BEFORE THE FEDERAL ENERGY REGULATORY ... - Tampa Electric

BEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

DOCKET NO. ER10-____-000

DIRECT TESTIMONY AND EXHIBIT

OF

WILLIAM E. AVERA

ON BEHALF OF TAMPA ELECTRIC COMPANY

DOCKET NO. ER10-____-000 EXHIBIT NO. TEC-200 FILED: 07/30/2010

WILLIAM E. AVERA 1

DIRECT TESTIMONY AND EXHIBIT INDEX 2

3

INTRODUCTION AND EXPERIENCE................................1 4

Qualifications........................................1 5

Overview..............................................4 6

Summary and Conclusions...............................7 7

FUNDAMENTAL ANALYSES.......................................9 8

Tampa Electric Company................................9 9

Electric Power Industry..............................12 10

Impact of Capital Market Conditions..................21 11

CAPITAL MARKET ESTIMATES..................................26 12

Cost of Equity Concept...............................26 13

Development and Selection of a Proxy Group...........31 14

DCF Model ...........................................44 15

Evaluation of DCF Results............................49 16

Evaluating an ROE Point Estimate.....................59 17

Flotation Costs......................................67 18

ROE BENCHMARKS............................................70 19

Non-Utility DCF Model................................73 20

Expected Earnings Approach...........................79 21

ROE FOR TAMPA ELECTRIC....................................83 22

Implications for Financial Integrity.................84 23

Capital Structure....................................92 24

ROE Recommendation...................................99 25


EXHIBITS.................................................104 1

2

Exhibit No. Description 3

TEC-201 Qualifications of William E. Avera 4

TEC-202 Risk Measures – Regional Proxy Group 5

TEC-203 Risk Measures – Ratings Screen Proxy Group 6

TEC-204 FERC DCF Model – Regional Proxy Group 7

TEC-205 “br + sv” Growth Rate – Regional Proxy Group 8

TEC-206 FERC DCF Model – Ratings Screen Proxy Group 9

TEC-207 DCF Model – Non-Utility Proxy Group 10

TEC-208 “br + sv” Growth Rate – Non-Utility Proxy Group 11

TEC-209 Expected Earnings Approach – Regional and 12

Ratings Screen Proxy Groups 13

TEC-210 Capital Structure – Regional and Ratings Screen 14

Proxy Groups 15

TEC-211 Capital Structure – Operating Companies 16

17

18

19

20

21

22

23

24

25


BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION 1

PREPARED DIRECT TESTIMONY 2

OF 3

WILLIAM E. AVERA 4

ON BEHALF OF TAMPA ELECTRIC COMPANY 5

6

INTRODUCTION AND EXPERIENCE 7

Q. Please state your name and business address. 8

9

A. William E. Avera, 3907 Red River, Austin, Texas, 78751. 10

11

Q. In what capacity are you employed? 12

13

A. I am the President of FINCAP, Inc., a firm providing 14

financial, economic, and policy consulting services to 15

business and government. 16

17

Qualifications 18

Q. What are your qualifications? 19

20

A. I received a B.A. degree with a major in economics from 21

Emory University. After serving in the U.S. Navy, I 22

entered the doctoral program in economics at the 23

University of North Carolina at Chapel Hill. Upon 24

receiving my Ph.D., I joined the faculty at the 25


2

University of North Carolina and taught finance in the 1

Graduate School of Business. I subsequently accepted a 2

position at the University of Texas at Austin where I 3

taught courses in financial management and investment 4

analysis. I then went to work for International Paper 5

Company in New York City as Manager of Financial 6

Education, a position in which I had responsibility for 7

all corporate education programs in finance, accounting, 8

and economics. 9

10

In 1977, I joined the staff of the Public Utility 11

Commission of Texas (“PUCT”) as Director of the Economic 12

Research Division. During my tenure at the PUCT, I 13

managed a division responsible for financial analysis, 14

cost allocation and rate design, economic and financial 15

research, and data processing systems, and I testified in 16

cases on a variety of financial and economic issues. 17

Since leaving the PUCT in 1979, I have been engaged as a 18

consultant. I have participated in a wide range of 19

assignments involving utility-related matters on behalf 20

of utilities, industrial customers, municipalities, and 21

regulatory commissions. I have previously testified 22

before the Federal Energy Regulatory Commission (“FERC” 23

or the “Commission”), as well as the Federal 24

Communications Commission (“FCC”), the Surface 25


3

Transportation Board (and its predecessor, the Interstate 1

Commerce Commission), the Canadian Radio-Television and 2

Telecommunications Commission, and regulatory agencies, 3

courts, and legislative committees in over 40 states. 4

5

In 1995, I was appointed by the PUCT, with the approval 6

of the Governor, to the Synchronous Interconnection 7

Committee to advise the Texas legislature on the costs 8

and benefits of connecting Texas to the national electric 9

transmission grid. In addition, I served as an outside 10

director of Georgia System Operations Corporation, the 11

system operator for electric cooperatives in Georgia. 12

13

I have served as Lecturer in the Finance Department at 14

the University of Texas at Austin and taught in the 15

evening graduate program at St. Edward’s University for 16

twenty years. In addition, I have lectured on economic 17

and regulatory topics in programs sponsored by 18

universities and industry groups. I have taught in 19

hundreds of educational programs for financial analysts 20

in programs sponsored by the Association for Investment 21

Management and Research, the Financial Analysts Review, 22

and local financial analysts societies. These programs 23

