STATE OF ALASKA

T-2

THE REGULATORY COMMISSION OF ALASKA

Prepared Direct and Answering Testimonyand Exbibits

ofFRANK J. HANLEY

AUS Consultants - Utility Services

Before Commissioners:

In the Matter of the Filing by AMERADA HESS )PIPELINE CORPORATION; BP PIPELINES )(ALASKA) INe.; EXXONMOBIL PIPELINE )COMPANY; PHILIPS TRANSPORTATION )(ALASKA) INC.; UNOCAL PIPELINE COMPANY; )and WILLIAMS ALASKA PIPELINE COMPANY, )LLC of Tariff Rates To Be Effective January 1,2003, )for the Intrastate Transponation of Petroleum over the )Trans Alaska Pipeline System and the Investigation )into the 2001 and 2002 Tariff Rates for the Intrastate )Transportation of Petroleum over the )Trans Alaska Pipeline System )

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VOLUME I OF III

Mark K. Johnson, ChairKate GiardDave HarbourJames S. StrandbergG. Nanette Thompson

P-03-4

OD BebalfofTESORO ALASKA COMPANY

September 3, 2003

VOLUME I of III

TABLE OF CONTENTS

TABLE OF CONTENTS i

I. INTRODUCTION AND PURPOSE I

II. DIRECT TESTIMONY 3

II.A SUMMARY 3

II.B THE RATEMAKING PARADIGM 6

II.C RJSK 8

I1.D EFFICIENT MARKET HYPOTHESIS 10

II.E CAPITAL STRUCTURE 12

II.F DEBT COST RATES 18

II.G COMMON EQUln COST RATES 20

I. Academic Literature Support for Use of MultipleCost of Common Equity Models 20

2. Discounted Cash Flow (DCF) Model 22

2.a Theoretical Basis 22

3. Application of the DCF Model 23

3.a Single-Stage Gro\\th DCF Model 24

4. Two-Stage Growth DCF Model 26

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TABLE OF CONTENTS cont.

5. The Risk Premium Model (RPM) 29

5.a Theoretical Basis 29

5.b Application of the RPM 30

6. The Capital Asset Pricing Model (CAPM) 34

6.a Theoretical Basis 34

6.b Traditional CAPM 35

6.c The Empirical CAPM 35

6.d Applications of the CAPM 36

6.d.1 Traditional CAPM Results 38

6.d.2 Empirical CAPM Results 39

6.d.3 Summary of CAPM Conclusion 39

7. Comparable Earnings Model (CEM) 39

7.a Theoretical Basis 39

7.b Market-Based Selection of Comparable Risk Companies 40

7.c Applications of the CEM 43

8. Recommended Common Equity Cost Rates 43

Ill. OVERALL COSTS OF CAPrT AL AND FAIR RATES OF RETURN 45

V. ANSWERING TESTIMONY 46

V.A TAPS CARRIERS' WITNESS WILLIAMSON 46

Appendix A - Professional Qualifications

TABLE OF CONTENTS cont.

VOLUME II OF HI

Workpapers (numbers correspond with exhibit designations):

TabFJH WP-IFJH WP-2FJH WP-3FJH WP-4FJH WP-5FJH WP-6FJH WP-7FJHWP-8FJH WP-9FJH WP-IO

DescriptionNoneNoneWorkpapers 1-3 to FJH-3Workpapers 1-2 to FJH-4NoneWorkpapers 1-9 to FJH-6Workpaper I to FJH-7NoneWorkpapers 1-7 to FJH-9Workpapers 1-3 to FJH-IO

VOLUME HI OF III

Workpapers (numbers correspond with exhibit designations):

TabFJH WP-llFJH WP-12FJHWP-J3FJH WP-14FJH Misc. WP

DescriptionWorkpapcrs J-4 to FJH-l JWorkpaper 1 to FJH-12NoneNoneMiscellaneous Work papers 1-3

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PREPARED DIRECT AND ANSWERING TESTIMONYOF

FRANK J. HANLEY

INTRODUCTION AND PURPOSE

Please state your name, occupation and business address.

My name is Frank J. Hanley and I am President of AUS Consultants - Utility Services.

My business address is 155 Gaither Drive, P.O. Box 1050, Moorestown, New Jersey

08057.

Please summarize your professional qualifications.

J have testified as an expert witness on rate of return and related financial issues before

33 state public utility commissions, including the Regulatory Commission of Alaska, the

Public Services Commission of the Territory of the U.S. Virgin Islands, and the Federal

Energy Regulatory Commission ("FERC"). I have also testified before local and county

reguJatorybodies, an arbitration panel, a U.S. Bankruptcy Court, the U.S. Tax Court and

a state district court. I have appeared on behalf of investor-owned companies,

municipalities, and state public utility commissions. I hold a B.S. in business

administration from Drexel University. I am also a Certified Rate of Return Analyst.

The details in Appendix A present a more detailed description of my professional

quali fications.

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What is the purpose of your testimony?

The purpose of my prepared direct testimony is to provide evidence on behalf of Tesoro

Alaska Company ("Tesoro") with regard to the fair rates of return which the Trans-

Alaska Pipeline System ('TAPS") should be afforded an opportunity to earn for the years

2001,2002. the going-forward period, i.e., 2003 and heyond.

The purpose of my answering testimony is to address the flaws in the approach

utilized hy TAPS Carriers' Witness Williamson in the determination of fair rates of

return in his prepared direct testimony as to the: (l) the differences in capital structure

ratios and debt and common equity cost rates attrihutable to his choice of proxy gas

pipeline companies; (2) the flaws in his reasoning for not relying upon the Risk Premium

Model ("RPM"), Capital Asset Pricing Model ("CAPM"), and Comparable Earnings

Model ("CEM") and failure to apply the methodology of the Commission's Order No.

151; (3) incorrect inclusion of the early period risk adjustment adder of 75 basis points

beyond mid-2002; and (4) his inconsistency with prior recent testimonies.

Have you prepared exhibits in support of your testimony?

Yes. I have prepared (or had prepared under my direct supervision and direction) 14

Exhibits which have been marked as Exhibits FJH-Ithrough FJH-14. Exhibits FJH-l

through FJH-I J relate to my direct testimony, Exhibits FJH-12through FJH-14 relate to

my answering testimony.

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Please summarize you r direct testimouy.

I recommend appropriate overall costs of capital and fair rates of return applicable to

TAPS for the years 2001, 2002, and the going-forward period commencing in 2003. I

have followed precisely the methodology established by this Commission in its Order

No. 151 relative to Docket No. P-97-4. The only differences are with regard to proxy gas

pipeline holding companies for varying and necessary reasons which will be explained.

The oil pipeline proxies are the same as in Order No. 151 except that the name of

Lakehead Pipeline Partners has been changed to Enbridge Energy Partners. The first step

in the process is the determination of an appropriate capital structure. The capital

structure ratios employed should be consistent with the prospective level of business risk

of the enterprise and with similar risk companies whose capital structure ratios have

found acceptance in the marketplace. The capital structure of a regulated utility should

be the result of its prospective level of business risk. It should not be based upon who

owns its common stock or the manner in which those owners are financed. TAPS should

n. DIRECT TESTIMONY

2 ILA SUMMARY

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be viewed as a stand-alone utility, and its business and financial risks should be evaluated

in that context.

Following the methodology of Order No. IS 1, I analyzed the capital structure of

the proxy groups of five oil and four gas pipeline holding companies (including their

operating gas pipeline subsidiaries whose bonds are rated) based on the years 2000 and

2001 applicable to the years 2001 and 2002; and three gas pipeline companies' capital

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4structures at year-end 2002 applicable to those companies qualifying for inclusion as

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proxies in August 2003 applicable to the going-forward period. I recommend the use of

separate capital structure and fair rate of return for each period, i.e., the two locked-in

years 2001 and 2002 as well as the going-forward period.

In order to ascertain reasonable debt cost rates for TAPS, I analyzed the

composite cost rates of long-term debt of the proxy groups of oil and gas pipeline

companies. I relied upon averages of the oil companies and the operating subsidiaries'

gas pipeline subsidiaries whose bonds are rated. In fomlUlating my recommended

common equity cost rates, I relied upon the Efficient Market Hypothesis ("EMH") which

suggests that investors are aware of all publicly available information including the

financial literature, which discusses multiple cost of common equity models and

encourages their use. Consequently, I employ four different cost of common equity

models, namely the Discounted Cash Flow ("DCF"); the Risk Premium Model (RPM);

the Capital Asset Pricing Model (CAPM); and the Comparable Earnings Model (eEM).

