (28,221) (27,361) (41,058)

Increase/(decrease) in provisions (26,525) (23,276) (18,695)

Pensions (205,863) (197,289) (187,461)

Net Cash From Operating Activities 951,302 982,252 1,046,579

Interest Received 4,067 1,915 366

Interest Paid (134,175) (136,051) (142,307)

Preferred Dividends (1,060) (1,060) (1,060)

Net Interest and Preferred Dividend Payments (131,167) (135,196) (143,001)

Common Dividends Paid (249,000) (48,500) 0

Corporate Income Taxes Paid (200,844) (305,432) (217,879)

Net Capex (760,409) (853,895) (899,786)

Share Capital Movements 15,074 15,320 15,211

Total Cash Movement in Net Debt (375,044) (345,450) (198,877)

202

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Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

FY20

11FY

2011

FY20

11FY

2011

FY20

12FY

2012

FY20

12FY

2012

FY20

12FY

2012

FY20

12FY

2012

FY20

12D

ecJa

nFe

bM

arA

prM

ayJu

nJu

lA

ugSe

pO

ctN

ovD

ec

ASS

ETS_

IN_C

ON

ST39

3,47

8

413,

814

43

5,70

3

459,

350

49

8,84

6

538,

795

57

9,16

3

619,

742

65

9,95

6

701,

205

74

1,59

2

781,

645

82

1,86

4

La

nd &

Bui

ldin

gs47

1,26

1

471,

261

47

1,26

1

471,

261

47

1,26

1

471,

261

47

1,26

1

471,

261

47

1,26

1

471,

261

47

1,26

1

471,

261

47

1,26

1

Po

rtabl

e &

Fre

esta

ndin

g11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

Pl

ant &

Mac

hine

ry8,

572,

191

8,29

2,21

0

8,

326,

751

8,38

0,30

1

8,

418,

049

8,46

7,16

6

8,

520,

573

8,56

7,73

4

8,

622,

885

8,68

2,31

8

8,

738,

124

8,78

6,29

0

8,

833,

643

La

nd &

Bui

ldin

gs A

ccum

Dep

r74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

Po

rtabl

e &

Fre

e A

ccum

Dep

r7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

Plan

t & M

achi

nery

Acc

um D

epr

2,76

3,94

2

2,

779,

100

2,79

4,66

2

2,

808,

566

2,81

9,21

4

2,

829,

193

2,83

8,52

9

2,

848,

561

2,86

5,35

5

2,

881,

761

2,89

8,59

9

2,

916,

491

2,93

4,24

9

Tang

ible

Fix

ed A

sset

s6,

601,

790

6,32

6,98

7

6,

367,

855

6,43

1,14

8

6,

497,

745

6,57

6,83

2

6,

661,

270

6,73

8,97

8

6,

817,

549

6,90

1,82

5

6,

981,

181

7,05

1,50

8

7,

121,

321

GO

OD

WIL

L1,

268,

004

1,26

8,00

4

1,

268,

004

1,26

8,00

4

1,

268,

004

1,26

8,00

4

1,

268,

004

1,26

8,00

4

1,

268,

004

1,26

8,00

4

1,

268,

004

1,26

8,00

4

1,

268,

004

O

ther

Inta

ngib

les

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

O

ther

Inta

ngib

les A

ccum

Am

ort

2,05

2

2,05

2

2,05

2

2,05

2

2,05

2

2,05

2

2,05

2

2,05

2

2,05

2

2,05

2

2,05

2

2,05

2

2,05

2

S

oftw

are

Inta

ng A

ccum

Am

ort

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

In

tang

ible

Ass

ets

1,26

4,91

0

1,

264,

910

1,26

4,91

0

1,

264,

910

1,26

4,91

0

1,

264,

910

1,26

4,91

0

1,

264,

910

1,26

4,91

0

1,

264,

910

1,26

4,91

0

1,

264,

910

1,26

4,91

0

Equi

ty In

vest

men

ts5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

Oth

er F

ixed

Ass

et In

vest

men

ts26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

Fi

xed

Ass

et In

vest

men

ts31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

FIX

ED_A

SSET

S7,

898,

698

7,62

3,89

4

7,

664,

762

7,72

8,05

5

7,

794,

653

7,87

3,73

9

7,

958,

178

8,03

5,88

5

8,

114,

456

8,19

8,73

2

8,

278,

088

8,34

8,41

6

8,

418,

229

Tota

l Sto

cks

110,

370

84

,134

62,0

95

45

,267

53,2

94

70

,420

90,0

98

11

1,15

8

128,

897

14

0,77

6

148,

417

14

2,60

9

118,

485

Cus

tom

er A

R46

8,38

7

542,

998

57

0,83

8

530,

235

49

7,47

8

464,

325

47

3,96

0

472,

066

49

8,45

6

465,

755

40

7,47

8

482,

819

50

7,70

6

O

ther

AR

37,6

62

30

7,66

2

307,

662

30

7,66

2

307,

662

30

7,66

2

307,

662

30

7,66

2

307,

662

30

7,66

2

307,

662

30

7,66

2

307,

662

AR

_FR

OM

_ASS

OC

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

D

ebto

rs L

edge

r51

2,64

2

857,

252

88

5,09

2

844,

489

81

1,73

2

778,

579

78

8,21

5

786,

321

81

2,71

1

780,

010

72

1,73

2

797,

074

82

1,96

1

Acc

um P

rov

for U

ncol

l Acc

ts-C

R17

8,25

0

178,

074

17

7,87

9

177,

587

17

7,54

9

177,

479

17

7,38

7

177,

272

17

7,11

9

177,

091

17

7,15

6

177,

349

17

7,51

1

U

nbill

ed R

even

ue15

3,37

0

150,

497

14

4,61

5

153,

049

14

9,07

7

152,

188

13

9,50

8

158,

643

16

1,83

6

140,

214

14

4,05

7

133,

808

15

3,37

0

M

isc

Cur

r & A

ccru

ed A

sset

s2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

Acc

rued

Deb

tors

(22,

789)

(2

5,48

6)

(31,

173)

(2

2,44

7)

(26,

381)

(2

3,20

0)

(35,

787)

(1

6,53

7)

(13,

192)

(3

4,78

6)

(31,

007)

(4

1,45

0)

(22,

050)