have been presented in Asia, Europe, and North America, 24

including the Financial Analysts Seminar at Northwestern 25


4

University. I hold the Chartered Financial Analyst (CFA®) 1

designation and have served as Vice President for 2

Membership of the Financial Management Association. I 3

have also served on the Board of Directors of the North 4

Carolina Society of Financial Analysts. I was elected 5

Vice Chairman of the National Association of Regulatory 6

Utility Commissioners (“NARUC”) Subcommittee on Economics 7

and appointed to NARUC’s Technical Subcommittee on the 8

National Energy Act. I have also served as an officer of 9

various other professional organizations and societies. 10

11

Overview 12

Q. What is the purpose of your testimony? 13

14

A. The purpose of my testimony is to present to the FERC my 15

independent analysis of a fair rate of Return on Equity 16

(“ROE”) for the jurisdictional wholesale electric utility 17

operations of Tampa Electric Company (“Tampa Electric” or 18

“the Company”). My evaluation considered FERC’s 19

established precedent and policy objectives, industry 20

conditions and fundamentals, independent estimates of the 21

ROE for alternative benchmark groups of electric 22

utilities, as well as the particular exposures 23

confronting the Company and its electric production and 24

transmission systems. 25


5

Q. Please summarize the basis of your knowledge and 1

conclusions concerning the issues to which you are 2

testifying in this case. 3

4

A. To prepare my testimony, I used information from a 5

variety of sources that would normally be relied upon by 6

a person in my capacity. In connection with the present 7

filing, I considered and relied upon corporate 8

disclosures, publicly available financial reports and 9

filings, and other published information relating to 10

Tampa Electric. In addition, I am familiar with FERC 11

policy generally and have submitted testimony in numerous 12

proceedings at the Commission dealing with required rates 13

of return for electric utilities.1 I also reviewed 14

information relating generally to capital markets and 15

specifically to investor perceptions, requirements, and 16

expectations for regulated utilities in a restructured 17

wholesale electric power market. These sources, coupled 18

with my experience in the fields of finance and utility 19

regulation, have given me a working knowledge of ROE 20

issues affecting Tampa Electric and are the basis of my 21

conclusions. 22

1 See, e.g., Docket No. ER00-3316-000 on behalf of American Transmission Company, LLC, Docket No. ER02-485-000 involving the Midwest Independent Transmission System Operator, Inc., Docket No. ER04-157-000 on behalf of the transmission-owning members of the ISO New England, Inc., Docket No. ER07-562-000 on behalf of Trans-Allegheny Interstate Line Company, Docket No. ER08-386-000 on behalf of Potomac-Appalachian Transmission Highline, LLC, Docket No. EL08-31-000 on behalf of Westar Energy, Inc., and Docket No. ER08-686-000 on behalf of Pepco Holdings, Inc.


6

Q. What is the role of the ROE in setting a utility’s rates? 1

2

A. The rate of return on common equity compensates 3

shareholders for the use of their capital to finance the 4

plant and equipment necessary to provide utility service. 5

Investors commit capital only if they expect to earn a 6

return on their investment commensurate with returns 7

available from alternative investments with comparable 8

risks. To be consistent with sound regulatory economics 9

and the standards set forth by the Supreme Court in the 10

Bluefield2 and Hope3 cases, a utility’s allowed return on 11

common equity should be sufficient to: (1) fairly 12

compensate investors for capital they have invested in 13

the utility, (2) enable the utility to offer a return 14

adequate to attract new capital on reasonable terms, and 15

(3) maintain the utility’s financial integrity. 16

17

Q. How did you go about evaluating the ROE for Tampa 18

Electric? 19

20

A. I first reviewed the operations and finances of Tampa 21

Electric, as well as the general conditions in the 22

electric utility industry. With this background, I 23

2 Bluefield Water Works & Improvement Co. v. Pub. Serv. Comm’n, 262 U.S. 679 (1923).

3 FPC v. Hope Natural Gas Co., 320 U.S. 591 (1944).


7

examined current capital market conditions and conducted 1

quantitative analyses to estimate the current cost of 2

equity. Consistent with Commission precedent,4 I relied 3

on the Discounted Cash Flow (“DCF”) methodology, 4

currently prescribed by FERC, and applied it to a proxy 5

group of other electric utilities with a direct 6

correlation to Tampa Electric and the broader markets in 7

which the Company operates. In addition, I examined 8

alternative ROE benchmarks that included DCF cost of 9

equity estimates for a proxy group of low-risk industrial 10

firms and expected earned rates of return for utilities. 11

12

Summary and Conclusions 13

Q. Based on your evaluation, what did you conclude regarding 14

a fair ROE for Tampa Electric? 15

16

A. I recommend an ROE for Tampa Electric of 11.25 percent. 17

My recommendation falls well within the 8.2 percent to 18

13.6 percent zone of reasonableness produced by applying 19

the Commission-approved DCF approach to the proxy group 20

of nine regional electric utilities. While my 11.25 21

percent ROE recommendation exceeds the midpoint and 22

4 See, e.g., Bangor Hydro-Elec. Co., 117 FERC ¶ 61,129 (2006) (“Bangor Hydro”); Midwest

Indep. Transmission Sys. Operator, Inc., 100 FERC ¶ 61,292 (2002) (“Midwest ISO”), reh’g denied, 102 FERC ¶ 61,143 (2003), modified on other grounds sub nom. Pub. Serv. Comm’n v. FERC, 397 F.3d 1004 (D.C. Cir. 2005); S. Cal. Edison Co., 92 FERC ¶ 61,070 (2000) (“Southern California Edison”), reh’g denied, 108 FERC ¶ 61,085 (2004).