As a result of the application of all four models to the two proxy groups of oil and gas

pipeline companies, I formulated my recommended common equity cost rates applicable

to the locked-in years 2001 and 2002, as well as the going-forward period. Because

ratemaking and the cost of capital are prospective, I assessed the cost of capital for each

locked-in year based on market conditions at the end of the preceding year. For the

going-forward period, i.e., 2003 and beyond, I utilized the most recent capital structures

and debt cost rates (2002) to the companies qualifying to be in each proxy group in

August 2003, and the most recent August 2003 market data for my cost of common

1 equity reconmlendation. My cost of capital recommendations for the locked-in years

2 2001-2002, the going-foIWard period are sUDilllarized in the following table:

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GoingFOIWard(I) 2002 (I) 2001 (I)

Capital StructuresDebt 50.52% 49.88% 48.34%Equity 49.48 50.12 51.66

Debt Cost Rates 6.03% 6.46% 7.52l}ij

Costs of ConmlOn Equity:Excluding Early Period Adder 12.95% 13.15% 14.30%

Early Period Added (2) N/ARisk Premium

0.375% 0.75%

Total Cost of Equity 12.95% 13.525% 15.05%

Reconmlended Overall Costsof Capital 9.46% 10.01% 11.41~{,

(I) Infonnation from Exhibit FJH-1 and Supporting Exhibits.(2) Order No. 151 specified added risk premium for early periods was to tenninate

mid-2002. Thus, no adder included for the going-foIWard period and only one-half, or 37.5 basis points recognized for 2002.

My recommended CODmlonequity cost rate for 2001 reflects the full 75 basis

points allowed by this Commission through mid-2002 per Order No. 151. Since the

added risk premium was to end mid-2002, only one-half the 75 basis points, or 37.5 basis

points, is recognized for 2002 and no added risk premium is reflected for the "going-

fOIWard"period, i.e., 2003 and beyond, hence the N/A, i.e., not applicable.

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H.B THE RATEMAKlNG PARADIGM

Please briefly explain the ratemaking paradigm.

In non-price regulated industries, the competition of the marketplace is the principal

determinant in establishing the price of a product or service. In the case of price-

regulated public utilities, regulation must act as a substitute for the competition of the

marketplace. The principal standard employed in utility price regulation is the rate base

limes rate of return paradigm. Rate base is typically the Depreciated Original Cost of

assets in service plus allowances for necessary cash working capital and materials and

supplies inventory. The fair rate of return must meet the judicial standards established

by the U.S. Supreme Court in Bluefield Water Works Improvement Co. v. Pub. Servo

Comm'n, 262 U.S. 679 (1922); and Federal Power Comm'n v. Hope Natural Gas Co.,

320 U.S. 591 (1944). Those cases essentially require that tbe rates set assure that a utility

can fulfill its obligation to serve and provide a level of earnings sufficient to maintain the

integrity of invested capital and permit the attraction of new capital at a reasonable cost

in competition with other comparable-risk seekers of capital in the marketplace. Thus,

the cost of capital must be determined from analyses of market-based cost rates.

Ratemaking is always prospective as is the cost of capital. Capital costs reflect

investors' expectations based upon their perceptions of future risks. Rates are set to be

collected over a future time period. Utilities are not guaranteed to earn a fair rate of

return but are afforded only an opportunity to earn it.

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Please explain.

As Phillipsl points out, the U.S. Supreme Court has stated that public utilities are not

guaranteed a fair rate of return. He cites the Market Street Railway Co. v. Railroad

Comm'n, 324 U.S. 548, 567 (] 945) where the Court stated:

The due process clause has been applied to prevent governmentaldestruction of existing economic values. It has not and cannot beapplied to insure values or to restore values that have been lost bythe operation of economic forces.

Phillips' adds that public utilities are not protected from "business hazards" or from the

operation of "economic forces."

There is a long-standing prohibition against retroactive ratemaking which

prohibits the recovery of past losses in the setting of new rates.

Can you provide an example from a past regulatory decision which affirms the

prospective nature of ratemaking and prohibits the recovery of past costs or risks?

Yes. For example, the California Public Utilities Commission, in its decision Re Pacific

Gas and Electric Company stated:

The general concept of retroactive ratemaking is spelled out in thecase law of numerous other states. Retroactive ratemaking occurswhen a rate is set so as to permit collection in the future forexpenses attributable to past services. (State ex reI. UtilitiesCommission v. Nantahala Power and Light Co., 309 S.E. 2d 473,485,65 N.C. App. 198.) It is the setting of rates which permit autility to recover past losses or which require it to refund past

Charles F. Phillips. Jr., The Regulation of Public Utilities B Theory and Practice. 1993, Public UtilityReports, Inc., Arlington, VA. p. 381.Id.Public Utilities Reports, Inc. 1997 B PURBase B PUR4th B Decision 92-02-037, Application 90-05-003,Feb. 5, 1992.

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excess profits collected under a rate that did not perfectly matchexpenses plus rate of return with the rate actually established.(State ex reI. Utility Consumers Council of Missouri, inc. v.Public Service Commission, 585 S.W. 2d 4159 (Mo.).)

5 Consequently, future rates should not include any provision to recover perceived past

6 earnings deficiencies.

7 II.C RISK

8 Q. Please describe in a general way tbe elements of investment risk investors face in9 tbe marketplace.

10 A. The collective investment risk faced by investors is comprised of both non-diversifiable,

11 systematic market risk and diversifiable, unsystematic, or non-market, risks. Systematic

12 market risk is the result of socioeconomic and other events that affect the returns on all

13 assets. Thus, diversification cannot reduce or eliminate systematic risk. Unsystematic,14 non-market risks are diversifiable and are comprised of a combination of both business15 and financial risks.

16 Q. Wbat is business risk?

17 A. Business risk is a collective term encompassing all of the diversifiable risks of a firnl

18 except financial risk. Business risk is important to the determination of a fair rate of

19 return because the greater the level of risk, the greater the rate of return demanded by

20 investors consistent with the basic financial precept of risk and return.

21 Q. Wbat is financial risk?22 A. Financial risk is the additional risk which arises when debt capital is introduced into the

23 capital structure ofa firnl. The marketplace determines, with guidelines from bond rating

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agencies, just how much debt is acceptable for a firm to employ given its collective

assessment of the firm's business risk. In other words, the greater the perceived business

risk, the greater is the required equity cushion underlying the debt capital and vice versa.

How can investors gain insigbt into a firm's diversifiable investment risk?

A firm's level of investment risk can be ascertained from its bond rating. Although the

specific business or financial risks may differ between companies, the same bond rating

indicates that the combined risks are similar because the bond rating process takes all

diversifiable business and financial risks into account. For example, Standard & Poor's

("'S&P") expressly states that the bond rating process encompasses a qualitative analysis

of business and financial risks.' Consequently, S&P's credit analysis results in a

bond/credit rating which reflects a comprehensive assessment of all of the diversifiable

risks of an enterprise. As a rule, higher credit ratings mean lower costs of debt and

equity.

How are perceived investment risks acknowledged by investors?

They are acknowledged by debt capital investors who place reliance upon bond ratings.

The higher a bond rating, the lower the perceived risks and the lower the expected rate

of return, and vice versa in accordance with the risk/return tenet oftlnance.1nvestors in

common stocks acknowledge all perceived risks in the prices they pay for stocks in

accordance with the Efficient Market Hypothesis (EMH).

Slandard & Poor's - Corporate Ratings Criteria. Copyright 1996, pp. 29~35.9

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Please describe the conceptual basis of the Efficient Market Hypothesis (EM H).

The EMH is the cornerstone of modern investment theory. It was pioneered by

Eugene F. Fama' in 1970. An efficient market is one in which security prices at all times

reflect all the relevant information at that time. An efficient market implies that prices

adjust instantaneously to the arrival of new information and that the process therefore

reflects the intrinsic fundamental economic value of a security.6

The essential components of the EMH are:

I. investors are rational and will invest in assets which provide the highestexpected return for a particular level of risk.

2. Current market prices reOect all publicly available information.

3. Returns are independent in that today's market returns are umelated toyesterday's returns as that information has already been processed.