PREP

AY

MEN

TS88

,541

128,

370

10

4,43

9

138,

307

11

4,22

4

89,2

46

67

,177

49,2

10

24

,664

162,

997

13

7,94

8

112,

899

87

,850

IN

T_D

IV_R

EC34

4

37

9

37

4

40

9

71

8

85

8

69

1

37

6

35

8

23

7

68

68

68

NO

TES_

REC

321,

045

22

7,78

0

312,

679

28

8,03

8

345,

667

42

4,66

8

182,

545

11

8,12

7

164,

892

73

73

73

73

Mis

c D

ebto

rs -

Cur

rent

391,

255

39

1,25

5

391,

255

39

1,25

5

391,

255

39

1,25

5

391,

255

39

1,25

5

391,

255

39

1,25

5

391,

255

39

1,25

5

391,

255

Mis

c D

ebto

rs N

on-C

urre

nt1,

184,

015

1,11

9,59

6

1,

054,

681

993,

269

93

8,09

6

883,

929

83

2,57

2

777,

412

72

1,15

4

667,

953

60

9,48

5

550,

313

49

2,26

1

U

nam

ortiz

ed D

ebt E

xp21

,694

21,4

96

21

,298

21,1

00

20

,901

20,7

03

20

,505

20,3

07

20

,108

19,9

10

19

,712

19,5

14

19

,315

M

isce

llane

ous D

ebto

rs1,

596,

964

1,53

2,34

7

1,

467,

233

1,40

5,62

3

1,

350,

252

1,29

5,88

7

1,

244,

331

1,18

8,97

3

1,

132,

517

1,07

9,11

8

1,

020,

452

961,

081

90

2,83

1

Tota

l Deb

tors

2,49

6,74

7

2,

720,

641

2,73

8,64

5

2,

654,

419

2,59

6,21

1

2,

566,

038

2,24

7,17

1

2,

126,

469

2,12

1,94

9

1,

987,

648

1,84

9,26

5

1,

829,

744

1,79

0,73

1

Cas

h an

d C

ash

Equi

vila

nts

21,4

39

21

,439

21,4

39

21

,439

21,4

39

21

,439

21,4

39

21

,439

21,4

39

21

,439

21,4

39

21

,439

21,4

39

Fina

ncia

l Inv

estm

ents

46,8

63

46

,863

46,8

63

46

,863

46,8

63

46

,863

46,8

63

46

,863

46,8

63

46

,863

46,8

63

46

,863

46,8

63

TOT_

CA

SH68

,302

68,3

02

68

,302

68,3

02

68

,302

68,3

02

68

,302

68,3

02

68

,302

68,3

02

68

,302

68,3

02

68

,302

Acc

ts P

ayab

le36

6,33

4

297,

281

30

0,08

4

297,

534

28

3,34

8

273,

146

28

5,86

1

296,

597

39

1,01

9

268,

980

26

2,97

9

266,

735

37

7,66

5

A

P_TO

_ASS

OC

67,1

78

67

,178

67,1

78

67

,178

67,1

78

67

,178

67,1

78

67

,178

67,1

78

67

,178

67,1

78

67

,178

67,1

78

Trad

e C

redi

tors

433,

512

36

4,45

9

367,

262

36

4,71

2

350,

526

34

0,32

4

353,

039

36

3,77

5

458,

197

33

6,15

8

330,

157

33

3,91

3

444,

843


203

Exhi

bit _

_ (A

ED-2

)W

orkp

aper

s for

Sch

edul

es 2

& 3

Page

9 o

f 27

Nia

gara

Moh

awk

Pow

er C

orp

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nB

alan

ce S

heet

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

Cur

rent

FY20

11FY

2011

FY20

11FY

2011

FY20

12FY

2012

FY20

12FY

2012

FY20

12FY

2012

FY20

12FY

2012

FY20

12D

ecJa

nFe

bM

arA

prM

ayJu

nJu

lA

ugSe

pO

ctN

ovD

ec

Inte

rest

Acc

rued

56,5

92

62

,602

50,3

08

56

,318

52,5

47

57

,658

62,7

70

68

,480

55,8

87

61

,597

58,7

25

64

,734

70,7

44

Inte

rest

Acc

rued

NM

Hol

ding

s13

,134

13,1

34

13

,134

13,1

34

13

,134

13,1

34

13

,134

13,1

34

13

,134

13,1

34

13

,134

13,1

34

13

,134

IN

TER

EST_

AC

CR

_ASS

OC

25

25

25

25

25

25

25

25

25

24

6

42

0

35

2

23

2

Tota

l Int

eres

t Acc

rued

69,7

51

75

,761

63,4

67

69

,477

65,7

06

70

,818

75,9

29

81

,639

69,0

46

74

,978

72,2

79

78

,221

84,1

11

Not

es P

ayab

le to

NM

Hol

ding

s50

0,00

0

500,

000

50

0,00

0

500,

000

50

0,00

0

500,

000

50

0,00

0

500,

000

50

0,00

0

500,

000

50

0,00

0

-

-

N

OTE

S_PA

YA

BLE

_ASS

OC

-

-

-

-

-

-

-

-

-

21

5,55

9

169,

133

15

0,00

3

51,6

92

NO

TES_

PAY

AB

LE50

0,00

0

500,

000

50

0,00

0

500,

000

50

0,00

0

500,

000

50

0,00

0

500,

000

50

0,00

0

715,

559

66

9,13

3

150,

003

51

,692

LTD

Due

in O

ne Y

ear

-

-

-

-

-

-

-

-

-

-

-

50

0,00

0

500,

000

C

omm

erci

al P

aper

-

-

-

-

-

-

-

-

-

-

-

-

-

Bor

row

ings

-

-

-

-

-

-

-

-

-

-

-

50

0,00

0

500,

000

Cur

rent

Tax

Lia

bilit

ies

113,

231

14

0,69

6

166,

759

11

3,23

1

133,

848

15

2,26

2

165,

828

12

8,73

4

140,

086

11

3,23

1

121,

975

13

4,07

2

113,

231

O

ther

Tax

14,1

88

(3

8,57

8)

(2

7,59

7)

(1

6,71

9)

(5

,613

)

6,

387

15

,479

20,4

68

32

,037

(61,

580)

(49,

508)

(37,

436)

(25,

364)

O

ther

Tax

es <

1Yr

127,

419

10

2,11

9

139,

163

96

,511

128,

235

15

8,64

9

181,

307

14

9,20

2

172,

123

51

,651

72,4

66

96

,635

87,8

66

Mis

c C

urr &

Acc

r Lia

bilit

ies

87,4

66

80

,020

72,5

74

65

,129

57,6

83

92

,315

87,4

66

80

,020

72,5

74

65

,129

57,6

83

92

,315

87,4

66

CA

P_LE

ASE

S <

1YR

595

595

595

595

595

595

595

595

595

595

595

595

595

M

isc

Oth

er C

redi

tors

88,0

61

80

,615

73,1

69

65

,724

58,2

78

92

,910

88,0

61

80

,615

73,1

69

65

,724

58,2

78

92

,910

88,0

61

CU

ST_D

EPO

SITS

36,7

94

36

,794

36,7

94

36

,794

36,7

94

36

,794

36,7

94

36

,794

36,7

94

36

,794

36,7

94

36

,794

36,7

94

DIV

S_D

ECL_

PREF

265

265

265

265

265

265

265

265

265

265

265

265

265

M

isc

Payr

oll

49,6

35

49

,635

49,6

35

49

,635

49,6

35

49

,635

49,6

35

49

,635

49,6

35

49

,635

49,6

35

49

,635

49,6

35

Sub

tota

l Mis

c C

redi

tors

86,6

94

86

,694

86,6

94

86

,694

86,6

94

86

,694

86,6

94

86

,694

86,6

94

86

,694

86,6

94

86

,694

86,6

94

Tota

l Cre

dito

rs1,

305,

436

1,20

9,64

7

1,

229,

755

1,18

3,11

8

1,

189,

440

1,24

9,39

6

1,

285,

030

1,26

1,92

5

1,

359,

229

1,33

0,76

3

1,

289,

008

1,33

8,37

7

1,

343,

267

Net

Cur

rent

Ass

ets

1,36

9,98

3

1,

663,

430

1,63

9,28

7

1,

584,

871

1,52

8,36

8

1,

455,

364

1,12

0,54

2

1,

044,

004

959,

918

86

5,96

4

776,

976

70

2,27

8

634,

252

Long

-Ter

m D

ebt

2,25

0,06

5

2,

250,

065

2,25

0,06

5

2,

250,

065

2,25

0,06

5

2,

250,

065

2,25

0,06

5

2,

250,

065

2,25

0,06

5

2,

250,

065

2,25

0,06

5

2,

250,

065

2,25

0,06

5

U

NA

MO

RT_

DIS

C_D

EBT

(498

)

(498

)

(498

)

(498

)

(498

)

(498

)

(498

)

(498

)

(498

)

(498

)

(498

)

(498

)

(498

)