8

median produced using the Commission’s DCF approach, an 1

ROE above these values is supported by reference to 2

alternative ROE benchmarks, which consistently support a 3

higher allowed return. In evaluating the ROE for 4

jurisdictional utility operations, it is also important 5

to consider the uncertainties associated with Tampa 6

Electric and the challenges the Company faces in raising 7

the capital required to finance significant planned 8

infrastructure investment – including a renewed focus on 9

regulatory uncertainties. 10

11

My conclusions are reinforced by the need to consider 12

flotation costs, and the fact that current cost of 13

capital estimates are likely to understate investors’ 14

requirements at the time the outcome of this proceeding 15

becomes effective and beyond. Moreover, ongoing turmoil 16

in the domestic and global financial markets and 17

continued economic uncertainties have exacerbated the 18

risks faced by utilities and their investors. In 19

addition, my recommendation also considers the 20

Commission’s policy goal of attracting the capital 21

investment to expand utility infrastructure necessary to 22

support efficient, reliable wholesale power markets. 23

Taken together, these considerations confirm the 24

reasonableness of my recommended range and support an 25


9

11.25 percent ROE for Tampa Electric. 1

2

FUNDAMENTAL ANALYSES 3

Q. What is the purpose of this section? 4

5

A. As a predicate to the quantitative analyses that I 6

address later in this testimony, this section briefly 7

reviews the operations and finances of Tampa Electric. In 8

addition, it examines the risks and prospects for the 9

electric utility industry and conditions in the capital 10

markets and the general economy. An understanding of the 11

fundamental factors driving the risks and prospects of 12

electric utilities is essential in developing an informed 13

opinion of investors’ expectations and requirements that 14

are the basis of a fair rate of return. 15

16

Tampa Electric Company 17

Q. Please briefly describe Tampa Electric. 18

19

A. Tampa Electric is the principal subsidiary of TECO 20

Energy, Inc. (“TECO Energy”). Headquartered in Tampa, 21

Florida, Tampa Electric provides electric generation, 22

transmission, and distribution utility services 23

throughout an area of approximately 2,000 square miles in 24

West Central Florida, including Hillsborough County and 25


10

parts of Polk, Pasco and Pinellas Counties, with an 1

estimated population of over one million. The principal 2

communities served are Tampa, Winter Haven, Plant City 3

and Dade City. In addition, Tampa Electric engages in 4

wholesale sales to utilities and other resellers of 5

electricity. Through its Peoples Gas System division, 6

Tampa Electric also purchases, distributes and markets 7

natural gas to more than 334,000 residential, commercial, 8

industrial and electric power generation customers in the 9

state of Florida. 10

11

During 2009, approximately 49 percent of Tampa Electric’s 12

total operating revenue was derived from residential 13

sales, 31 percent from commercial sales, 9 percent from 14

industrial sales, and 11 percent from other sales, 15

including bulk power sales for resale. Tampa Electric’s 16

generating resources have a combined capacity of 17

approximately 4,700 megawatts. Approximately 55 percent 18

of Tampa Electric’s generation of electricity for 2009 19

was coal-fired, with natural gas representing 20

approximately 45 percent and oil representing less than 1 21

percent. Tampa Electric used its generating units to meet 22

approximately 91 percent of the total system load 23

requirements, with the remaining 9 percent coming from 24

purchased power. 25


11

Tampa Electric's transmission and distribution facilities 1

include over 7,700 miles of overhead lines and 2

approximately 4,470 miles of underground cables. At 3

December 31, 2009, Tampa Electric’s investment in assets 4

amounted to approximately $6.3 billion, with revenues 5

totaling approximately $2.9 billion. Tampa Electric's 6

retail electric operations are subject to the 7

jurisdiction of the Florida Public Service Commission 8

(“FPSC”), with wholesale power and interstate 9

transmission service regulated by FERC. 10

11

Q. Is Tampa Electric interconnected with other utilities 12

through a regional reliability organization? 13

14

A. Yes. Tampa Electric is interconnected with electric 15

power systems in the southeast through the Florida 16

Reliability Coordinating Council, Inc. (“FRCC”), which 17

serves as a regional entity for the purpose of proposing 18

and enforcing reliability standards and coordinating and 19

planning the bulk electric system in Florida. The area 20

of Florida that is within the FRCC region is peninsular 21

Florida east of the Apalachicola River, while the 22

panhandle area west of the Apalachicola River is within 23

the scope of the SERC Reliability Corporation (“SERC”). 24

25


12

Q. What credit ratings have been assigned to Tampa Electric? 1

2

A. Currently, Tampa Electric is assigned a corporate credit 3

rating of “BBB” by Standard & Poor’s Corporation (“S&P”), 4

with Moody’s Investors Service (“Moody’s”) assigning an 5

issuer rating of “Baa1”. Meanwhile, Fitch Ratings Ltd. 6

(“Fitch”) has assigned the Company a “BBB” issuer default 7

rating. 8

9

Electric Power Industry 10

Q. What general conditions have characterized the electric 11

power industry? 12

13

A. Since the 1990s, the industry has experienced significant 14

structural change resulting from market forces and 15

regulatory initiatives. At least initially, this process 16

was largely driven by regulatory reforms at the federal 17

level. The Energy Policy Act of 1992 greatly facilitated 18

competition for the production and sale of power at the 19

wholesale level, with FERC being a proponent of actions 20

designed to foster greater competition in markets for 21

wholesale power supply. 22

23

In April 1996, the Commission adopted Order No. 888,5 24

5 Promoting Wholesale Competition Through Open Access Non-Discriminatory Transmission Services by Public Utilities; Recovery of Stranded Costs by Public Utilities and Transmitting Utilities, Order No. 888, 1991-1996 FERC Stats. & Regs., Regs. Preambles ¶ 31,036 (1996), order on reh’g, Order No. 888-A, 1996-2000 FERC Stats. & Regs., Regs. Preambles ¶ 31,048, order on reh’g, Order No. 888-B, 81 FERC ¶ 61,248 (1997), reh’g denied, Order No. 888-C, 82 FERC ¶ 61,046 (1998), aff’d in part and remanded in part sub nom. Transmission Access Policy Study Group v. FERC, 225 F.3d 667 (D.C. Cir. 2000), aff’d sub nom. N.Y. v. FERC, 535 U.S. 1 (2002).


13

which mandated open access to the wholesale transmission 1

facilities of jurisdictional electric utilities. The 2

Commission later promoted improvements to the 3

transmission system and has continued to pursue the goal 4

of creating “seamless” wholesale power markets that 5

facilitate transactions across transmission grid 6

boundaries, among other objectives. In response to the 7

passage of the Energy Policy Act of 2005 (“EPAct 2005”), 8

FERC also issued its Order Nos. 679 and 679-A, 9

establishing incentive-based rate treatments to promote 10

greater capital investment in electric utility 11

infrastructure. 12

13

Q. How have investors’ risk perceptions for the utility 14

industry evolved? 15

16

A. Implementation of these structural changes and related 17

events have caused investors to rethink their assessment 18

of the relative risks associated with the utility 19

industry. The past decade witnessed steady erosion in 20

credit quality throughout the electric power industry, 21

both as a result of revised perceptions of the risks in 22

the industry and the weakened finances of industry 23

participants themselves. Late last year, S&P observed 24

with respect to the industry’s future that: 25

26


14

Looming costs associated with environmental 1 compliance, slack demand caused by economic 2 weakness, the potential for permanent demand 3 destruction caused by changes in consumer 4 behavior and closing of manufacturing 5 facilities, and numerous regulatory filings 6 seeking recovery of costs are some of the 7 significant challenges the industry has to deal 8 with.6 9

10

Q. Does Tampa Electric anticipate the need to access 11

the capital markets going forward? 12

13

A. Yes. Tampa Electric will require capital investment to 14

provide for necessary maintenance and replacements and 15

fund new investments in the facilities needed to 16

generate, transmit and distribute electricity, which are 17

expected to total over $1.2 billion over the years 2011 18

to 2014.7 19

20

Continued support for Tampa Electric’s financial 21

integrity and flexibility will be instrumental in 22

attracting the long-term capital necessary to fund these 23

projects in an effective manner. In addition, Tampa 24

Electric will be required to refinance maturing debt 25

issues and must meet short-term liquidity needs arising 26

from seasonal cash flows and ongoing construction 27

6 Standard & Poor’s Corporation, “U.S. Regulated Electric Utilities Head Into 2010 With Familiar Concerns,” RatingsDirect (Dec. 28, 2009).

7 TECO Energy, Inc., 2009 Form 10-K Report at 57.


15

programs. Tampa Electric’s exposure to storm restoration 1

activities magnifies the importance of maintaining 2

financial flexibility, which is essential to guarantee 3

access to the cash resources and interim financing 4

required to cover operating cash flows and fund required 5

investments in the utility system. 6

7

Q. Is the potential for energy market volatility an ongoing 8

concern for investors? 9

10

A. Yes. In recent years, utilities and their customers have 11

had to contend with dramatic fluctuations in energy costs 12

due to ongoing price volatility in the spot markets and 13

investors recognize the prospect of further turmoil in 14

energy markets. In times of extreme volatility, 15

utilities can quickly find themselves in a significant 16

under-recovery position with respect to power costs, 17

which can severely stress liquidity. Moody’s has warned 18

investors of ongoing exposure to “extremely volatile” 19

energy commodity costs, including purchased power prices, 20

which are heavily influenced by fuel costs,8 and Fitch 21

noted that rapidly rising energy costs created 22

vulnerability in the utility industry.9 23

8 Moody’s Investors Service, “Storm Clouds Gathering on the Horizon for the North American Electric Utility Sector,” Special Comment (Aug. 2007).

9 Fitch Ratings Ltd., “Staying Afloat: Downstream Liquidity in the Energy and Power Sectors,” Oil & Gas / Global Power Special Report (June 16, 2008).