4. The markets follow a random walk, i.e., the probability distribution ofexpected returns approximates the nornlal bell curve.

Brealey and Myers 7 state:

When economists say that the security market is 'efficient', theyare not talking about whether the filing is up to date or whetherdesktops are tidy. They mean that information is widely andcheaply available to investors and that all relevant andascertainable information is already reflected in security prices.

fama, Eugene f., "Eflicient Capital Markets: A Review of Theory and Empirical Work." Journal orFinance, May 1970, pp. 383-417.Morin, Roger A., "Regulatory Finance - Utilities' Cost of Capital." Public Utilities Reports, Inc., 1994,p.136.Brealey. R.A. and Myers, S.c., "Principles orCorporate finance." McGraw-Hill Publications, Inc., 1996,pp.323-24.

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Brigham' defines the three forms of the EMH, thusly:

I. The "weak" form asserts that all past market prices and data are fullyreflected in securities prices. In other words, technical analysis cannotenable an investor to "outperform the market."

2. The "semi strong" form asserts that all publicly available information isfully reflected in securities prices. In other words, fundamental analysiscannot enable an investor to "outperform the market."

3. The "strong" form asserts that all information, both public and private, isfully reflected in securities prices. In other words, even insiderinformation cannot enable an investor to "outperform the market."

The "semi strong" form is generally held as true because the use of insider information

(even though illegal) can often enable an investor to "beat the market" and earn excessive

returns, thereby disproving the "strong" form.

Does the EMH influence the capital structure ratios which a firm can employ?

Yes. Investors (and bond rating agencies to whom debt investors look for guidance and

comfort) take into account all publicly available infoffilation before purchasing debt

instruments. When a firm attempts to employ more financial leverage than its business

risk permits, as perceived by investors, either the firm will be unable to raise all required

external capital, or at a minimum, the capital will be more costly. If a firnl crosses the

financial leverage threshold relative to investors' perceptions of business risk, its bond

rating will inevitably be lowered which will result in higher capital costs.

Brigham, Eugene F., "Fundamentals of Financial Management". The Dryden Press. Fifth Edition, 1989.p.225.

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Q. Please explain tbe applicability oftbe EMH to tbe determination of common equitycost rate.

Common sense affirms the conceptual basis of the "semi strong" form of the EMH as

described above. In practical terms, this means that market prices paid for securities

reOect all publicly-available information. Thus, no degree of sophistication and/or

analysis can enable an investor to outperform the market without the illegal use of insider

information. Investors are aware of all publicly available information, including, but not

limited to, bond rating, analysts' assessments of risk and earnings forecasts, and all the

various cost of common equity models discussed in the tinancialliterature. This means

that all such cost of common equity models should be employed in an effort to emulate

investors' actions because the EMH requires the assumption that investors utilize all

publicly-available information.

13 II.E CAPITAL STRUCTURE

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Wbat are tbe most important factors in determining an appropriate capital

structure for ratemaking purposes?

The capital structure should be reasonably similar to the capital structures maintained by

other companies of similar risk as long as it is not excessively costly to customers. Too

much common equity in the capital structure results in the need for an excessive level of

revenues in order to support the higher common equity ratio. The need for excessive

revenues occurs because, with the use of too much equity, there is less interest paid on

debt capital. Interest expense is deductible in arriving at corporate taxable income which

reduces the level of income taxes which need to be collected from customers through

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rates. In other words, an appropriate capital structure should be commensurate with the

perceived level of business risk wruch can be ascertained by reference to comparable risk

proxies and credit rating agency guidelines.

What comparable risk proxies have you evaluated?

I have evaluated two separate proxy groups. The first is a group of five oil pipeline

companies which remains constant for all three periods, i.e., 2001, 2002, "going

forward." It is the same group of companies utilized in Order No. 151 except for a name

change for one of the companies, i.e., Lakehead Pipe Line Partners is now Enbridge

Energy Partners. The second is a group of gas pipeline holding companies. The number

varies from four companies applicable to 2001 and 2002 and three applicable to the

"going-forward" period. J believe that the gas pipeline holding companies generally are

over-leveraged as a result of a number of acquisitions and mergers in recent years which

have been accomplished largely through the use of debt capital. Because those highly

leveraged capital structure ratios of the gas pipeline companies are not indicative of how

an operating gas pipeline company should be financed, I chose instead to view the capital

structure ratios maintained by their operating subsidiaries which issue their own long-

term debt capital that is rated, an approach also consistent with Order No. 151. I have

differences in the companies chosen for these groups of gas pipeline holding companies

(and hence their operating subsidiaries whose bonds are rated) from those chosen by

Dr. Willianlson. Those differences will be addressed in the answering portion of this

testimony.

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Please describe Exhibit FJH-3.

Exhibit FJH-3 consists of eleven pages and contains information on the capital structure

ratios for the years 2000 through 2002 for the proxy groups of oil and gas pipeline

companies, and the operating subsidiaries of the gas pipeline holding companies whose

bonds are rated. The resulls of my analyses are summarized on page I of Exhibit FJH-3.

How were the capital structure ratios shown in Exhibit FJH-3 calculated?

They were calculated based on the reported financial statements and are based on the

book values of common equity or partners' capital, i.e., net worth, for all of the

companies in accordance with standard financial practice. This is the same methodology

utilized by analysts, bond rating agencies, and financial publication firms such as Value

Line Investment Survey, etc. 1lis consistent with balance sheets prepared in accordance

with generally accepted accounting principles.

Please summarize your analyses of capital structure ratios.

Page I of Exhibit FJH-3 summarizes the capital structure ratios. My calculations were

based on all of the outstanding investor-provided capital, including the current portion

of long-term debt as well as short term debt. Market-based conunon equity cost rates

reflect investors' perception of the total risk of each company including financial risk.

Investor-influencing rating agencies such as S&P base their quantitative analyses in part

on capital structure ratios calculated /Tomthe books (the balance sheets) and they include

total debt, i.e., the sum of both long- and short-term debt.

I have shown on page I of Exhibit FJH-3 for all three periods, the average capital

structure ratios for the five oil pipeline companies and the operating subsidiaries of the

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gas pipeline holding companies whose bonds are rated. I also show at the bottom of

page 1 of Exhibit FJH-3, consistent with Order No. 151, the average of those averages

by period, which are those capital structure ratios which I recommend for use in

determining rates ofretum for TAPS for 2001,2002, the going-forward period.

On the top of page 2 of Exhibit FJH-3, Ihave shown the average capital structure

ratios of the gas pipeline holding companies whose debt ratios ranged between 58.38%

and 61.24%,during the periods studied. Ibelieve that these holding companies have been

over-leveraged in recent years due to acquisitions and mergers accomplished through the

use of substantial debt. Thus, Ido not believe that such ratios are representative of how

an operating gas pipeline company should be financed. Consequently, I chose to

examine the capital structure ratios maintained by the operating gas pipeline subsidiaries

of these holding companies that have their own bonds outstanding which are rated. I

should note that in each of the three periods, Idid include Kinder Morgan Interstate Gas

Transmission at 100% equity in the calculation of the average ratios for the operating gas

companies. That subsidiary, until 2000, did have its own rated debt outstanding. Had

Inot done so, the resultant capital structure ratios would have been biased toward too

much debt for the reasons stated above regarding the gas pipeline holding companies.

Itwas also necessitated because of the relatively few operating gas pipeline companies

with rated debt outstanding; especially in 2002 (applicable to the going-forward period)

for the three holding companies. Enterprise Products Partners and GulfTerra Energy

Partners have issued debt only at the parent level. They are included in the 2002 average,

but Ialso included Kinder Morgan Interstate Gas Transmission (a subsidiary of Kinder

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Morgan, Inc.) at 100% equity to achieve a realistic capital structure of 43.53% debt and

56.47% equity for this group. Had I not done so and included Kinder Morgan, Inc. along2

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with the other two holding companies (Enterprise Partners and Gulff erra), the average

capital structure applicable to the gas pipeline group for the going-forward period would

have been 65.30% debt and 34.71% equity- a non-representative and wholly inadequate

capital structure with too much debt and too little equity.

The details of the capital structures by period are shown in Exhibit FJH-3, pages

5 through 9, the results of which are shown in summary form on page I of Exhibit FJH-3.