B

OR

RO

W_L

ON

G_T

ERM

2,24

9,56

7

2,

249,

567

2,24

9,56

7

2,

249,

567

2,24

9,56

7

2,

249,

567

2,24

9,56

7

2,

249,

567

2,24

9,56

7

2,

249,

567

2,24

9,56

7

2,

249,

567

2,24

9,56

7

DEF

ERR

ED_I

TC28

,018

28,0

18

28

,018

28,0

18

28

,018

28,0

18

28

,018

28,0

18

28

,018

28,0

18

28

,018

28,0

18

28

,018

Oth

er N

on C

urre

nt L

iabi

litie

s27

0,19

6

270,

196

27

0,19

6

270,

196

27

0,19

6

270,

196

27

0,19

6

270,

196

27

0,19

6

270,

196

27

0,19

6

270,

196

27

0,19

6

Cap

italiz

ed le

ases

2,08

3

2,08

3

2,08

3

2,08

3

2,08

3

2,08

3

2,08

3

2,08

3

2,08

3

2,08

3

2,08

3

2,08

3

2,08

3

O

ther

Cre

dit (

LTD

)27

2,27

9

272,

279

27

2,27

9

272,

279

27

2,27

9

272,

279

27

2,27

9

272,

279

27

2,27

9

272,

279

27

2,27

9

272,

279

27

2,27

9

DEF

ERR

ED_R

EV_L

T134

34

34

34

34

34

34

34

34

34

34

34

34

Def

erre

d Ta

xes P

rov

1,36

3,42

6

1,

361,

900

1,36

0,37

5

1,

358,

850

1,35

7,32

5

1,

355,

800

1,35

4,27

5

1,

352,

750

1,35

1,22

5

1,

349,

700

1,34

8,17

5

1,

346,

649

1,34

5,12

4

H

azar

dous

Was

te P

rov

386,

562

38

3,50

2

380,

783

37

6,70

3

376,

234

37

5,06

0

373,

886

37

2,00

8

369,

661

36

7,07

9

364,

497

36

2,14

9

360,

037

A

RO

Pro

visi

ons

10,1

49

10

,149

10,1

49

10

,149

10,1

49

10

,149

10,1

49

10

,149

10,1

49

10

,149

10,1

49

10

,149

10,1

49

Post

Em

ploy

men

t Ben

efit

Prov

31,5

47

31

,547

31,5

47

31

,547

31,5

47

31

,547

31,5

47

31

,547

31,5

47

31

,547

31,5

47

31

,547

31,5

47

Pens

ion

Prov

(91,

197)

(104

,964

)

(118

,731

)

(132

,498

)

(146

,814

)

(161

,129

)

(175

,445

)

(189

,761

)

(204

,076

)

(218

,392

)

(232

,708

)

(247

,023

)

(261

,339

)

Po

stre

tirem

ent H

ealth

Pro

v87

6,08

6

873,

068

87

0,05

0

867,

032

86

4,06

9

861,

106

85

8,14

3

855,

180

85

2,21

7

849,

254

84

6,29

1

843,

328

84

0,36

5

PRO

VIS

ION

S2,

576,

573

2,55

5,20

4

2,

534,

174

2,51

1,78

4

2,

492,

511

2,47

2,53

4

2,

452,

556

2,43

1,87

5

2,

410,

723

2,38

9,33

7

2,

367,

952

2,34

6,80

0

2,

325,

884

CR

EDIT

OR

S(5

,126

,472

)

(5

,105

,102

)

(5

,084

,072

)

(5

,061

,683

)

(5

,042

,409

)

(5

,022

,432

)

(5

,002

,454

)

(4

,981

,773

)

(4

,960

,622

)

(4

,939

,236

)

(4

,917

,850

)

(4

,896

,699

)

(4

,875

,782

)

NET

_ASS

ETS

4,14

2,20

9

4,

182,

222

4,21

9,97

7

4,

251,

244

4,28

0,61

1

4,

306,

671

4,07

6,26

6

4,

098,

117

4,11

3,75

3

4,

125,

461

4,13

7,21

4

4,

153,

995

4,17

6,69

8

Com

mon

Sto

ck18

7,36

5

187,

365

18

7,36

5

187,

365

18

7,36

5

187,

365

18

7,36

5

187,

365

18

7,36

5

187,

365

18

7,36

5

187,

365

18

7,36

5

OC

I FA

S 15

8 - P

ensi

on10

,457

11,7

13

12

,968

14,2

23

15

,480

16,7

36

17

,993

19,2

49

20

,506

21,7

62

23

,019

24,2

75

25

,532

O

ther

Pai

d-in

Cap

ital

2,91

3,14

0

2,

913,

140

2,91

3,14

0

2,

913,

140

2,91

3,14

0

2,

913,

140

2,91

3,14

0

2,

913,

140

2,91

3,14

0

2,

913,

140

2,91

3,14

0

2,

913,

140

2,91

3,14

0

U

napp

Und

ist S

ub E

arni

ngs

1,00

3,66

6

1,

042,

424

1,07

8,92

4

1,

108,

935

1,13

7,04

6

1,

161,

849

930,

188

95

0,78

2

965,

162

97

5,61

4

986,

110

1,

001,

635

1,02

3,08

1

U

nrea

lized

App

reci

atio

n on

Inv

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

(1,7

06)