16

For example, while coal has historically provided 1

relative stability with respect to fuel costs, the Energy 2

Information Administration (“EIA”), a statistical agency 3

of the U.S. Department of Energy (“DOE”), reported that 4

prices for Central and Northern Appalachia coal spiked 5

from approximately $45 per ton in June 2007 to over $140 6

per ton in September 2008, before falling back into the 7

$40 to $50 range in September 2009.10 8

9

The power industry and its customers have also had to 10

contend with dramatic fluctuations in gas costs due to 11

ongoing price volatility in the spot markets. Fitch has 12

highlighted the challenges that fluctuations in energy 13

prices can have for utilities and noted that: 14

15

The sharp run-up and subsequent collapse of 16 natural gas prices in 2008 is emblematic of the 17 extreme price volatility that characterizes the 18 commodity and is likely to persist in the 19 future.11 20

21

Moody’s concluded that natural gas “remains highly 22

volatile,” and warned that such price fluctuations “could 23

have a significant impact on a utility’s liquidity 24

10 Energy Information Administration, Coal News and Markets (Jun. 20 & Sep. 26, 2008, Oct. 13, 2009).

11 Fitch Ratings, Ltd., “U.S. Utilities, Power and Gas 2009 Outlook,” Global Power North American Special Report (Dec. 22, 2008).


17

profile.”12 1

2

While expectations for significantly lower power prices 3

reflect weaker fundamentals affecting current load and 4

fuel prices, investors recognize the potential that such 5

trends could quickly reverse. S&P observed that “short-6

term price volatility from numerous possibilities … is 7

always possible”,13 while Fitch noted, “uncertainty 8

regarding fuel prices, in particular natural gas costs, 9

has made planning for the future even more problematic.”14 10

Moody’s concluded that utilities remain exposed to 11

“volatile commodity prices … which can wreak havoc on 12

even the strongest utility liquidity profiles.”15 13

14

Q. What other financial pressures impact investors’ risk 15

assessment of electric utilities? 16

17

A. Investors are aware of the financial and regulatory 18

pressures faced by utilities associated with both rising 19

costs and the need to undertake significant capital 20

investments. As Moody’s observed: 21

12 Moody’s Investors Service, “Carbon Risks Becoming More Imminent for U.S. Electric Utility Sector,” Special Comment (March 2009).

13 Standard & Poor’s Corporation, “Top 10 Investor Questions: U.S. Regulated Electric Utilities,” RatingsDirect (Jan. 22, 2010).

14 Fitch Ratings, Ltd., “Electric Utility Capital Spending: The Show Will Go On,” Global Power U.S. and Canada Special Report (Oct. 14, 2009).

15 Moody’s Investors Service, “U.S. Electric Utilities Face Challenges Beyond Near-Term,” Industry Outlook (Jan. 2010).


18

Utilities remain exposed to large, long-term 1 capital investment challenges, volatile 2 commodity prices and legal judgments that can 3 wreak havoc on even the strongest liquidity 4 profiles.16 5

6

Similarly, S&P recently noted that cost increases and 7

capital projects, along with uncertain load growth, were 8

a significant challenge to the utility industry.17 Fitch 9

reached similar conclusions: 10

11

The combination of high capital expenditures 12 and relatively weak electricity demand will 13 continue to pressure credit quality and require 14 base rate increases in 2010 and beyond.18 15

16

As noted earlier, investors are aware that Tampa Electric 17

will undertake significant electric utility capital 18

expenditures. Providing the infrastructure necessary to 19

meet the energy needs of customers imposes additional 20

financial responsibilities and risks on Tampa Electric. 21

22

Q. Are environmental considerations also affecting 23

investors’ evaluation of electric utilities? 24

25

A. Yes. Although Tampa Electric’s exposure has been 26


17 Standard & Poor’s Corporation, “Industry Economic And Ratings Outlook,” RatingsDirect (Feb. 2, 2010).

18 Fitch Ratings Ltd., “U.S. Utilities, Power, and Gas 2010 Outlook,” Global Power North America Special Report (Dec. 4, 2009).


19

moderated through its ability to recoup certain 1

environmental and conservation costs through a surcharge 2

recovery mechanism at the retail level in Florida, 3

utilities are confronting increased environmental 4

pressures that could impose significant uncertainties and 5

costs. In early 2007 S&P cited environmental mandates, 6

including emissions, conservation, and renewable 7

resources, as one of the top ten credit issues facing 8

U.S. utilities.19 Similarly, Moody’s noted that “the 9

prospect for new environmental emission legislation – 10

particularly concerning carbon dioxide – represents the 11

biggest emerging issue for electric utilities.”20 12

13

Compliance with these evolving standards will undoubtedly 14

require significant capital expenditures, especially for 15

utilities like Tampa Electric that depend significantly 16

on coal-fired generation. S&P concluded, “Although we 17

expect the cap-and-trade program to be economy wide and 18

affect a variety of sectors, it will disproportionately 19

affect the power sector.”21 S&P recently emphasized that 20

because of uncertainty over the details and timing of 21

future limits on CO2 emissions, existing ratings do not 22

19 Standard & Poor’s Corporation, “Top Ten Credit Issues Facing U.S. Utilities,” RatingsDirect (Jan. 29, 2007).

20 Moody’s Investors Service, “U.S. Investor-Owned Electric Utilities,” Industry Outlook (Jan. 2009).

21 Standard & Poor’s Corporation, “The Potential Credit Impact Of Carbon Cap-And-Trade Legislation On U.S. Companies,” RatingsDirect (Sep. 14, 2009).


20

fully reflect the impact of carbon risks.22 1

2

Q. Have investors recognized that electric utilities face 3

additional risks because of the impact of industry 4

restructuring on transmission operations? 5

6

A. Yes. Transmission operations have become increasingly 7

complex, and investors have recognized that difficulties 8

in obtaining permits and uncertainty over the adequacy of 9

allowed rates of return have contributed to heightened 10

risk and fueled concerns regarding the adequacy of 11

investment in the transmission sector of the electric 12

power industry. 13

14

At the same time, the development of competitive 15

wholesale power markets has resulted in increased demand 16

for transmission resources. Concerns regarding the need 17

to encourage further investment in the transmission 18

sector were exemplified by the Commission’s observations 19

in Order No. 679:23 20

21

[I]nvestment in transmission facilities in real 22 dollar terms declined significantly between 23 1975 and 1998. Although the amount of 24

22 Id.

23 Promoting Transmission Investment through Pricing Reform, Order No. 679, FERC Stats. & Regs. ¶ 31,222 (“Order No. 679”), order on reh’g, Order No. 679-A, FERC Stats. & Regs.¶ 31,236 (2006), order on reh’g, 119 FERC ¶ 61,062 (2007).