As shown on page I of Exhibit FJH-3, the average capital structure ratios of the oil

pipeline companies, the operating subsidiaries of the gas pipeline companies and their

average applicable to each period are as follows:

Capital Structure RatiosPeriods

Oil PipelinesDebtEquity

GoingForward (]) 2002 (2) 2001 (3)

57.50% 54.67% 53.60%42.50 45.33 46.40

Operating Subsidiariesof Gas Pipeline Holding Companies

DebtEquity

Average

DebtEquity

43.53% 45.09% 43.08%56.47 54.91 56.92

50.52~o 49.88% 48.34%49.48 50.12 51.66

(1) Basedon year-end 2002 capital structures for qualifying proxy companies inAugust2003.

(2) Based on year-end 2001 capital structures.3) Based on year-end 2000 capital structures.

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The above average ratios are those which I adopt for each locked-in period 2001,

2002 as well as the going-forward period.

The average S&P assigned business position to the average oil pipeline proxy

company islhas been essentially 4 with an average bond rating ranging between BBB+

and A-. The average assigned business position for those operating subsidiaries of the

gas pipeline holding companies islhas been close to 5 with average bond ratings ranging

between BBB- to BBB+. The information for both groups is shown in Workpaper No.3

to Exhibit FJH-9 (FJH WP-9). In view of the foregoing, Idecided to observe the S&P's

financial target ratios for a utility with a credit rating of BBB and a business position

ranging between 4 and 5. The S&P financial target ratios are shown on page 10 of

Exhibit FJH-3, while S&P's definitions of those ratios are shown on page IIof the same

exhibit. As can be determined by taking the complement of the total debt to total capital

target ratios in order to detemline the range of required total equity ratios, the S&P

ranges of required capital structure ratios for a utility with a BBB bond rating and

business positions of 4 and 5 are as follows:

BBB Bond RatingBusiness Position

_4_ _5_

Total Debt 49.5%-57.0% 47.0%-55.0%

Total Equity 43.0%-50.5% 45.0%-53.0%

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In vIew of the recent actual ratios of the proxy groups and their average

applicable to each period as discussed above, as well as the S&P target ratios for a utility

with BBB bond rating and business position ranging between 4 and 5, it is clear that the

capital structure ratios which Ihave recommended to be applicable to each period (2001,

2002, going-forward) are reasonable because they fit within S&P's financial target

ratios.

7 I1.F DEBT COST RATES

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How did you arrive at your recommended debt cost rates for the locked-in years

2001 and 2002, as well as the going-forward period?

Consistent with Order No. 151 methodology, Irelied upon an average of the average

long-term debt cost rate for the oil pipeline group and the operating subsidiaries of the

gas pipeline holding companies whose bonds are rated for each of those periods. My

comparative analysis of all those long-term debt cost rates is contained in Exhibit FJH-4

which consists of three pages. Page I is a summary of those rates, and pages 2 and 3

contain the cost rates by company and group. For the year 2001, Irely upon the long-

tern] debt cost rates at year-end 2000 and for 2002 Irely upon the long-tern] debt cost

rates at year-end 2001. For the going-forward period, I rely upon the companies that

appropriately can be included in the proxy groups in August 2003 and utilize the year-

end 2002 long-term debt cost rates for those companies. The results of my analyses of

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long-term debt cost rate are summarized on page I of Exhibit FJH-4. They are as

follows:

Applicable Period

Average Long-Term Debt Cost RatesGoing-Forward 2002

Oil Pipelines 5.47%5.57% 7.54%

Operating Subsidiaries of

Gas Pipeline Holding Companies

A verage (Recommended) 6.03%

Tbe capital structure ratios wbicb you analyzed include sbort-term debt. Please

explain wby long-term debt cost rates are appropriate to use witb total debt ratios

ranging between 48.34% and 50.52% for eacb of tbe tbree periods.

I believe it is appropriate to use long-term debt cost rates because it is reasonable to

assume that over time short-term debt would be permanently funded based on a capital

mix consistent with industry averages and the financial target ratios of bond rating

agencies such as S&P. Moreover, this view is generous because with the usual normal

yield curve (such as has been experienced in recent years and is currently the case), the

use of short-term debt cost rates, which are substantially lower than long-term debt cost

rates, would result in lower composite debt cost rates. This has certainly been the case

from January 200 I to date with commercial paper rates and bank prime rates well below

my recommended long-term debt cost rates.

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Academic Literature Support for Use of Multiple Cost of Common Equity Models

Previously, you discussed why the EMH requires the use of multiple cost of

common equity models. Is there support in the academic literature for the need to

rely upon multiple cost of common equity models in arriving at a recommended

common equity cost rate?

Yes. For example, Phillips states:

Since regulation establishes a level of authorized earnings which,in turn, implicitly influences dividends per share, estimation ofthe growth rate from such data is an inherently circular process.For these reasons. the DCF model 'suggests a degree 0/precision which is infact not present' and leaves 'wide room lorcontroversy and argument about the level 0/ k '. (p. 396, italicsadded).

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Despite the difficulty 0/ measuring relative risk. the comparableearnings standard is no harder to app(v than is the market-determined standard. The DCF method, to illustrate. requires asubjective determination 0/ the growth rate the market iscontemplating. Moreover, as Leventhal has argued: 'Unless theutility is permilled to eam a retum comparable to that amilableelsewhere on similar risk, it will not be able in the long run toallract capital. ' (p. 398, italics added).

Also, Morin 10 states:

Sole reliance on the DCF model ignores the capital marketevidence andfinancial theoryformalized in the CAPM and otherrisk premium methods. The DCF model is one 0/ many 100is 10be employed in conjunction with other methods 10 estimate the

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Id.Id., pp. 23 I-32; 239-40.

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cost of equity. It is not a superior methodology that supplantsother financial theory and market evidence. The broad usage ofthe DCF methodology in regulatory proceedings does not makeit superior to other methods. (pp. 231-32, italics added).

Each methodology requires the exercise of considerablejudgement on the reasonableness of the assumption underlyingthe methodology and on the reasonableness of the proxies used tovalidate a theory. Thefailure of the traditional infinite growthDCF model to account for changes in relative market valuation,discussed above, is a vivid example of the potential shortcomingsof the DCF model when applied to a given company. It followsthat more than one methodology should be employed in arrivingat ajudgment on the cost of equity and that these methodologiesshould be applied across a series of comparable risk companies....Financial literature supports the use of multiple methods.(p. 239, italics added).

Professor Eugene Brigham, a widely respected scholar and finance academician asserted:

In practical work, it is often best to use all three methods -CAPM, bond yield plus risk premium, and DCF - and then applyjudgement when the methods produce different results. Peopleexperienced in estimating capital costs recognize that both carefulanalysis and very fine judgements are required. It would be niceto pretend that these judgements are unnecessary and to specifYan easy, precise way of determining the exact cost of equitycapital. Unfortunately, this is not possible. (pp. 239-40, italicsadded).

Another prominent finance scholar, Professor Stewart Myers, in his best-selling corporate

finance textbook stated:

The constant growth formula and the capital asset pricing modelare two different ways of gelling a handle on the same problem.(p. 240, italics added).

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In an earlier article, Professor Stewart Myers explained the point more fully:

Use more than one model when you can. Because estimating theopportunity cost of capital is difficult. onZv a fool throws awayuseful information. That means you should not use anyonemodel or measure mechanicalZv and exclusiveZv. Beta is helpfulas one tool in a kit, to be used in parallel with DCF models orother techniques for interpreting capital market data. (p. 240,italics added).

In view of the foregoing, it is clear that investors are aware of all of the models including

comparable earnings. The EMH requires the assumption that investors use them all.

Discounted Cash Flow

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Application oftbe DCF Model

Wbat versions of tbe DCF model did you use and bow were tbey applied?

I applied two basic versions of the DCF model, namely a single-stage growth model and

a two-stage growth model. Both models theoretically presume infinite investment

holding periods. In practical terms, this means a very long period of time such as 40 to

50 years.

In the application of the two-stage growth model, Icalculated the growth rates in

two different ways. The first Icall "compound growth" and the second Icall the "FERC

weighted growth." These will be explained subsequently.