Eq

uity

Sha

reho

lder

s Fun

ds4,

112,

923

4,15

2,93

6

4,

190,

691

4,22

1,95

8

4,

251,

325

4,27

7,38

5

4,

046,

980

4,06

8,83

1

4,

084,

468

4,09

6,17

5

4,

107,

928

4,12

4,70

9

4,

147,

413

Pref

erre

d St

ock

29,2

86

29

,286

29,2

86

29

,286

29,2

86

29

,286

29,2

86

29

,286

29,2

86

29

,286

29,2

86

29

,286

29,2

86

Tota

l Cap

italiz

atio

n4,

142,

209

4,18

2,22

2

4,

219,

977

4,25

1,24

4

4,

280,

611

4,30

6,67

1

4,

076,

266

4,09

8,11

7

4,

113,

753

4,12

5,46

1

4,

137,

214

4,15

3,99

5

4,

176,

698


204

Exhi

bit _

_ (A

ED-2

)W

orkp

aper

s for

Sch

edul

es 2

& 3

Page

10

of 2

7

Nia

gara

Moh

awk

Pow

er C

orp

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Bal

ance

She

etC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntFY

2012

FY20

12FY

2012

FY20

13FY

2013

FY20

13FY

2013

FY20

13FY

2013

FY20

13FY

2013

FY20

13Ja

nFe

bM

arA

prM

ayJu

nJu

lA

ugSe

pO

ctN

ovD

ec

ASS

ETS_

IN_C

ON

ST86

0,57

1

89

9,24

5

93

8,39

9

98

1,56

0

1,

025,

203

1,

069,

291

1,

113,

604

1,

157,

529

1,

202,

554

1,

246,

664

1,

290,

417

1,

334,

346

La

nd &

Bui

ldin

gs47

1,26

1

47

1,26

1

47

1,26

1

47

1,26

1

47

1,26

1

47

1,26

1

47

1,26

1

47

1,26

1

47

1,26

1

47

1,26

1

47

1,26

1

47

1,26

1

Po

rtabl

e &

Fre

esta

ndin

g11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

Pl

ant &

Mac

hine

ry8,

420,

028

8,

464,

336

8,

589,

869

8,

631,

809

8,

686,

272

8,

745,

395

8,

796,

113

8,

857,

047

8,

923,

825

8,

986,

616

9,

040,

738

9,

093,

540

La

nd &

Bui

ldin

gs A

ccum

Dep

r74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

Po

rtabl

e &

Fre

e A

ccum

Dep

r7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

Pl

ant &

Mac

hine

ry A

ccum

Dep

r2,

948,

544

2,

963,

436

2,

976,

511

2,

991,

381

3,

005,

482

3,

019,

090

3,

033,

537

3,

047,

399

3,

060,

822

3,

077,

544

3,

092,

288

3,

107,

233

Ta

ngib

le F

ixed

Ass

ets

6,73

2,11

9

6,80

0,20

8

6,95

1,82

0

7,02

2,05

1

7,10

6,05

6

7,19

5,66

0

7,27

6,24

3

7,36

7,24

0

7,46

5,62

0

7,55

5,79

9

7,63

8,93

0

7,72

0,71

6

GO

OD

WIL

L1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

O

ther

Inta

ngib

les

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

Oth

er In

tang

ible

s Acc

um A

mor

t2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

S

oftw

are

Inta

ng A

ccum

Am

ort

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

Inta

ngib

le A

sset

s1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

Equi

ty In

vest

men

ts5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

O

ther

Fix

ed A

sset

Inve

stm

ents

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

Fixe

d A

sset

Inve

stm

ents

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

FIX

ED_A

SSET

S8,

029,

027

8,

097,

116

8,

248,

728

8,

318,

958

8,

402,

964

8,

492,

568

8,

573,

150

8,

664,

147

8,

762,

528

8,

852,

707

8,

935,

838

9,

017,

624

Tota

l Sto

cks

89,3

51

64

,878

46,1

91

54

,478

72,1

35

92

,388

114,

009

130,

969

143,

136

150,

484

144,

506

124,

182

Cus

tom

er A

R60

0,63

0

64

0,68

3

60

0,31

4

55

4,79

8

50

9,78

2

51

4,01

8

50

6,08

6

52

8,58

2

48

8,34

3

42

2,02

2

49

3,75

5

51

4,31

8

O

ther

AR

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

AR

_FR

OM

_ASS

OC

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

Deb

tors

Led

ger

914,

885

954,

937

914,

568

869,

052

824,

036

828,

272

820,

340

842,

837

802,

598

736,

276

808,

009

828,

572

Acc

um P

rov

for U

ncol

l Acc

ts-C

R17

7,86

7

17

8,06

2

17

8,30

1

17

8,36

2

17

8,44

4

17

8,49

2

17

8,49

7

17

8,40

3

17

8,23

1

17

7,99

9

17

7,65

2

17

7,39

6

U

nbill

ed R

even

ue15

0,49

7

14

4,61

5

15

3,04

9

14

9,07

7

15

2,18

8

13

9,50

8

15

8,64

3

16

1,83

6

14

0,21

4

14

4,05

7

13

3,80

8

15

3,37

0

M

isc

Cur

r & A

ccru

ed A

sset

s2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

A

ccru

ed D

ebto

rs(2

5,27

9)

(3

1,35

6)

(2

3,16

0)

(2

7,19

3)

(2

4,16

4)

(3

6,89

3)

(1

7,76

3)

(1

4,47

6)

(3

5,92

6)

(3

1,85

1)

(4

1,75

3)

(2

1,93

5)

PREP

AY

MEN

TS12

9,96

4

10

4,91

5

13

8,26

5

11

3,05

1

86

,893

63,8

00

45

,023

19,3

18

16

2,72

4

13

6,49

0

11

0,25

6

84

,021

INT_

DIV

_REC

248

441

329

307

430

415

194

79

79

68

68

68

NO

TES_

REC

176,

114

188,

229

66,3

47

96

,623

150,

536

86,2

11

73

8,

115

73

73

73

73

Mis

c D

ebto

rs -

Cur

rent

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

Mis

c D

ebto

rs N

on-C

urre

nt43

2,81

1

37

5,01

7

32

0,93

7

30

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6

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68,3

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68

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Acc

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1,25

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6

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,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

11

,355

11,3

55

Pl

ant &

Mac

hine

ry8,

738,

415

8,

787,

189

8,

865,

229

8,

907,

408

8,

962,

319

9,

021,

968

9,

073,

070

9,

134,

561

9,

201,

991

9,

265,

369

9,

319,

934

9,

373,

156

La

nd &

Bui

ldin

gs A

ccum

Dep

r74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

74

,749

74,7

49

Po

rtabl

e &

Fre

e A

ccum

Dep

r7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

7,

804

Pl

ant &

Mac

hine

ry A

ccum

Dep

r3,

119,

392

3,

132,

226

3,

143,

030

3,

156,

702

3,

173,

217

3,

189,

075

3,

205,

806

3,

221,

930

3,

237,

677

3,

253,

901

3,

271,

028

3,

288,

323

Ta

ngib

le F

ixed

Ass

ets

7,39

5,75

4

7,47

3,98

1

7,58

4,01

2

7,65

6,39

6

7,73

9,23

1

7,82

7,98

0

7,90

7,57

1

7,99

7,70

4

8,09

5,43

7

8,18

7,57

3

8,26

9,57

9

8,35

0,27

7

GO

OD

WIL

L1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

1,

268,

004

O

ther

Inta

ngib

les

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

6,36

0

Oth

er In

tang

ible

s Acc

um A

mor

t2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

2,

052

S

oftw

are

Inta

ng A

ccum

Am

ort

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

7,40

3

Inta

ngib

le A

sset

s1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

1,

264,

910

Equi

ty In

vest

men

ts5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

5,

581

O

ther

Fix

ed A

sset

Inve

stm

ents

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

26,4

17

26

,417

Fixe

d A

sset

Inve

stm

ents

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

31,9

98

31

,998

FIX

ED_A

SSET

S8,

692,

662

8,

770,

889

8,

880,

920

8,

953,

304

9,

036,

139

9,

124,

888

9,

204,

479

9,

294,

612

9,

392,

345

9,

484,

481

9,

566,

487

9,

647,

185

Tota

l Sto

cks

96,6

85

65

,696

46,4

62

54

,847

72,6

96

93

,183

115,

060

133,

468

145,

793

153,

273

149,

636

127,

818

Cus

tom

er A

R60

8,62

2

64

9,01

8

60

5,42

3

55

9,09

7

51

4,21

5

51

9,06

6

51

1,31

9

53

4,18

1

49

3,44

3

42

5,65

4

49

9,08

4

51

9,55

0

O

ther

AR

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

307,

662

122,

674

122,

674

122,

674

122,

674

AR

_FR

OM

_ASS

OC

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

6,59

2

Deb

tors

Led

ger

922,

876

963,

273

919,

677

873,

351

828,

469

833,

321

825,

573

848,

435

622,

710

554,

921

628,

350

648,

817

Acc

um P

rov

for U

ncol

l Acc

ts-C

R17

6,88

6

17

6,61

8

17

6,28

5

17

6,18

2

17

5,98

6

17

5,78

2

17

5,55

8

17

5,18

8

17

4,90

9

17

4,70

1

17

4,53

2

17

4,45

6

U

nbill

ed R

even

ue15

0,49

7

14

4,61

5

15

3,04

9

14

9,07

7

15

2,18

8

13

9,50

8

15

8,64

3

16

1,83

6

14

0,21

4

14

4,05

7

13

3,80

8

15

3,37

0

M

isc

Cur

r & A

ccru

ed A

sset

s2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

2,

091

A

ccru

ed D

ebto

rs(2

4,29

8)

(2

9,91

2)

(2

1,14

5)

(2

5,01

3)

(2

1,70

7)

(3

4,18

2)

(1

4,82

3)

(1

1,26

1)

(3

2,60

4)

(2

8,55

3)

(3

8,63

3)

(1

8,99

5)

PREP

AY

MEN

TS12

9,58

2

10

3,34

7

13

6,24

6

10

9,70

2

82

,140

57,8

61

38

,184

11,1

05

16

1,54

3

13

3,90

0

10

6,25

7

78

,615

INT_

DIV

_REC

68

68

68

68

68

216

216

102

102

68

68

68

NO

TES_

REC

73

73

73

73

73

78,9

40

73

18

,189

73

73

73

73

Mis

c D

ebto

rs -

Cur

rent

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

391,

255

Mis

c D

ebto

rs N

on-C

urre

nt12

5,81

8

11

0,62

5

99

,386

86,4

34

74

,318

64,9

19

51

,628

37,2

10

25

,928

9,34

1

(7,8

33)