21

investment has increased somewhat in the past 1 few years, data for the most recent year 2 available, 2003, shows investment levels still 3 below the 1975 level in real dollars. This 4 decline in transmission investment in real 5 dollars has occurred while the electric load 6 using the nation’s grid more than doubled. 7 Further, the record shows that the growth rate 8 in transmission mileage since 1999 is not 9 sufficient to meet the expected 50 percent 10 growth in consumer demand for electricity over 11 the next two decades.24 12

13

The challenges posed by an increasingly complex 14

marketplace heighten the uncertainties associated with 15

transmission operations while requiring the commitment of 16

significant new capital investment to maintain and 17

enhance service capabilities. 18

19

Impact of Capital Market Conditions 20

Q. What are the implications of recent capital market 21

conditions? 22

23

A. The deep financial and real estate crisis that the 24

country experienced in late 2008, and continuing into 25

2009 led to unprecedented price fluctuations in the 26

capital markets as investors dramatically revised their 27

risk perceptions and required returns. As a result of 28

investors’ trepidation to commit capital, stock prices 29

24 Order No. 679 at P 10.


22

declined sharply while the yields on corporate bonds 1

experienced a dramatic increase. 2

3

With respect to utilities specifically, as of April 2010, 4

the Dow Jones Utility Average stock index remained almost 5

30 percent below the previous high reached in May 2008. 6

This sell-off in common stocks and sharp fluctuations in 7

utility bond yields reflect the fact that the utility 8

industry was not immune to the impact of financial market 9

turmoil and the ongoing economic downturn. As the Edison 10

Electric Institute (“EEI”) noted in a letter to 11

congressional representatives as the financial crisis 12

intensified, capital market uncertainties have serious 13

implications for utilities and their customers: 14

15

In the wake of the continuing upheaval on Wall 16 Street, capital markets are all but 17 immobilized, and short-term borrowing costs to 18 utilities have already increased substantially. 19 If the financial crisis is not resolved 20 quickly, financial pressures on utilities will 21 intensify sharply, resulting in higher costs to 22 our customers and, ultimately, could compromise 23 service reliability.25 24

25

Similarly, an October 1, 2008 Wall Street Journal report 26

confirmed that utilities had been forced to delay 27

25 Letter to House of Representatives, Thomas R. Kuhn, President, Edison Electric Institute (Sep. 24, 2008).


23

borrowing or pursue more costly alternatives to raise 1

funds.26 In December 2008, Fitch confirmed “sharp 2

repricing of and aversion to risk in the investment 3

community,” and noted that the disruptions in financial 4

markets and the fundamental shift in investors’ risk 5

perceptions had increased the cost of capital for 6

utilities.27 7

8

More recently, in assessing the impact of the downturn on 9

the utility sector, Fitch concluded, “While utilities 10

maintained relatively good market access during the 11

credit crisis, the cost of capital is higher than prior 12

to the credit crisis, and bank credit remains relatively 13

tight.”28 Similarly, S&P noted that while utilities are 14

expected to maintain access to credit in 2010, such 15

access will be “on more demanding terms than in previous 16

years,”29 with Moody’s noting that “costs associated with 17

credit facilities have increased significantly.”30 18

19

Q. How do interest rates on long-term bonds compare with 20

26 Smith, Rebecca, “Corporate News: Utilities’ Plans Hit by Credit Markets,” Wall Street Journal at B4 (Oct. 1, 2008).

27 Fitch Ratings Ltd., “U.S. Utilities, Power and Gas 2009 Outlook,” Global Power North America Special Report (Dec. 22. 2008).

28 Fitch Ratings Ltd., “Electric Utility Capital Spending: The Show Will Go On,” Global Power U.S. and Canada Special Report (Oct. 14, 2009).

29 Standard & Poor’s Corporation, “Ratings Roundup: Ratings Trend In Electric Utility Sector Turns More Negative In First Quarter Of 2010,” RatingsDirect (Apr. 16, 2010).



24

those projected for the next few years? 1

2

A. Table WEA-1 below compares current interest rates on 30-3

year Treasury bonds, double-A rated utility bonds, and 4

triple-A rated corporate bonds with near-term projections 5

from the Value Line Investment Survey (“Value Line”), IHS 6

Global Insight, and the EIA: 7

8

TABLE WEA-1 9

INTEREST RATE TRENDS 10

11

12

13

14

15

16

17

18

19

20

21

22

As evidenced above, there is a clear consensus that the 23

cost of permanent capital will be higher in the 2011-2015 24

timeframe than it is currently. As a result, current 25

2011 2012 2013 2014 2015 Apr. 201030‐Yr. Treasury

Value Line (a) 4.9% 5.3% 5.8% 6.3% ‐‐ 4.7% IHS Global Insight (b) 4.6% 4.9% 5.2% 5.8% 5.8% 4.7%

AAA CorporateValue Line (a) 6.0% 6.4% 6.7% 7.0% ‐‐ 5.3%IHS Global Insight (b) 5.5% 5.9% 6.2% 6.7% 6.7% 5.3%S&P (c) 6.6% 6.6% 6.3% ‐‐ ‐‐ 5.3%

AA UtilityIHS Global Insight (b) 5.8% 6.3% 6.6% 7.2% 7.2% 5.6%EIA (d) 6.4% 6.5% 6.8% 7.2% 7.2% 5.6%

(a)

(b) The Value Line Investment Survey, Forecast for the U.S. Economy (Feb. 26, 2010).(c)

(d)

(e)

Based on monthly average bond yields for April 2010 reported at www.credittrends.moodys.com and http://www.federalreserve.gov/releases/h15/data.htm.

Standard & Poorʹs Corporation, ʺU.S. Economic Forecast: Withdrawal Symptoms,ʺ RatingsDirect (Apr. 9, 2010).Energy Information Administration, Annual Energy Outlook 2010, Early Release (Dec. 5, 2009) at Table 20.

IHS Global Insight, The U.S. Economy: The 30‐Year Focusʺ (Third‐Quarter 2009) at Table 34.


25

cost of capital estimates are likely to understate 1

investors’ requirements at the time the outcome of this 2

proceeding becomes effective and beyond. 3

4

Q. What do these events imply with respect to the ROE for 5

Tampa Electric? 6

7

A. No one knows the future of our complex global economy. 8

We know that the financial crisis had been building for a 9

long time, and few predicted that the economy would fall 10

as rapidly as it has, or that corporate bond yields would 11

fluctuate as dramatically as they did. While conditions 12

in the economy and capital markets appear to have 13

stabilized, investors are apt to react swiftly and 14

negatively to any future signs of trouble in the 15

financial system or economy. As the Wall Street Journal 16

noted in February: 17

18

Stocks pulled out of a 167-point hole with a 19 late rally Friday, capping a wild week 20 reminiscent of the most volatile days of the 21 credit crisis. … It was a return to the unusual 22 relationships, or correlations, seen at major 23 flash points over the past two years when 24 investors fled risky assets and jumped into 25 safe havens. This market behavior, which has 26 reasserted itself repeatedly since the 27 financial crisis began, suggests that 28 investment decisions are still being driven 29 more by government support and liquidity 30


26

concerns than market fundamentals.31 1

2

More recently, the European debt crisis has sparked 3

renewed share price volatility and stress in the credit 4

markets. Given the importance of reliable utility 5

service for customers and the economy, it would be unwise 6

to ignore investors’ increased sensitivity to risk in 7

evaluating a fair ROE for Tampa Electric in this case. 8

9

CAPITAL MARKET ESTIMATES 10

Q. What is the purpose of this section of your testimony? 11

12

A. In this section, I develop DCF estimates of the cost of 13

equity for proxy groups of electric utilities. First, I 14

address the concept of the cost of equity, along with the 15

risk-return tradeoff principle fundamental to capital 16

markets. Next, I describe the specific DCF analyses I 17

conducted to estimate the current cost of equity for the 18

alternative proxy groups. 19

20

Cost of Equity Concept 21

Q. What role does the return on common equity play in a 22

utility’s rates? 23

24

31 Gongloff, Mark, “Stock Rebound Is a Crisis Flashback – Late Surge Recalls Market’s Volatility at Peak of Credit Difficulties; Unusual Correlations,” Wall Street Journal at B1 (Feb. 6, 2010).