The DCF models and all the cost of common equity models which Iutilize are

market-based. Icalculate the cost of common equity as of the December 31, preceding

each of the locked-in years 2001 and 2002 as well as in August 2003 for the going-

forward period. The cost of capital expected by investors is prospective. Accordingly,

application of the costs of common equity models at year-end 2000 and 2001 is

appropriately applicable to the subsequent locked-in years, namely 2001 and 2002. For

the "going-forward" period, i.e .. 2003 and beyond, I rely upon the most recent data

available in August 2003. Thus, for the going-forward period, Iutilized spot dividend

yields on July 31,2003, and for the three, six and twelve months then ended. Such data

is most representative of the future and that is also why Ibased it upon those companies

that qualify for inclusion as valid proxies in August 2003. Isummarize all of the results

of my applications of the DCF model in Exhibit FJH-5.

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Sinele-Staee Growth DCF Model

How did you determine the dividend yields used iu your application of the single-

stage growth DCF model?

The recent volatility of the stock market demonstrates why current spot (single day)

market prices should not be used exclusively in the ratemaking paradigm. A principal

goal of regulation is to normalize in order to avoid erratic pricing. Consequently, in

calculating dividend yields I relied upon the spot prices at December 31, preceding each

of the two locked-in years 2001 and 2002, as well as the averages of each of the

preceding three, six and twelve months, respectively. Exhibit FJH-6 contains all of the

single-stage growth DCF details and consists of seven pages. Page 1contains a summary

of the results for all three periods. Group average dividend yields are shown in Line Nos.

1,5, and 10. Pages 2 through 4 contain details of the dividend yields by company and

group as well as averages for each period. Pages 5 through 7 contain growth rate

information by year which will be discussed subsequently.

Please explain the dividend growth components shown on Line Nos. 2, 7, and 12,

respectively of Exhibit FJH-6, page 1.

Due to the fact that dividends are paid quarterly, or periodically, as opposed to

continuously (daily), an adjustment must be made. This is often referred to as the

discrete, or the Gordon Periodic version of the DCF model.

Since all of the companies pay quarterly dividends at di fferent times of the year,

a reasonable assumption is to reflect one-half the expected dividend growth rate. This

is a conservative approach so as not to overstate the dividend yield as it should be

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representative of the next twelve-month period consistent with the academic literature.

Therefore, the actual average dividend yields on Line Nos. I, 6, and lion page I of

Exhibit FJH-6 have been adjusted upward to reflect one-half the growth rates shown on

Line Nos. 4, 9, and 14, respectively. The resultant adjusted dividend yields are shown on

Line Nos. 3, 8, and 13, respectively.

Please explain the basis of the growth rates you utilized in your application of the

single-stage growth DCF model.

When it comes to fonnulating an expectation of growth for use in the DCF model, I

believe that investors are most inclined to give weight to analysts' forecasts. This is

especially so in a time of investor awareness of increasing regulatory changes affecting

the energy industry. Moreover, I believe it is clear that investors' expectation of earnings

gro\'o1.his the largest single factor which affects market prices. Consequently, I have

reviewed Value Line and I/B/E/S (Source: Standard & Poor's Earnings Guides)

projections of growth rates in earnings per share ("EPS"). I average the two projections

of EPS growth rates by company in each group and obtain an average growth rate for

each group.

Please explain why you also rely upon Value Line's earnings growth forecasts in

addition to I/BIE/S.

Value Line is an independent financial advisory service; it is not in the brokerage

business; its subscription rate is inexpensive, thereby making it very affordable for

individual investors; and it is readi ly accessible in the business reference section of better

libraries. Since Value Line has more than 100,000 subscribers and is so accessible to

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investors. it is investor-influencing. Moreover. because it is not in the brokerage

business, its independence is important to investors, especially in recent years due to the

scandals attributable to analysts who work for brokerage firms. The goal of an expert

witness testifying to the cost of common equity capital is to emulate what influences

investor opinions, and since a large percentage of utility common stocks are owned by

individual investors, the use of the Value Line forecasts is indispensable.

The details of my conclusions of growth rates are shown on pages 5 through 7 of

Exhibit FJH-6 by company and group for each of the three periods, i.e., the locked-in

years 2001 and 2002, as well as the going-forward period.

Please discuss the results of your application ofthe single-stage growth DCF model.

The results are summarized on page I of Exhibit FJH-5. The going-forward cost rates

range from 14.4% for the proxy group of five oil pipeline companies to 16.1% for the

three gas pipeline companies. The 2002 cost rates range trom 13.7% for the proxy group

of four gas pipeline companies to 15.0% for the proxy group of five oil pipeline

companies. The 2001 cost rates range trom 15.3% for the proxy group of four gas

pipeline companies to 16.4~ofor the proxy group of five oil pipeline companies.

Two-Stage Growth DCF Model

Please explain the basis of a two-stage growth DCF model.

Analysts' forecasts are usually limited to five years. The investment horizon implicit in

the standard DCF model used in rate regulation is infinity. In practical terms, this means

a typical period of 40 to 50 years when discounting is performed on a Net Present Value

("NPV") basis before the NPV is essentially zero. The theory for a second-stage growth

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rate is that over the long-run no company's growth can exceed that of the economy as a

whole. Growth of the economy is typically now measured hy growth in the Gross

Domestic Product ("GDP"). The FERC relies upon forecasted GDP growth during the

second stage in its application of a two-stage growth DCF model. For the first-stage

growth rate, 1 use only the average (first five years) forecasted growth in EPS. For the

second-stage growth, 1 use an average of forecasted GDP growth rates in a manner

previously utilized by the FERC. In the application, [ use the information available at

December 31 preceding the locked-in years 200 I and 2002 as well as at July 31, 2003,

preceding the going-forward period. I utilize two di fferent forms of the two-stage growth

model, namely a compound growth form consistent with DCF theory and previously

utilized hy the FERC as well as FERC"s current weighted growth version. I helieve the

latter to be flawed because it is arbitrary and inconsistent with the compound growth

theory of the DCF model. In applying both fOrolSof the two-stage gro\\1h model, I relied

upon the Energy Information Administration (E.l.A.) and the Social Security

Administration (S.S.A.) forecasts of growth in GDP.

What dividend yields do you use in your applications of the two-stage growth DCF

model?

I use the same dividend yields as those in my applications of the single-stage growth

model. The expected growth components are different because the growth rates differ

due to the use of second-stage growth rates.

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Please discuss the results of the two-stage, compound growth DCF model.

The results are shown in Exhibit FJH-7 which consists of seven pages. Page 1 contains

a summary of the results. Pages 2 through 7 contain the supporting details. The

first-stage growth rates are the average growth in EPS as shown by proxy group and

company in Column 2 of pages 5 through 7 of Exhibit FJH-6. The second-stage growth

rates are the average of the E.LA. and S.S.A. forecasted growth rates in GDP through

2020 to 2022 applicable to the years 2001, 2002, the going-forward period, respectively.

1have compounded the impact of the first and second-stage growth rates on the initial

annual dividends per share consistent with DCF theory.

As shown on page 1 of Exhibit FJH-7, the two-stage compound growth rates

range from a low of5.7% applicable to 2001 to a high of6.4% applicable to 2002 for the

five oil pipeline companies and from a low of 6.7% applicable to the going-forward

period to a high of7.9% applicable to 2002 for the four gas pipeline companies. The

DCF cost rates range from a low of 8.6% for the four gas pipeline holding companies

applicable to the year 2001 to a high of 14.4% applicable to the five oil pipeline

companies for the year 2001.

Please discuss the results of the two-stage, FERC weighted DCF model.

Application is identical to the two-stage compound growth model with the exception that

1have emulated the current FERC approach to calculating the gro\>,'lhrate. The FERC

arbitrarily gives 2/3 weight to the first-stage growth rate and 1/3 weight to the average

of all of the forecasted GDP growth rates. There is no basis in the theory of the DCF

model to support such an approach which is, therefore, completely arbitrary.

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Nonetheless, 1 have weighted growth in that manner in this application of the DCF

model. The results are shown in Exhibit FJH-8 which consists of four pages. Page I

contains a summary of the results. Pages 2 through 4 contain the details of growth rates

by company for each of the proxy groups of oil and gas pipeline holding companies. As

shown on page 1, the DCF cost rates range IToma low of 13.5% for the four gas pipeline

holding companies applicable to 2001, to a high of 16.0% applicable to the proxy group

of five oil pipeline companies for 2001.

Please su mmarize the results of the applications of the single-stage growth DCF

model and both versions of the two-stage growth DCF model.