(23,

833)

Una

mor

tized

Deb

t Exp

16,7

38

16

,540

16,3

41

16

,143

15,9

45

15

,747

15,5

48

15

,350

15,1

52

14

,954

14,7

55

14

,557

Mis

cella

neou

s Deb

tors

533,

811

518,

419

506,

982

493,

832

481,

518

471,

920

458,

431

443,

814

432,

334

415,

549

398,

177

381,

978

Tota

l Deb

tors

1,56

2,11

1

1,55

5,26

8

1,54

1,90

1

1,45

2,01

2

1,37

0,56

0

1,40

8,07

6

1,30

7,65

4

1,31

0,38

4

1,18

4,15

7

1,07

5,95

7

1,09

4,29

2

1,09

0,55

5

Cas

h an

d C

ash

Equi

vila

nts

21,4

39

21

,439

21,4

39

21

,439

21,4

39

21

,439

21,4

39

21

,439

21,4

39

21

,439

21,4

39

21

,439

Fina

ncia

l Inv

estm

ents

46,8

63

46

,863

46,8

63

46

,863

46,8

63

46

,863

46,8

63

46

,863

46,8

63

46

,863

46,8

63

46

,863

TOT_

CA

SH68

,302

68,3

02

68

,302

68,3

02

68

,302

68,3

02

68

,302

68,3

02

68

,302

68,3

02

68

,302

68,3

02

Acc

ts P

ayab

le31

1,40

0

30

0,01

6

30

5,21

8

28

1,59

7

27

4,98

4

28

6,80

5

29

5,82

3

41

0,52

8

27

2,03

2

25

9,34

3

26

6,64

4

38

9,70

7

A

P_TO

_ASS

OC

67,1

78

67

,178

67,1

78

67

,178

67,1

78

67

,178

67,1

78

67

,178

67,1

78

67

,178

67,1

78

67

,178

Trad

e C

redi

tors

378,

578

367,

194

372,

396

348,

775

342,

162

353,

983

363,

000

477,

706

339,

210

326,

521

333,

822

456,

884


207

Exhi

bit_

___

(AED

-2)

Wor

kpap

ers f

or S

ched

ules

2 &

3Pa

ge 1

3 of

27

Nia

gara

Moh

awk

Pow

er C

orp

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Cur

rent

_Pla

nC

urre

nt_P

lan

Bal

ance

She

etC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntC

urre

ntFY

2013

FY20

13FY

2013

FY20

14FY

2014

FY20

14FY

2014

FY20

14FY

2014

FY20

14FY

2014

FY20

14Ja

nFe

bM

arA

prM

ayJu

nJu

lA

ugSe

pO

ctN

ovD

ec

Inte

rest

Acc

rued

120,

821

10

9,66

6

116,

815

11

5,38

1

122,

829

13

0,27

7

138,

025

12

7,46

9

135,

217

13

4,36

4

142,

394

15

0,42

3

Inte

rest

Acc

rued

NM

Hol

ding

s13

,134

13,1

34

13

,134

13,1

34

13

,134

13,1

34

13

,134

13,1

34

13

,134

13,1

34

13

,134

13,1

34

IN

TER

EST_

AC

CR

_ASS

OC

1,27

4

1,09

3

1,26

4

1,74

4

1,59

5

765

55

55

513

1,06

1

1,14

7

1,04

6

Tota

l Int

eres

t Acc

rued

135,

229

12

3,89

4

131,

213

13

0,25

9

137,

558

14

4,17

6

151,

214

14

0,65

9

148,

865

14

8,55

9

156,

675

16

4,60

4

Not

es P

ayab

le to

NM

Hol

ding

s-

-

-

-

-

-

-

-

-

-

-

-

N

OTE

S_PA

YA

BLE

_ASS

OC

355,

548

37

1,73

7

471,

629

44

0,28

3

392,

370

-

15,9

07

-

258,

963

29

0,43

5

304,

852

23

6,86

1

NO

TES_

PAY

AB

LE35

5,54

8

371,

737

47

1,62

9

440,

283

39

2,37

0

-

15

,907

-

25

8,96

3

290,

435

30

4,85

2

236,

861

LTD

Due

in O

ne Y

ear

45,6

00

45

,600

45,6

00

45

,600

45,6

00

45

,600

45,6

00

45

,600

45,6

00

-

-

-

Com

mer

cial

Pap

er-

-

-

-

-

-

-

-

-

-

-

-

B

orro

win

gs45

,600

45,6

00

45

,600

45,6

00

45

,600

45,6

00

45

,600

45,6

00

45

,600

-

-

-

Cur

rent

Tax

Lia

bilit

ies

139,

738

16

4,63

7

113,

231

13

7,21

3

152,

023

16

5,08

5

129,

947

14

4,66

1

113,

231

12

5,96

6

141,

135

11

3,23

1

Oth

er T

ax(1

24,2

01)

(1

11,4

00)

(9

8,71

6)

(8

5,92

2)

(7

2,11

1)

(6

1,58

3)

(5

5,65

6)

(4

2,32

8)

(1

47,5

01)

(1

33,6

09)

(1

19,7

17)

(1

05,8

25)

O

ther

Tax

es <

1Yr

15,5

36

53

,237

14,5

14

51

,290

79,9

12

10

3,50

2

74,2

91

10

2,33

3

(34,

271)

(7,6

44)

21,4

17

7,

405

Mis

c C

urr &

Acc

r Lia

bilit

ies

80,0

20

72

,574

65,1

29

57

,683

92,3

15

87

,466

80,0

20

72

,574

65,1

29

57

,683

92,3

15

87

,466

CA

P_LE

ASE

S <

1YR

595

595

595

595

595

595

595

595

595

595

595

595

Mis

c O

ther

Cre

dito

rs80

,615

73,1

69

65

,724

58,2

78

92

,910

88,0

61

80

,615

73,1

69

65

,724

58,2

78

92

,910

88,0

61

CU

ST_D

EPO

SITS

36,7

94

36

,794

36,7

94

36

,794

36,7

94

36

,794

36,7

94

36

,794

36,7

94

36

,794

36,7

94

36

,794

DIV

S_D

ECL_

PREF

265

265

265

265

265

265

265

265

265

265

265

265

Mis

c Pa

yrol

l49

,635

49,6

35

49

,635

49,6

35

49

,635

49,6

35

49

,635

49,6

35

49

,635

49,6

35

49

,635

49,6

35

S

ubto

tal M

isc

Cre

dito

rs86

,694

86,6

94

86

,694

86,6

94

86

,694

86,6

94

86

,694

86,6

94

86

,694

86,6

94

86

,694

86,6

94

Tota

l Cre

dito

rs1,

097,

801

1,12

1,52

6

1,

187,

771

1,16

1,17

9

1,

177,

206

822,

016

81

7,32

2

926,

160

91

0,78

5

902,

844

99

6,37

1

1,04

0,51

0

Net

Cur

rent

Ass

ets

629,

297

56

7,74

0

468,

895

41

3,98

1

334,

351

74

7,54

5

673,

694

58

5,99

4

487,

467

39

4,68

9

315,

859

24

6,16

6

Long

-Ter

m D

ebt

2,60

4,46

5

2,

604,

465

2,60

4,46

5

2,

604,

465

2,60

4,46

5

3,

104,

465

3,10

4,46

5

3,

104,

465

3,10

4,46

5

3,

104,

465

3,10

4,46

5

3,

104,

465

UN

AM

OR

T_D

ISC

_DEB

T(4

98)

(4

98)

(4

98)

(4

98)

(4

98)

(4

98)

(4

98)

(4

98)

(4

98)

(4

98)

(4

98)

(4

98)