27

A. The return on common equity is the cost of inducing and 1

retaining investment in the utility’s physical plant and 2

assets. This investment is necessary to finance the 3

asset base needed to provide utility service. Competition 4

for investor funds is intense and investors are free to 5

invest their funds wherever they choose. They will commit 6

money to a particular investment only if they expect it 7

to produce a return commensurate with those from other 8

investments with comparable risks. 9

10

Q. What fundamental economic principle underlies this cost 11

of equity concept? 12

13

A. The fundamental economic principle underlying the cost of 14

equity concept is the notion that investors are risk 15

averse. In capital markets where relatively risk-free 16

assets are available (e.g., U.S. Treasury securities), 17

investors can be induced to hold riskier assets only if 18

they are offered a premium, or additional return, above 19

the rate of return on a risk-free asset. Since all 20

assets compete with each other for investor funds, 21

riskier assets must yield a higher expected rate of 22

return than safer assets to induce investors to hold 23

them. 24

25


28

Given this risk-return tradeoff, the required rate of 1

return (k) from an asset (i) can generally be expressed 2

as 3

ki = Rf +RPi 4

5

where: Rf = Risk-free rate of return, and 6

RPi = Risk premium required to hold 7

riskier asset i. 8

9

Thus, the required rate of return for a particular asset 10

is a function of: (1) the yield on risk-free assets and 11

(2) the asset’s relative risk, with investors demanding 12

correspondingly larger risk premiums for bearing greater 13

risk. 14

15

Q. Is there evidence that the risk-return tradeoff principle 16

actually operates in the capital markets? 17

18

A. Yes. The risk-return tradeoff can be readily documented 19

in segments of the capital markets where required rates 20

of return can be directly inferred from market data and 21

where generally accepted measures of risk exist. Bond 22

yields, for example, reflect investors’ expected rates of 23

return, and bond ratings measure the risk of individual 24

bond issues. The observed yields on government 25


29

securities, which are considered free of default risk, 1

and bonds of various rating categories demonstrate that 2

the risk-return tradeoff does, in fact, exist in the 3

capital markets. 4

5

Q. Does the risk-return tradeoff observed with fixed income 6

securities extend to common stocks and other assets? 7

8

A. It is generally accepted that the risk-return tradeoff 9

evidenced with long-term debt extends to all assets. 10

Documenting the risk-return tradeoff for assets other 11

than fixed income securities, however, is complicated by 12

two factors. First, there is no standard measure of risk 13

applicable to all assets. Second, for most assets – 14

including common stock – required rates of return cannot 15

be directly observed. Yet there is every reason to 16

believe that investors exhibit risk aversion in deciding 17

whether or not to hold common stocks and other assets, 18

just as when choosing among fixed-income securities. 19

20

Q. Is this risk-return tradeoff limited to differences 21

between firms? 22

23

A. No. The risk-return tradeoff principle applies not only 24

to investments in different firms, but also to different 25


30

securities issued by the same firm. The securities issued 1

by a utility vary considerably in risk because they have 2

different characteristics and priorities. Long-term debt 3

secured by a mortgage on property is senior among all 4

capital in its claim on a utility’s net revenues and is, 5

therefore, the least risky. Following first mortgage 6

bonds are other debt instruments also holding contractual 7

claims on the utility’s net revenues, such as 8

subordinated debentures. The last investors in line with 9

respect to a claim on the utility’s assets are common 10

shareholders. They receive only the net revenues, if any, 11

which remain after all other claimants have been paid. 12

As a result, the rate of return that investors require 13

from a utility’s common stock, the most junior and 14

riskiest of its securities, must be considerably higher 15

than the yield offered by the utility’s senior, long-term 16

debt. 17

18

Q. What does the above discussion imply with respect to 19

estimating the cost of equity? 20

21

A. Although the cost of equity cannot be observed directly, 22

it is a function of the returns available from other 23

investment alternatives and the risks to which the equity 24

capital is exposed. Because it is unobservable, the cost 25


31

of equity for a particular utility must be estimated by 1

analyzing information about capital market conditions 2

generally, assessing the relative risks of the company 3

specifically, and employing various quantitative methods 4

that focus on investors’ required rates of return. These 5

various quantitative methods typically attempt to infer 6

investors’ required rates of return from stock prices, 7

interest rates, or other capital market data. 8

9

Q. What method did you use to evaluate the cost of equity 10

for Tampa Electric? 11

12

A. Consistent with FERC precedent, my analysis applied the 13

Commission’s one-step DCF methodology for electric 14

utilities. In recognition of the fact that no single 15

approach to estimating a utility’s cost of equity can be 16

regarded as definitive, I also developed an alternative 17

DCF benchmark using a proxy group of non-utility 18

companies. In addition, I also evaluated a fair ROE 19

using an earnings approach based on investors’ current 20

expectations in the capital markets. 21

22

Development and Selection of a Proxy Group 23

Q. How did you implement the DCF method to estimate the cost 24

of common equity for Tampa Electric? 25


32

A. Application of the DCF model to estimate the cost of 1

equity requires observable capital market data, such as 2

stock prices. Tampa Electric does not have publicly 3

traded common stock, but even for a publicly traded firm, 4

the cost of equity can only be estimated. As a result, 5

applying quantitative models using observable market data 6

produces only a result that inherently includes some 7

degree of observation error. Thus, the accepted approach 8

to increase confidence in the results is to apply the DCF 9

model to a proxy group of publicly traded companies that 10

investors regard as risk comparable. The results of the 11

analysis on the sample of companies are relied upon to 12

establish a range of reasonableness for the cost of 13

equity for the specific company at issue. 14

15

Q. What specific proxy group did you rely on for your 16

analyses? 17

18

A. Following the same general approach approved by the 19

Commission in Bangor Hydro and Westar,32 my analyses 20

focused on regional utilities located in adjacent 21

reliability organizations. My initial proxy group 22

consisted of the investor-owned members of FRCC and SERC 23

with publicly traded stock. Excluded from my analyses 24

32 Westar Energy, Inc., 122 FERC ¶ 61,268 at P 94 (2008) (“Westar”).


33

was one firm (E.ON AG) for which no data from IBES or 1

Value Line was currently available.33 Finally, I also 2

verified that Value Line, S&P, and IBES classify all of 3

the proxy companies predominantly as electric utilities.34 4

I refer to the resulting group of nine utilities as the 5

“Regional Proxy Group.” 6

7

Q. Has the Commission previously considered membership in a 8

regional reliability or transmission organization when 9

establishing proxy groups? 10

11

A. Yes. The ultimate goal of assembling a proxy group for 12

purposes of performing the DCF analysis is to calculate a 13

return for the utility in question that is analogous to 14

returns on comparable investments with a similar risk 15

profile.35 The Commission has recognized that being 16

located in the same geographical market is a relevant 17

factor in determining whether companies face comparable 18

risks. Consideration of geography as a proxy group 19

criterion first arose where the Commission established a 20

single ROE that was to be implemented across an entire 21

regional organization, as was the case in Midwest ISO.36 22

33 Formerly I/B/E/S International, Inc., IBES growth rates are now compiled and published by Thomson Reuters.

34 See, e.g., Tallgrass Transmission, LLC, 125 FERC ¶ 61,248 at P 77 (2008) (“Tallgrass”).

35 See, e.g., Southern California Edison Co., at 61,266 (2000).

36 Midwest ISO Inc., 100 FERC ¶ 61,292 (2002).


34

Subsequently, in cases involving services provided within 1

the context of well-integrated and coordinated market 2

operations, the Commission has accepted proxy groups 3

composed of members of adjacent regional transmission 4

organizations.37 In other words, in the specific case 5

where participating utilities face comparable risks due 6

to a high degree of similarity in market and regulatory 7

circumstances, geography has been accepted as a valid 8

proxy for risks. 9

10

Similarly, the Commission’s decision in Atlantic Path 15 11

premised its ROE findings on DCF results for the 12

applicant’s proposed proxy group of companies within the 13

footprint of the Western Electricity Coordinating Council 14

(“WECC”).38 The Atlantic Path 15 decision observed that 15

WECC utilities are electrically integrated and that being 16

located in the same geographic market is a relevant 17

factor to consider in determining whether companies face 18

similar risks.39 In Atlantic Path 15, the Commission 19

reasoned that adopting a region-wide proxy group, 20

modified through application of additional risk-based 21

screens, “will provide a significant measure of 22

37 See, e.g., Bangor Hydro; Potomac-Appalachian Transmission Highline, LLC, 122 FERC ¶ 61,188 (2008) (“PATH”); Westar; Virginia Electric Power Co., 123 FERC ¶ 61,098 (2008) (“VEPCO”).