As discussed previously, the summaryof my DCF conclusions is shown in Exhibit FJH-5

which consists of one page. As shown, the average of all the DCF cost rates range from

a low of 13.7% for the proxy group of four gas pipeline companies applicable to 2002

to a high of 16.4% applicable to the proxy group of five oil pipeline companies for 2001.

The Risk Premium Model (RP~n

Theoretical Basis

Please describe the theoretical basis of the RPM.

The RPM is based upon the theory that the cost of common equity capital is greater than

the prospective company-speci fie cost rate for long-term debt capital. In other words, it

is the expected cost rate for long-term debt capital plus a premium to compensate

common shareholders for the added risk of being unsecured and last-in-line in any claim

on a fimJ's assets and earnings.

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Some assert tbat the RPM is another form of the CAPM. Do you agree?

Generally yes, but there is a very significant distinction between the two models. The

RPM and CAPM both add a "risk premium" to an interest rate. The use ofa prospective

yield on a U.S. Government Security as the risk-free rate of return in the CAPM by

definition cannot reflect any company-specific risk. In contrast, the use of a prospective

company-specific, long-term bond yield in the RPM fully reflects company-specific risk

because the bond rating reflects an assessment by the rating agency of all diversifiable

business and financial risks. Consequently, although similar in a very broad way, they

are actually two separate and distinct cost of common equity models and recognized as

such in the financial literature.

Application of the RPM

Please describe your application of the RPM.

My application is contained in Exhibit FJH-9 which consists of nine pages. Page I

contains a summary of the results. Page 2 contains notes relative to page I. Page 3

contains a summary of my judgment of equity risk premiums while pages 4 through 9

contain the details related to the inputs of equity risk premiums upon which my

conclusions are based. I estimated the prospective cost rates oflong-term debt capital for

each proxy group based upon the average bond rating of each group in each period, i.e.,

2001,2002, going-forward, which are summarized in Line Nos. 5,12 and 19 on page I

of Exhibit FJH-9.

I then estimated the equity risk premiums through the use of two different studies.

The first study is based upon the use ofa long-ternl historical market equity risk premium

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averaged with a forecasted market equity risk premiwn allocated to each proxy group in

each period by use of each group's average beta. The second study is based upon a long-

term historical study using the actual holding period returns of public utilities with bonds

rated Baa by Moody's Investors Service which is equivalent to BBB by S&P.

Please explain the first equity risk premium study as shown on pages 4 through 6

of Exhibit FJH-9.

For each year, Iutilized the then most current arithmetic mean returns on the S&P 500

Composite Index as shown on Line No. I of pages 4 through 6 of Exhibit FJH-9. For

example, on page 4, Line No. I, relative to the going-forward period, the average total

return (1926-2002, inclusive) was 12.2%. From that return Isubtracted the arithmetic

mean return on long-term, high-grade corporate bonds of6.2% (e.g., Line No.2, page 4).

The result is a long-term historical market equity risk premium of 6.0~{'. Similar

calculations result in historical market equityriskpremiwns of7.0% and 7.4% applicable

to 2002 and 2001, respectively, as shown on pages 5 and 6 of Exhibit FJH-9.

Ithen relied upon the Value Line forecasted total market returns at each date (e.g.,

Line No.4, page 4) and subtracted the prospective yield on Aaa rated corporate bonds

(e.g., Line No.5, page 4). The result is a forecasted market equity risk premium of

11.0% applicable to the going-forward period. Similarly calculated results are 9.3% and

12.1% applicable to the years 2002 and 2001, respectively. Ithen averaged the long-term

historical and forecasted market equity risk premiums (e.g .. Line No.7, pages 4 through

6 of Exhibit FJH-9) and allocated the average equity risk premiums using the average

beta for each proxy group (e.g., Line No.8, pages 4 through 6). Each application results

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in group-specific equity risk premiums which are shown on Line No.9, pages 4

through 6).

Why did you use long-term historical equity risk premiums in your analyses?

The data were derived from Ibbotson Associates' 2000, 2001 and 2003 - Stocks, Bonds,

Bills and Inflation -- Valuation Edition Yearbooks as indicated in footnote I to pages 4

through 6 of Exhibit FJH-9. Under the DCF theory as applied in rate regulation, an

infinite holding period is presumed. The best estimation of the infinite (in practical

terms, a very long period of time) future is the arithmetic mean of actually experienced

equity risk premiums over a very long historical time period. Ibbotson Associates points

out that without an appreciation of the very-long past it would have been statistically

improbable to predict the stock market crash of 1987 because the 1929-31 period would

not have been factored in.

Why did you use the arithmetic mean return rates instead of the geometric (or

compound) mean return rates in your calculations of equity risk premium?

Historical total returns and equity risk premium spreads differ in size and direction over

time. The arithmetic mean is important because it provides insight into the variance and

standard deviation of returns. Investors require insight into the potential for volatility,

i.e., variance, when contemplating making an investment. Insight into the variance can

only be obtained by the use of the arithmetic mean of historical returns. Absent valuable

insight into the potential variance of returns, there can be no meaningful evaluation of

prospective risk. Ifinvestors relied upon the geometric mean of historical returns, they

would have no insight into the potential variance of future returns because the geometric

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mean relates the changes over many periods to a constant rate of change, thereby

obviating the year-to-year fluctuations, or variance, critical to risk analysis. Workpaper

No.4 to Exhibit FJH-9 (FJH WP-9) contains the full content of the explanation by

Ibbotson Associates as to why the use of the arithmetic mean is appropriate when

estimating the cost of capital. It conlirms that equity risk premiums are random with

serial correlation near zero. Because they are random, the best estimate of the future is

the arithmetic mean of all the historic equity risk premiums.

Please explain the second equity risk premium study which you utilized.

The second risk premium study is one performed by my firm relative to the Standard &

Poor's Public Utility Index. It covers the periods fTom 1928 through the closest prior

year-end available preceding each of the locked-in years and the going-forward period

as shown on pages 7 through 9 of Exhibit FJH-9. After the deduction fTomtotal returns

of the yields on the Salomon Brothers' high grade corporate bond index, a utility equity

risk premium is derived (e.g., Line 3, pages 7 through 9). After adjustments to reflect

average bond yield differentials between high grade corporate and the average bond

rating ofthe proxy groups of oil and gas pipeline companies, respectively, (e.g., Line 4,

pages 7 through 9), adjusted equity risk premiums were derived (e.g., Line 5, pages 7

through 9).

Please discuss your findings of RPM cost rates.

They are shown in summary form on page I of Exhibit FJH-9. They range fToma low

of J 1.5% for the proxy group of five oil pipeline companies applicable to the going-

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forward period to a high of 13.7% applicable to the four gas pipeline holding companies

for the year 2001.

The Capital Asset Pricing Model (CAPM)

Theoretical Basis

Please explain the theoretical basis of the CAPM.

The CAPM defines risk as the covariability of a security's returns with the market's

returns. This covariability is measured by beta ("a"), an index measure of an individual

security's variability relative to the market. A beta less than 1.0 indicates lower

variability while a beta greater than 1.0 indicates greater variability than the market.

The CAPM assumes that all non-market or unsystematic risk, can be eliminated

through diversification. The risk that cannot be eliminated through diversification is

called market, or systematic, risk. The model presumes that investors require

compensation for risks that cannot be eliminated through diversification. Systematic

risks are caused by socioeconomic events that affect the returns on all assets. In essence,

the model is applied by adding a market risk premium to a risk-free rate ofretum. The

market risk premium is adjusted proportionally to reflect the systematic risk of the

individual security relative to the market as measured by beta.

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Traditional CAPM

Please describe the traditional CAPM.

The traditional CAPM is expressed as:

Where:R, = Return rate on the common stock

= Risk-free rate ofreturn

Return rate on the market as a whole

Adjusted beta (volatility of the securityrelative to the market as a whole)

Numerous tests of the CAPM have confirmed its validity. These tests have measured the

extent to which security returns and betas are related as predicted by the CAPM.

The Empirical CAPM

Please describe the empirical CAPM (ECAPM).