B

OR

RO

W_L

ON

G_T

ERM

2,60

3,96

7

2,

603,

967

2,60

3,96

7

2,

603,

967

2,60

3,96

7

3,

103,

967

3,10

3,96

7

3,

103,

967

3,10

3,96

7

3,

103,

967

3,10

3,96

7

3,

103,

967

DEF

ERR

ED_I

TC28

,018

28,0

18

28

,018

28,0

18

28

,018

28,0

18

28

,018

28,0

18

28

,018

28,0

18

28

,018

28,0

18

Oth

er N

on C

urre

nt L

iabi

litie

s27

0,19

6

270,

196

27

0,19

6

270,

196

27

0,19

6

270,

196

27

0,19

6

270,

196

27

0,19

6

270,

196

27

0,19

6

270,

196

C

apita

lized

leas

es2,

083

2,

083

2,

083

2,

083

2,

083

2,

083

2,

083

2,

083

2,

083

2,

083

2,

083

2,

083

O

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214

Exhibit___ (AED-2)Workpapers for TestimonyPage 20 of 27

National National Consolidating schedules Grid Grid as at 31 March 2009 plc plc

US GAAP US GAAP consolidated consolidated

£'m $'mCondensed balance sheetGoodwill 7,570 10,877 Other intangible assets 215 309 Property, plant & equipment 30,937 44,450 Investments in subsidiaries - - Investments 364 523 Non-current regulatory assets 4,689 6,737 Non Current Financial Derivative assets 1,533 2,203 Other non-current assets 375 539

Intercompany receivables -

Inventories 556 799 Receivables and other current assets 2,636 3,787 Regulatory assets 89 128 Current Financial Derivative assets 593 852 Financial and other investments 441 634 Cash and cash equivalents 2,574 3,698

Assets of businesses held for sale -

Total assets 52,572 75,535

Borrowings (including bank overdrafts) (2,872) (4,126)Current Financial Derivative liabilities (307) (441)Current liabilities (3,618) (5,198)Current tax liabilities (328) (471)

Intercompany payables 0

Non-current borrowings (22,764) (32,707)Non Current Financial Derivative liabilities (633) (909)Other non-current liabilities (4,212) (6,052)Deferred tax liabilities (4,762) (6,842)Pensions and other post-retirement benefits (3,093) (4,444)

Liabilities of businesses held for sale 0 0

Total liabilities (42,589) (61,192)

Shareholders' equity (9,945) (14,289)

Minority interests (38) (55)

Total liabilities and equity (52,572) (75,535)

Share holders equity 9,945Net Debt (21,435)

Equity Ratio 31.7%

215


£'m

US GAAP

Remove NGGas and NGET equity

After NGGas and NGET equity removal

Add NGET RAV

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Add NGGas Metering Net Asset Value

RAV adjusted US GAAP

Share holders equity 9,945 (15,045) (5,100) 6,720 6,550 4,281 603 13,054Net Debt (21,435) (21,435) (21,435) (21,435) (21,435) (21,435) (21,435) (21,435)

Equity Proportion 31.7% 37.8%

216


US GAAPIFRS adj US GAAP

Retranslation of 31/3/09 gross assets at 31/3/08 exchange rate

NGUSA gross assets (excluding debt, intercompany, investment in subs) USD 20,961 2,276 23,237At March 08 rate GBP 10,562 11,709At March 09 rate GBP 14,589 16,173Impact on gross assets 4,026 4,463

March 08 rate 1.9845 1.9845March 09 rate 1.4368 1.4368

Retranslation of 31/3/09 debt at 31/3/08 exchange rate

USIFRS GAAP adj US GAAP

Closing net debt - IFRS USD (5,732) 546 (5,186)UK USD debt USD (14,035) (14,035)Total USD debt USD (19,767) 546 (19,221)

At March 08 rate GBP (9,961) (9,686)At March 09 rate GBP (13,758) (13,378)

Impact on net debt (3,797) (3,692)

March 08 rate 1.9845 1.9845March 09 rate 1.4368 1.4368

IFRS US GAAPImpact on gross assets (4,026) (4,463)Impact on net debt 3,797 3,692Impact on Net Assets/Shareholders equity (229) (771)

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Standard & Poor’s and Moody’s Investors Service Evaluations

223


Schedule 1

224

Global Credit ResearchCredit Opinion

22 JUL 2009

Credit Opinion: Niagara Mohawk Power Corporation

Niagara Mohawk Power Corporation

Syracuse, New York, United States

[1][2]

[1] All ratios calculated in accordance with the Global Regulated Electric Utilities Rating Methodology usingMoody's standard adjustments [2] Fiscal Year End March 31st

Note: For definitions of Moody's most common ratio terms please see the accompanying User's Guide.

Rating Drivers

Generally low risk electric and gas transmission and distribution (T&D) operations

Regulatory support under performance-based rate plans in New York

Ratings

Category Moody's RatingOutlook StableIssuer Rating A3Senior Secured A2Senior Unsecured MTN A3Preferred Stock Baa2Ult Parent: National Grid PlcOutlook StableIssuer Rating Baa1Senior Unsecured Baa1Commercial Paper P-2Other Short Term P-2Parent: National Grid USAOutlook StableIssuer Rating A3Senior Unsecured A3Commercial Paper P-2

Contacts

Analyst PhoneKevin G. Rose/New York 212.553.0389William L. Hess/New York 212.553.3837

Key Indicators

Niagara Mohawk Power CorporationFY 2009 FY 2008 FY 2007 FY 2006

(CFO Pre-W/C + Interest) / Interest Expense 5.7 4.9 5.5 4.4(CFO Pre-W/C) / Debt 28% 28% 31% 21%(CFO Pre-W/C - Dividends) / Debt 28% 28% 31% 21%(CFO Pre-W/C - Dividends) / Capex 165% 225% 306% 316%Debt / Book Capitalization 30% 35% 37% 42%EBITA Margin % 23% 24% 24% 24%

Opinion


225

Sound financial performance expected to continue

Significant financial and operational interdependencies within the National Grid family

Corporate Profile

Niagara Mohawk Power Corporation (NiMo), is a wholly-owned subsidiary of National Grid USA (NG USA), whichis the United States-based intermediate level holding company for the U.S. regulated utility businesses ultimatelyowned by National Grid plc, a holding company headquartered in the United Kingdom (UK) for a range of largelyregulated T&D businesses in the U.S. and the UK.

NiMo provides electric T&D service in upstate New York and delivers natural gas in eastern, northern, and centralNew York. NiMo's retail rates are subject to the jurisdiction of the New York Public Service Commission (NYPSC).

SUMMARY RATING RATIONALE

Using the Moody's Rating Methodology for Global Regulated Electric Utilities in concert to some degree with theRating Methodology for European Complex Holding Company Structures as a framework, NiMo's A3 seniorunsecured rating reflects its favorable business and operating risk profile; support provided by the NYPSC whichhas allowed NiMo to institute a performance-based rate (PBR) plan that provides a means for the utility to receivecash recovery of its significant regulatory assets; key financial metrics in recent periods that are typical of A-ratedelectric T&D utility peers; and a liquidity position that is viewed as sufficient, albeit taking into account that NiMohas historically supplemented its internally generated cash flow by being an active borrower under the NG USAmoney pool.

DETAILED RATING CONSIDERATIONS

FAVORABLE BUSINESS, OPERATING, AND REGULATORY RISK PROFILES

NiMo's business activities remain entirely focused on the transmission and distribution of electricity and delivery ofnatural gas, which contributes to its generally low business risk profile. Since divesting its generation assets, NiMohas been recovering the significant regulatory assets created by the sales under the terms provided by the ten-year merger rate plan, which runs through February 2012. In particular, the rate plan provides for acceleratedamortization of the regulatory assets in the latter years, which is apparent in the favorable trend noted for keycredit metrics (see Financial Metrics below for more specifics). Also, NiMo is able to retain a portion of excessearnings above the allowed 10.6% return on equity as defined in the agreement.