38 Atlantic Path 15, 122 FERC ¶ 61,135 at P 19 (2008) (“Atlantic Path 15”).

39 Id. at PP 25-26.


35

regulatory certainty” and “improve the Commission’s 1

ability to decide cases quickly for entities seeking 2

financing of necessary infrastructure.”40 The decision 3

also suggested that the use of such proxy group might 4

“simplify rate proceedings and reduce litigation costs.”41 5

Thus, while there is no general policy requiring that 6

proxy companies be chosen based on geography, in those 7

instances where there is a clear link between location 8

and key operational characteristics that help to define 9

risks in the minds of investors, membership in a regional 10

reliability or transmission organization can serve as 11

valid criteria in defining proxy companies. 12

13

Q. Does the use of the Regional Proxy Group to establish a 14

reasonable ROE for Tampa Electric follow the Commission’s 15

precedent? 16

17

A. Yes. Consistent with FERC’s guidance, this proxy group 18

is composed of utilities “with a direct correlation” to 19

Tampa Electric and “the broader markets” with which Tampa 20

Electric interacts.42 In fact, geographic location is a 21

primary characteristic that shapes the risks and 22

challenges faced by Tampa Electric and its investors. 23

40 Id. at P 23.

41 Id.

42 Duquesne Light Co., 118 FERC ¶ 61,087 at P 73 (2007).


36

Because of its location on the Florida peninsula, Tampa 1

Electric is exposed to potential fuel supply 2

interruptions and transmission disturbances, and the 3

Company faces the ever-present danger of catastrophic 4

damage from recurring tropical storms. 5

6

Moreover, use of the Regional Proxy Group to determine 7

the ROE range of reasonableness is also consistent with 8

the high degree of integration between the FRCC and SERC 9

members, with three of the four publicly traded FRCC 10

member utilities also being members of SERC. Given the 11

history of regional planning, coordination and system 12

operations among these utilities and within the region, 13

there is a very direct link in the minds of investors 14

between Tampa Electric’s operating environment and that 15

of the other members of the FRCC and SERC. Reference to 16

the Regional Proxy Group also recognizes that these firms 17

compete for investment funds from the same pool of 18

potential capital. Considering these common traits, the 19

companies in the Regional Proxy Group provide a sound 20

basis on which to estimate investors’ required returns 21

and establish the ROE range of reasonableness for Tampa 22

Electric. 23

24

Q. Did your analysis also consider reported risk measures? 25


37

A. Yes. My evaluation also included a comparison of four 1

objective measures of the investment risks associated 2

with bonds and common stocks – S&P’s corporate credit 3

rating and Value Line’s Safety Rank, Financial Strength 4

Rating, and beta. 5

6

Credit ratings are assigned by independent rating 7

agencies to provide investors with a broad assessment of 8

the creditworthiness of a firm. Because the rating 9

agencies’ evaluation includes virtually all of the 10

factors normally considered important in assessing a 11

firm’s relative credit standing, corporate credit ratings 12

provide a broad measure of overall investment risk that 13

is readily available to investors. Widely cited in the 14

investment community and referenced by investors as an 15

objective measure of risk, credit ratings are also 16

frequently used as a primary risk indicator in 17

establishing proxy groups to estimate the cost of equity. 18

19

Apart from the broad assessment of investment risk 20

provided by credit ratings, other quality rankings 21

published by investment advisory services also provide 22

relative assessments of risk that are considered by 23

investors in forming their expectations. Given that Value 24

Line is perhaps the most widely available source of 25


38

investment advisory information, its rankings provide 1

useful guidance regarding the risk perceptions of 2

investors. The Safety Rank is Value Line’s primary risk 3

indicator and ranges from “1” (Safest) to “5” (Most 4

Risky). This overall risk measure is intended to capture 5

the total risk of a stock, and incorporates elements of 6

stock price stability and financial strength. The 7

Financial Strength Rating is designed as a guide to 8

overall financial strength and creditworthiness, with the 9

key inputs including financial leverage, business 10

volatility measures, and company size. Value Line’s 11

Financial Strength Ratings range from “A++” (strongest) 12

down to “C” (weakest) in nine steps. Finally, Value 13

Line’s beta, which measures the volatility of a 14

security's price relative to the market as a whole. A 15

stock that tends to respond less to market movements has 16

a beta less than 1.00, while stocks that tend to move 17

more than the market have betas greater than 1.00. 18

19

Q. What do these criteria indicate with respect to the 20

investment risks of the Regional Proxy Group and Tampa 21

Electric? 22

23

A. The risk measures for the Regional Proxy Group are shown 24

on Exhibit No. TEC-202. The average S&P corporate credit 25


39

rating for the utilities in the Regional Proxy Group is 1

“BBB+”, with four companies having ratings in the single-2

A category. Meanwhile, the average Value Line Safety 3

Rank for the utilities in the Regional Proxy Group is 4

“2”, while the Financial Strength Ratings for the proxy 5

firms averaged “B++”. Finally, the average beta value 6

for the Regional Proxy Group is 0.70. As discussed 7

earlier, Tampa Electric is rated “BBB” by S&P. Value 8

Line has assigned TECO Energy a Safety Rank of “3” and a 9

Financial Strength Rating of “B”, and reports a beta 10

value of 0.85.43 Based on these criteria, which reflect 11

objective, published indicators that incorporate 12

consideration of a broad spectrum of risks, including 13

financial and business position and exposure to company 14

specific factors, investors are likely to regard the 15

risks and prospects of the Utility Proxy Group as being 16

lower than those of Tampa Electric. 17

18

Q. Did you also evaluate DCF results after narrowing the 19

Regional Proxy Group based on credit ratings? 20

21

A. Yes. In developing a regional proxy group, the Commission 22