The ECAPM discussed by Morin reflects the reality that the empirical Security Market

Line (USML") described by the CAPM is not as steeply sloped as the predicted SML in

the traditional CAPM. Morin" states:

At the empirical level, there have been countless tests of theCAPM to determine to what extent security returns and betas arerelated in the manner predicted by the CAPM.12 The results of

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hL alp. 321.For a summary oflhe empirical evidence on the CAPM, see Jensen (19721 and Ross (1978). The majorempirical lesls of lhe CAPM were published by Friend and Blume (1975 I, Black, Jensen, and Scholes(1972), Miller and Scholes (19721, Blume and Friend (1973), Blume and Husic (1973), Fama and Macbelh(1973), Basu (1977), Reinganum (l98IB), Litzenberger and Ramaswamy (1979), Banz (1981.1,Gibbons(1982), Stambaugh (1982), and Shanken (1985). CAPM evidence in Ihe Canadian conlexi is available inMorin (1981).

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the tests support the idea that beta is related to security returns,that the risk-return tradeoff is positive, and that the relationshipis linear. The contradictory finding is that the empirical SecurityMarket Line (SML) is not as steeply sloped as the predicted SML.With few exceptions, the empirical studies agree that the impliedintercept term exceeds the risk-free rate and the slope term is lessthan predicted by the CAPM. That is, low-beta securities earnreturns somewhat higher than the CAPM would predict, and high-beta securities earn less than predicted.

* * *

Therefore, the empirical evidence suggests that the expectedreturn on a security is related to its risk by the followingapproximation:

where x is a fraction to be determined empirically. [T]he valueof x that best explains the observed relationship is between 0.25and 0.30. If x = 0.25, the equation becomes:

* * *

1will use the more conservative value of x, 0.25, in my applications of the ECAPM.

Applications of the CAPM

Did you apply the traditional and empirical forms ofthe CAPM to the proxy grou ps

of oil and gas pipeline companies?

Yes. The results are summarized on page 1 of Exhibit FJH-10 which consists of seven

pages. Pages 2 through 4 of Exhibit FJH-lO contain the details of my applications by

" Jd., at pp. 335-36.

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group, company and period. Pages 5 through 7 contain notes related to pages 2

through 4.

What risk-free rates did you utilize aDd why?

In both the CAPM and ECAPM, I utilized the average consensus forecasts by the

approximately 50 economists who regularly respond to surveys by Blue Chip Financial

Forecasts. Ispecifically relied upon the consensus forecasts of the yields on long-term

U.S. Treasury Bonds (yields are no longer available on 30-year U.S. Treasury Bonds) for

the subsequent six calendar quarters reported in the January I issue for each of the years

200 I and 2002 and the August I,2003, issue. Irely on those yields because the yield on

long-term U.S. Treasury Bonds is almost risk-free and its term is consistent with the

long-term cost of capital to public utilities measured by the yields on long-term utility

bonds and more closely matches the long-term investment horizon inherent in utilities'

cornmon stocks. Moreover, use of the long-term U.S. Treasury Bond yield as the proxy

for the risk-free rate is consistent with the long-term investment horizon, which is

presumed to be infinite, in the standard regulatory version of the DCF model employed

in proceedings such as these. In addition, Ibbotson Associates" states:

A cornmon choice for the nominal riskless rate is the yield on aU.S. Treasury Security. The ability of the U.S. government tocreate money to fulfill its debt obligations under virtually anyscenario makes U.S. Treasury securities practically default-free.While interest rate changes cause government obligations tofluctuate in price, investors face essentially no default risk as toeither coupon payment or return of principal. The horizon of thechosen Treasury security should match the horizon of whatever

" Stocks. Bonds. Bills and Inflation: 2003 Yearbook - Valuation Edition. Ibbotson Associates, Chicago.IL, p. 53.

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is being valued. When valuating a business that is being treatedas a going concern. the appropriate Treasurv yield should be thatof a long-ternl Treasury bond. Note that the horizon is a functionof the investment. not the investor. If an investor plans to holdstock in a company for only five years, the yield on a five-yearTreasury note would not be appropriate since the company willcontinue to exist beyond those five years. (underlining added foremphasis)

How did you determine the total returns on the market to use in your applications

of the CAPM and ECAPM?

I used the arithmetic average of the long-term historical returns on the market from

Ibbotson Associates for the same reasons provided previously regarding equity risk

premiums in my applications of the RPM. I explain in Notes 1,7 and 12 on pages 5 and

6 of Exhibit FJH-I 0 how the historical, as well as the Value Line forec.asted, total market

returns were calculated. From each total market return I subtracted the risk-free rates of

return to derive the market risk premiums.

What hetas did you use'!

I used the most recent Value Line adjusted betas which were available to investors on or

about December 31, preceding each locked-in year and the most recent available on

August I, 2003, as applicable to the going-forward period. The betas are shown by

company, group and year on pages 2 through 4 of Exhibit FJH-I O.

22 6.d.l Traditional CAPM Results

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What cost rates resulted from your applications of the traditional CAPM?

As shown in summary fornl on page I of Exhibit FJH-l 0, the cost rates range from a low

of 10.9% for the proxy group of five oil pipeline companies applicable to the going-

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forward period, to a high of 14.2% for the proxy group of four gas pipeline holding

2 companies applicable to the year 2001.

3 6.d.2 Empirical CAPM Results

4 Q.

5 A.

What cost rates resulted from your application of the ECAPM?

These rates are also summarized on page I of Exhibit F JH-l O. They range from a low

6 of 11.7% for the proxy group of five oil pipeline companies applicable to the going-

7 forward period to a high of 14.8% for the proxy group of four gas pipeline holding

8 companies applicable to the year 2001.

9 6.d.3 Summary ofCAPM Conclusion

What are your conclusions of CAPM cost rates?

Although I have shown both the traditional and EeAPM cost rates and the averages of

both for each period, Irely upon only the ECAPM results in order to be consistent with

Order No. 151. The ECAPM cost rates range from a low of 11.7% for the proxy group

oftive oil pipeline companies applicable to the going-forward period to a high of 14.8%

for the proxy group of four gas pipeline holding companies applicable to the year 2001.

Comparable Earnings Model ICEI'D

Theoretical Basis

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Please describe the theoretical basis of the CEM.

The comparable earnings standard recognizes the fundamental economic concept of

opportunity cost. This concept states that the cost of using any resource -- land, labor

and/or capital -- for a specific purpose is the return that could have been eamed in the

next best alternative use. The opportunity cost to an investor in a utility's common stock

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is what that capital would yield in an alternative investment of similar risk. The

opportunity cost principle is consistent with one of the fundamental principles of utility

price regulation: It is intended to act as a surrogate for competition.

The problem in using returns on book equity or net worth (the ROEs) of non-

price regulated companies operating in the competitive marketplace is determining

whether such companies are similar in risk to the regulated utility. The ROEs of other

similar price regulated firms either should not be relied upon at all or should be used with

extreme caution because they reflect the result of regulatory awards. Consequently, they

may not be indicative of what could have been earned in a competitive market.

Consequently, application of the CEM is most appropriately implemented by examining

the ROEs of similar risk, domestic, non-price regulated firms.

Market-Based Selection of Comparable Risk Companies

Is your approacb to tbe selection of comparable risk, domestic, non-price regulated

companies market-based?

Yes.

Please explain.

My application of the CEM is market-based because the selection of the comparable risk,

domestic, non-price regulated firms is based upon statistics derived from the market

prices paid by investors, i.e., the betas and related statistics utilized in the selection

process result from regression analyses of market prices over the most recent five years

available from Value Line just prior to the beginning of each applicable period, i.e.,

August 2003, the going-forward period, and the locked-in years 2002 and 2001. Under

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the EMH, the market prices paid by investors reflect investors' perceptions of all risks.

Consequently, the bases of selection resulted in proxy groups of non-price regulated

firms comparable in total risk (the sum ofnon-diversifiablemarket risk and diversifiable

company-specific risks) to each of the two proxy groups, i.e., the five oil and the

four/three gas pipeline holding companies, respectively. The criteria used in the selection

of the non-price regulated proxy companies comparable to each proxy group were:

I. They must be domestic, non-price regulated companies, i.e., non-utilities.

2. They must have a meaningful projected five-year rate of return on networth or partner's capital of less than 20% as reported in Value LineInvestment Survey (Standard Edition).

3. Their betas must lie within plus or minus two standard deviations of theaverage unadjusted betas of each proxy group.

4. Their standard errors ofthe regressions must lie within plus or minus twostandard deviations ofthe standard errors of the regressions of each proxygroup.

Wby are tbe companies selected comparable in total risk to eacb group?