Meanwhile, NiMo retains the provider of last resort (POLR) role for its electric customers. Supplies have beenroutinely arranged by purchasing power under long-term purchase power agreements (PPAs) and other openmarket purchases through the New York Independent System Operator. The arrangements with the NYPSC havebeen providing for generally timely and virtually full recovery of the costs associated with serving as the POLR.This is a heavily weighted consideration in our overall assessment of the degree of support provided to NiMo bythe NYPSC. Since commodity prices can tend to be volatile at times, any shift by the NYPSC to restrict timely andfull recovery of these costs could contribute to weaker financial results and downward rating pressure.

Although revenues generated by delivery of natural gas comprised only 20% of NiMo's consolidated revenues forFY'08, it is still important for NiMo to maintain sufficient access to the lowest possible cost supplies in fulfilling itsresponsibility to meet gas demands of retail customers in its franchise service territory. The company has donereasonably well in this regard, thanks in part to the multiple points of direct connections with interstate pipelines.The future financial performance of NiMo's gas distribution operations is expected to benefit from a recent gasdistribution rate case, which resulted in approval of a two-year settlement granting a $39.4 million rate increase inthe first year (new rates effective May 20, 2009) and rate adjustments in the second year to address a variety ofchanges in costs related to pension and post-retirement plans and environmental remediation, and to true up theactual cost of any new long-term debt. This outcome, resulting in the first gas delivery rate increase since 1996,also included approval of a revenue decoupling mechanism and expanded capital infrastructure investments,among other requests.

We note that strengthened regulatory ring fencing was introduced as required by the NYPSC when it approved theKeyspan acquisition in 2007, which affords additional insulation from the potential need for cash elsewhere withinthe family. While the ring fencing changes did not contribute to a change in NiMo's rating level, they are viewed asa credit positive, albeit to the possible detriment of creditworthiness elsewhere within the National Grid family.

Prospectively, we anticipate that NiMo will prepare to file a general electric rate case probably towards Q1-2010 inanticipation of expiration of its long-term merger rate plan in February 2012 and to address recovery of capitalexpenditures that will likely be in excess of recent periods. Our ratings assume that Niagara Mohawk will besuccessful in these filings, with new rates anticipated to take effect by January 2011, thereby establishing areasonable opportunity to earn on its utility investments and maintain earnings and cash flow levels to help sustainkey metrics at levels commensurate with what is typically seen for regulated utilities at the A3 senior unsecuredlevel. In the event that settlement negotiations are part of the process for future rate filings, we would likely expect


226

shorter tenors given current market dynamics and a desire to retain more flexibility with respect to timing of futurerate cases.

STRONG FINANCIAL METRICS EXPECTED TO BE THE NORM FOR MEDIUM TERM

Profitable utility operations and cash recovery through accelerated amortization of regulatory assets under the ten-year rate plan have resulted in healthy levels of positive free cash flow for NiMo over the past four years. NiMo hasused this cash to achieve significant reduction in the utility's gross debt level, which has contributed tocorresponding favorable improvements in key credit metrics. For FY 2009, NiMo's cash flow from operations(exclusive of changes in working capital) covered its interest and debt by 6.3x and 31.5%, respectively (subject topotential further adjustments upon clarification of underfunded pension obligations). Also, as of March 31, 2009,NiMo's adjusted debt to adjusted capitalization, calculated in accordance with Moody's Global Rating Methodologyfor Regulated Electric Utilities (i.e., including non-current deferred income taxes as part of total capitalization) was30.8% (subject to potential further adjustments upon clarification of underfunded pension obligations). These levelsleave NiMo comfortably positioned relative to peers. We note that the ultimate parent has not historically reliedupon NiMo for dividends; however, prospectively we would not be surprised to see the parent take dividends fromNiMo, consistent with financial strategies to realign the utility's capital structure with an equity level closer to thatused as a basis for establishing revenue requirements in rate case proceedings (i.e. 43.7% in NiMo's recentlyconcluded gas rate case). At the same time, it is our understanding that management will manage this realignmentprocess in a credit neutral way and we will be wary of any unexpected change in support provided to NiMo by theNYPSC that might jeopardize achieving this objective.

Liquidity

NiMo maintains sufficient liquidity by supplementing its cash on hand and internally generated cash flow fromoperating activities with borrowings from other NG USA companies through the inter-company money pool. Cashmanagement in the NG USA system is conducted through an inter-company pool, which serves as an investmentvehicle for the participants' excess cash as well as a relatively inexpensive short-term liquidity reserve. The qualityof alternate liquidity could, however, be improved upon in our opinion by arranging for more substantial committedstandalone multi-year bank credit facilities not burdened by a material adverse change clause. Participatingregulated utility subsidiary companies contribute their excess cash to the pool. The surplus cash invested in thepool is first used to meet the short-term borrowing needs of eligible subsidiaries. Companies borrowing from thepool pay rates linked to A1/P-1 30-day commercial paper rates. Any remaining cash is typically invested into Aaarated money funds with same day liquidity. As a measure of additional security, NG USA's parent, the UK-basedNational Grid plc, has the ability to increase the amount of cash in the pool through direct loans to NG USA.Alternatively, NG USA can also issue commercial paper and medium term notes in lieu of or to supplement directloans from the UK parent.

NiMo has historically been a borrower under the money pool and, while we expect that it will continue to takeadvantage of that source of short term funds, we anticipate that NiMo will revert in the near term to issuance ofthird party long-term debt to repay the large borrowings outstanding under the money pool as of March 31, 2009and as it moves ahead with its T&D utility capital expenditure plans. At this stage, NiMo has no standalone bankcredit facility. It does, however, have $100 million of sub-limit availability for letters of credit under a jointarrangement among NG USA and several other affiliates in the US, which expires November 29, 2009. We expectthat the need for this facility will be addressed within the context of an ongoing consolidated liquidity planningstrategy ahead of its expiration date. We are particularly focused on liquidity for corporate rated issuers,particularly in light of current bank market conditions, which make it likely that pricing will increase and tenors willbe shortened along with the possibility of stricter covenants and other conditionality. The existing joint arrangementhas a traditional material adverse change clause that does not apply beyond closing and does not contain anyrating triggers that would result in any acceleration or put of obligations. The arrangement also contains a 65%maximum allowable debt level (as defined) that applies to NiMo. As of March 31, 2009, there was significantheadroom versus the 65% level allowed for NiMo and we expect that to remain the norm for the foreseeable future.

As of March 31, 2009, NiMo had about US$23.1 million of unrestricted cash on hand, while owing about US$650.6million to affiliates under the money pool and reporting US$350 million as the current portion of long-term debt(CPLTD). The significantly higher than typical amount of short term borrowing under the money pool results fromuse of that source to repay a $600 million long-term senior note issue that matured in October 2008 and the $350million CPLTD relates to $350 million intercompany note due July 31, 2009. With regard to recent past practices,NiMo has been repaying debt with positive free cash flow or otherwise refinancing with inter-company instead ofthird party debt. Going forward, we expect NiMo to again begin issuing third party long-term debt once it receivesclarification from the NYPSC on its May 2009 decision authorizing NiMo to issue up to $2.0 billion of long-termdebt through March 31, 2012. Although we expect that NiMo will address the impending inter-company notematurity with internal borrowing, we anticipate a long-term debt issue later this year to address repayment of asubstantial portion of borrowings under the money pool. In addition to the US$350 million inter-company note dueJuly 31, 2009, NiMo's next material long-term debt maturity is another US$350 million inter-company note dueJune 30, 2010. In considering NiMo's other near term calls on cash, the company is following through on aReliability Enhancement Program (REP) aimed at improving the utility's overall performance and reliability as wellas enhancing opportunities to achieve financial benefits under performance based regulation currently in place.Setting aside long-term debt maturities, but taking into account spending for the REP, which could result in NiMoagain making capital expenditures in excess of US$400 million in FY 2010, and the likely commencement ofdividends to be paid to National Grid USA, we anticipate that NiMo will still be cash flow positive, albeitconsiderably less so than in recent years. As a result, we would expect the pace of NiMo's debt reduction to taper


227

off considerably going forward.

Rating Outlook

The stable rating outlook for NiMo mirrors the stable rating outlook for its ultimate parent National Grid plc and allthe other rated entities in the group, largely reflecting the significant interdependencies that exist within theNational Grid group of companies and our view that on the whole the National Grid Group's credit quality willstrengthen during FY 2010, thereby solidifying ratings for NiMo and those of the other rated entities within thefamily. Under this scenario, we believe that there would be additional headroom within existing ratings, therebyproviding a degree of flexibility that does not currently exist.

What Could Change the Rating - Up

Assuming some guidance under the Moody's Rating Methodology for Complex European Holding CompanyStructures, it is unlikely that the ratings for NiMo will go up in the near future, unless there is a change in the viewof the overall group rating for the National Grid plc family. While we do not anticipate upward rating pressure in thenear to medium term, ratings would become more strongly positioned if the consolidated National Gridperformance improves as expected during FY 2010.

What Could Change the Rating - Down

NiMo's ratings could go down if there is a downgrade to our assessment of the overall group credit quality forNational Grid plc or if there is significant change to the standalone financial metrics resulting from an increase in itsdividend obligation. Ratings could also be pressured if National Grid plc decides to increase the leverage at thecompany as part of its further expansion in the US. For example, ratings could be pressured down if NiMo'scoverage of interest and debt by cash flow from operations (exclusive of the effects of changes in working capital)falls below 4.5x and 22%, respectively, for a sustained period.

[1] CFO pre-W/C, which is also referred to as FFO in the Global Regulated Electric Utilities Rating Methodology, isequal to net cash flow from operations less net changes in working capital items

Rating Factors

Niagara Mohawk Power Corporation

Select Key Ratios for Global Regulated ElectricUtilities

Rating Aa Aa A A Baa Baa Ba Ba

Level of Business Risk Medium Low Medium Low Medium Low Medium Low

CFO pre-W/C to Interest (x) [1] >6 >5 3.5-6.0 3.0-5.7

2.7-5.0 2-4.0 <2.5 <2

CFO pre-W/C to Debt (%) [1] >30 >22 22-30 12-22 13-25 5-13 <13 <5

CFO pre-W/C - Dividends to Debt (%) [1] >25 >20 13-25 9-20 8-20 3-10 <10 <3

Total Debt to Book Capitalization (%) <40 <50 40-60 50-75 50-70 60-75 >60 >70

CREDIT RATINGS ARE MOODY'S INVESTORS SERVICE, INC.'S (MIS) CURRENT OPINIONS OF THERELATIVE FUTURE CREDIT RISK OF ENTITIES, CREDIT COMMITMENTS, OR DEBT OR DEBT-LIKESECURITIES. MIS DEFINES CREDIT RISK AS THE RISK THAT AN ENTITY MAY NOT MEET ITSCONTRACTUAL, FINANCIAL OBLIGATIONS AS THEY COME DUE AND ANY ESTIMATED FINANCIAL LOSSIN THE EVENT OF DEFAULT. CREDIT RATINGS DO NOT ADDRESS ANY OTHER RISK, INCLUDING BUTNOT LIMITED TO: LIQUIDITY RISK, MARKET VALUE RISK, OR PRICE VOLATILITY. CREDIT RATINGS ARENOT STATEMENTS OF CURRENT OR HISTORICAL FACT. CREDIT RATINGS DO NOT CONSTITUTEINVESTMENT OR FINANCIAL ADVICE, AND CREDIT RATINGS ARE NOT RECOMMENDATIONS TOPURCHASE, SELL, OR HOLD PARTICULAR SECURITIES. CREDIT RATINGS DO NOT COMMENT ON THESUITABILITY OF AN INVESTMENT FOR ANY PARTICULAR INVESTOR. MIS ISSUES ITS CREDIT RATINGSWITH THE EXPECTATION AND UNDERSTANDING THAT EACH INVESTOR WILL MAKE ITS OWN STUDYAND EVALUATION OF EACH SECURITY THAT IS UNDER CONSIDERATION FOR PURCHASE, HOLDING,OR SALE.

© Copyright 2009, Moody's Investors Service, Inc. and/or its licensors including Moody's Assurance Company, Inc.(together, "MOODY'S"). All rights reserved.

ALL INFORMATION CONTAINED HEREIN IS PROTECTED BY COPYRIGHT LAW AND NONE OF SUCH INFORMATION MAY BE COPIED OR OTHERWISE REPRODUCED, REPACKAGED, FURTHER TRANSMITTED, TRANSFERRED, DISSEMINATED, REDISTRIBUTED OR RESOLD, OR STORED FOR SUBSEQUENT USE FOR ANY SUCH PURPOSE, IN WHOLE OR IN PART, IN ANY FORM OR MANNER OR BY ANY MEANS WHATSOEVER, BY ANY PERSON WITHOUT MOODY'S PRIOR WRITTEN CONSENT. All


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information contained herein is obtained by MOODY'S from sources believed by it to be accurate and reliable. Because of the possibility of human or mechanical error as well as other factors, however, such information is provided "as is" without warranty of any kind and MOODY'S, in particular, makes no representation or warranty, express or implied, as to the accuracy, timeliness, completeness, merchantability or fitness for any particular purpose of any such information. Under no circumstances shall MOODY'S have any liability to any person or entity for (a) any loss or damage in whole or in part caused by, resulting from, or relating to, any error (negligent or otherwise) or other circumstance or contingency within or outside the control of MOODY'S or any of its directors, officers, employees or agents in connection with the procurement, collection, compilation, analysis, interpretation, communication, publication or delivery of any such information, or (b) any direct, indirect, special, consequential, compensatory or incidental damages whatsoever (including without limitation, lost profits), even if MOODY'S is advised in advance of the possibility of such damages, resulting from the use of or inability to use, any such information. The credit ratings and financial reporting analysis observations, if any, constituting part of the information contained herein are, and must be construed solely as, statements of opinion and not statements of fact or recommendations to purchase, sell or hold any securities. NO WARRANTY, EXPRESS OR IMPLIED, AS TO THE ACCURACY, TIMELINESS, COMPLETENESS, MERCHANTABILITY OR FITNESS FOR ANY PARTICULAR PURPOSE OF ANY SUCH RATING OR OTHER OPINION OR INFORMATION IS GIVEN OR MADE BY MOODY'S IN ANY FORM OR MANNER WHATSOEVER. Each rating or other opinion must be weighed solely as one factor in any investment decision made by or on behalf of any user of the information contained herein, and each such user must accordingly make its own study and evaluation of each security and of each issuer and guarantor of, and each provider of credit support for, each security that it may consider purchasing, holding or selling. MOODY'S hereby discloses that most issuers of debt securities (including corporate and municipal bonds, debentures, notes and commercial paper) and preferred stock rated by MOODY'S have, prior to assignment of any rating, agreed to pay to MOODY'S for appraisal and rating services rendered by it fees ranging from $1,500 to approximately $2,400,000. Moody's Corporation (MCO) and its wholly-owned credit rating agency subsidiary, Moody's Investors Service (MIS), also maintain policies and procedures to address the independence of MIS's ratings and rating processes. Information regarding certain affiliations that may exist between directors of MCO and rated entities, and between entities who hold ratings from MIS and have also publicly reported to the SEC an ownership interest in MCO of more than 5%, is posted annually on Moody's website at www.moodys.com under the heading "Shareholder Relations - Corporate Governance - Director and Shareholder Affiliation Policy."


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Schedule 2

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morin testimony final - national grid€¦ · 29/01/2010 · 14 journal of business...

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