Betas are measures of non-diversifiable systematic market risk. Companies which have

similar betas have similar systematic risk. The standard errors of the regressions (the

standard errors of the estimate resulting from the regression equations from which each

company's beta was derived by Value Line) were used to measure each tirnl's

diversifiable company-specific risks. Thus, the standard errors of the regressions

measure the extent to which events specific to a company affect its stock price. In

essence, they reflect the residual diversifiable risks of a firm which are not reflected in

beta, which is a measure of non-diversifiable, market, risk. Companies with similar

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standard errors have similar diversi fiable risks. Consequently, companies which have

similar betas and similar standard errors of the regressions have similar total investment

risk (the sum ofnon-diversifiable, market, risk measured by beta and diversifiable, non-

market, risks measured by similar standard errors) because those statistics result from

regression analyses of market prices which reflect investors' perception of all risks

consistent with the EMH.

All of the non-price regulated fimls were ehosen based on ranges of betas and

standard errors of the regressions. The ranges were based upon two standard deviations

from the average standard deviation of the beta and the standard error of the regression

for each respective proxy group. The use of two standard deviations reflects 95.5% of

the universe of comparable companies, thus assuring comparability of total investment

risk.

It is true that individual business and financial risks will vary, but ifthe collective

average of the group of non-price regulated companies is chosen as a proxy for each

proxy group of oil pipeline and gas pipeline holding companies in each period, then the

total, or aggregate, combined non-diversifiable market risk and diversi fiable non-market

risks are similar. Thus, because the non-price regulated companies are selected based

upon market data, they are comparable in total risk (even though individual risks may

vary) to the proxy groups of oil and gas pipeline companies. Consequently, the expected

rates ofeamings on the book equity of those non-price regulated companies comparable

to the oil and gas pipeline proxy groups are appropriate indicators of equity cost rates for

TAPS. They are appropriate because they are rates which are applicable to the common

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equity financed portion of a depreciated original cost rate ("DOC") (or net book value)

rate base. A DOC rate base is also consistent with Order No. 151.

Applications of the CEM

Please describe the results of your applications of the CEM.

As explained above, my market-based selection process was applied to the average

regression statistics for the oil and gas proxy groups for each period.

The results are shown in Exhibit FJH-II which consists of 12 pages. Page I is

a summary of the results by group and period. Pages 2 through 9 contain all of the

details, while pages 10 through 12 contain all the notes relevant to pages 2 through 9.

The number of comparable companies varies by period for each group because of the

different regression statistics used in the selection process for each period.

On pages 2 through 9, I have shown the five-year projected ROEs available to

investors at the time they could have formulated opinions of common equity cost rate

relative to each period.

I relied on the median projected ROEs. As a result, the CEM cost rates range

from a low of 11.8% for the proxy group offive oil pipeline companies applicable to the

year 2001 to a high of 14.5% for the proxy group offour gas pipeline holding companies

applicable to the year 2001 as shown on page I of Exhibit FJH-I1.

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Recommended Common Equity Cost Rates

How did .r0u arrive at }'our recommended common equit} cost rates for each

period?

Afier applying all four cost of common equity models as described above, I observed the

average common equity cost rate for each group for each period as shown on Exhibit

FJH-2. Consistent with Order No. 151, Irelied upon the two proxy groups, namely of

five oil and four or three gas pipeline companies (three for the going-forward period

based on August 2003 information) respectively for the reasons discussed previously.

I observed that in certain instances the results of the application of a single cost of

common equity model may be disparate from the results of the application of other cost

of common equity models. For example, on Exhibit FJH-2. it is shown that the average

DCF cost rate for the proxy group of three gas pipeline holding companies is 16.1% in

August 2003 applicable to the going-forward period in contrast to the range of the other

cost rates (i.e. from the RP, CAPM, and CFM models) which range between 12.0% and

12.5%. In other words, the aberrant cost rate in this instance is the DCF cost rate. This

exemplifies why the use of all four common equity models is essential and why the

average cost rate of 13.3% for the group of three gas pipeline companies for the going-

forward period is the most relevant based only on that proxy group. Similarly, it is also

shown on Exhibit FJH-2 that the average DCF cost rate ofl6.4% for the proxy group of

five oil pipeline companies is disparate from the range of 11.8% to 13.2% for the cost

rates derived from the other cost of equity models applicable to the year 200 I.

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After review of the average cost rates for each proxy group in each period with

reliance on the midpoint of the average cost rate for each proxy group the following

common equity cost rates are applicable to TAPS without and with regard to any risk

premium adder for early period risks:

Recommended Common EquityCost RatesPeriod

GoingForward 2002 2001

Without Regard to Premiumfor Added Risk 12.95% 13.15% 14.30%

Risk Premium Adder (1) N/A 0.375 0.75

Total Equity Cost Recommendation 12.95% 13.525% 15.05~"

(1) 75 basis points per Order No. 151 ends 6/30/02. Thus, only one-half, or 37.5basis points applies to 2002. No added premium is applicable to the going-forward period.

18 III. OVERALL COSTS OF CAPITAL AND FAlRRATES OF RETURN

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What are tbe overall costs of capital and fair rates of return which result from your

recommended capital structure ratios, debt and common equity cost rates?

A. All are summarized in Exhibit FJR-I. My recommended overall costs of capital and fair

rates of return, which include allowance for added risk premium through June 30, 2002,

are as follows:

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Recommended Overall Costs of CapitalPeriod

Going Forward

'----~-------_.~

9.46% 10.01% 11.41%

6 Q. Are your recommended overall costs of capital and fair rates of return applicable7 to a DOC cost rate base?

8 A. Yes. The ratemaking norm includes the use of a DOC rate base in virtually every state

9 jurisdiction. Such application would also be consistent with this Commission's Order

10 No. 151.

11 V. ANSWERING TESTIMONYe 12 V.A TAPS CARRIERS' WITNESS WILLIAMSON13 Q.14 A.

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Please summarize your answering testimony.

Although I agree with the use of the five oil pipeline proxy companies utilized by TAPS

Carriers' Witness Dr. Williamson, I will explain why I disagree with the composition of

his gas pipeline proxy groups for each of the three periods I analyzed, namely 2001,

2002, and the going-forward period. As a result of his inclusion of inappropriate gas

pipeline proxies, his recommended capital structure ratios are inappropriate. r will also

show that Dr. Williamson's failure to rely upon the CAPM, Risk Premium (uRP"), and

CEM as employed in this Commission's Order No. 151 is incorrect even though he states

at the bottom of page I and the top of page 2 of JPW T-2 that he was asked to apply the

approach adopted by this Conmlission in Order No. 151. As a result of his failure to

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apply the approach adopted by this Commission in Order No. 151, his recommended

common equity cosl rates are overstated; and by the inclusion of a full 75 basis points

added risk premium for early periods beyond June 30, 2002, his recommended rates of

return for 2002 and the going-forward period are overstated. Moreover, by averaging his

weighted costs of capital for all periods, and including the full 75 basis points for all

periods, the overstatement of the weighted costs (or overall cost of capital) for each

period is exacerbated. It is further exacerbated by his recommendation of common

equity cost rates which rely solely on the DCF model, contrary to Order No. 151.

I will show that his criticisms of the CAPM, RP and CEM models utilized in

Order No. 151 are incorrect and that his sole reliance on DCF is inconsistent with Order

No. 151 and his own prior testimonies.

You indicated that you have differences with the gas pipeline proxy companies

utilized by Dr. Williamson for eacb period. Please explain the differences and why

you believe Dr. Williamson's choices are incorrect.

Let me preface my response by stating that other than the exceptions discussed below,

I agree with the other companies included or excluded for the reasons stated by

Dr. Williamson in JPW T-2 at page 4.

My selection of the gas pipeline holding companies for use in determining capital

structures, cost of equity, etc., applicable to 2001 are based on information available at

the end of calendar year 2000. Dr. Williamson included Coastal Corp. I do not believe

that Coastal Corp. is appropriate to be included in a proxy group for use in determining

a fair rate of return for the year 200 I. On January 1S, 2000. EI Paso Energy Corp.

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announced that it was buying Coastal Corp. (See pages 1-2 of Exhibit Flli-12).

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Moreover, it is also shown in the Value Line issue of December 22, 2000 (page 3 of

Dr. Williamson did not include Kinder Morgan, Inc. in his proxy group used to

Exhibit Flli-12) that Coastal's merger with El Paso Energy was imminent. In fact, the

merger was consummated on January 29,2001. Therefore, inclusion of Coastal Corp.

as a proxy gas