has also recognized that it may be appropriate to 23

43 Because Tampa Electric has no publicly traded common stock, I referenced the Value Line risk measures for its parent, TECO Energy.


40

eliminate firms based on reference to corporate credit 1

ratings. Consistent with this practice, I also examined 2

the results of the Commission’s DCF model after screening 3

the Regional Proxy Group to eliminate utilities with 4

corporate credit ratings outside a “comparable risk 5

band”, which the Commission has interpreted as one 6

“notch” higher or lower than the corporate ratings of the 7

utility at issue. With TECO Energy being rated “BBB” by 8

S&P, application of this criterion resulted in a proxy 9

group of five electric utilities with corporate credit 10

ratings in the “BBB-” to “BBB+” range, which I refer to 11

as the “Ratings Screen Proxy Group”. These utilities are 12

shown on Exhibit No. TEC-203. 13

14

Q. Do you believe that it is necessary to impose this credit 15

ratings screen in defining a proxy group for Tampa 16

Electric? 17

18

A. No. The ultimate goal of assembling a proxy group for 19

purposes of performing the DCF analysis is to calculate a 20

return for the utility in question that is analogous to 21

returns on comparable investments with a similar risk 22

profile. In cases involving services provided within the 23

context of well-integrated and coordinated market 24

operations, the Commission has recognized that geography 25


41

can serve as a proxy for comparable risk. In other 1

words, in geographic markets where participating 2

utilities face comparable risks due to similar market 3

circumstances, membership in adjacent regional 4

organizations has been accepted as a valid proxy for 5

risks in the context of establishing rates for wholesale 6

utility services. 7

8

I agree that credit ratings are a meaningful measure of 9

investment risks and that the overall risk profile of the 10

Regional Proxy Group should be considered, as I have 11

done; but narrowing a geographically-based proxy group 12

based on additional criteria runs counter to the 13

fundamental notion underlying this approach. Namely, 14

that participation in integrated, adjacent wholesale 15

markets with similar regulatory and operating 16

environments is a valid proxy for risk. The Regional 17

Proxy Group is consistent with the Commission’s 18

determination that members of well-integrated regional 19

markets face similar risks because of common 20

characteristics that are related to geographical 21

location. Moreover, as I demonstrated earlier, the 22

average investment risks attributable to the Regional 23

Proxy Group is generally comparable to those that 24

investors associate with Tampa Electric. Under these 25


42

circumstances, there is no need for additional screening 1

criteria. 2

3

Q. What potential problems are associated with employing 4

credit ratings to further narrow the Regional Proxy 5

Group? 6

7

A. If membership in regional organizations and geographic 8

proximity are accepted as the primary risk factors in 9

determining whether a utility should be included in a 10

proxy group, imposing additional screens can weaken the 11

ability of the proxy group to serve its intended purpose 12

of most closely approximating the risks entailed in 13

providing jurisdictional wholesale utility service. 14

Narrowing the regional proxy groups using additional risk 15

screens, such as corporate credit ratings, increases the 16

potential that the resulting subset will be insufficient 17

to reflect industry conditions and investor expectations 18

and ROE requirements. As noted earlier, the cost of 19

equity is inherently unobservable and because the DCF 20

model depends on estimates it is subject to measurement 21

error, with FERC having acknowledged the pitfalls of a 22

constrained proxy group.44 23

44 Application of the credit rating screen reduces the size of the proxy group, and while the

Commission has on occasion accepted proxy groups as small as four companies, FERC has generally recognized that a constrained proxy group “may not be representative of industry conditions.” See, e.g., Enbridge Pipelines (KPC), 100 FERC ¶ 61,260 at P 237 (2002) (citing Transcontinental Gas Pipe Line Corp., 60 FERC ¶ 63,001, at 65,041, aff'd in part, rev'd in part, 60 FERC ¶ 61,246, at 61,826 (1992), rev'd and remanded, N. C. Util. v. FERC, 42 F.3d 659 (1994), order on reh’g, Transco, 71 FERC ¶ 61,305, at 62,195 (1995)).


43

Even though corporate credit ratings provide a widely 1

accepted, objective benchmark for investment risks, the 2

inherent limitations of the DCF approach mean that the 3

potential to misjudge investors’ required return 4

increases as the size of the proxy group shrinks. In a 5

perfect world, bond ratings and DCF results would always 6

be inversely correlated, with DCF estimates for higher 7

rated companies being lower than for utilities with 8

inferior ratings. But because the true cost of equity is 9

unobservable and our estimating tools (e.g., applications 10

of the DCF model based on observable data) provide 11

imperfect readings, this is not always the case. 12

Consider the Commission’s decision in VEPCO, for example. 13

There, the Commission excluded FPL Group, Inc. (“FPL 14

Group,” now NextEra Energy, Inc.) from the proxy group 15

because its credit rating indicated lower risk than the 16

top threshold of its “BBB” to “A-” range, while the 17

average DCF estimate implied for FPL Group exceeded the 18

10.9 percent ROE determined based on the remaining proxy 19

companies.45 Conversely, while Central Vermont Public 20

Service Corporation was eliminated because its lower bond 21

rating was indicative of greater risk, its implied 22

average DCF estimate of 9.6 percent fell 130 basis points 23

below the 10.9 percent estimate for the proxy group. 24

Because the application of quantitative methods to 25

45 VEPCO at P 63; Supplemental Protest of Central Virginia Electric Cooperative, Craig-Botetourt Electric Cooperative, North Carolina Electric Membership Corporation, and Old Dominion Electric Cooperative, Exhibit INC-1.


44

estimate the cost of equity is inherently imprecise, the 1

potential for anomalous conclusions rises as the proxy 2

group is narrowed. As a result, while imposing an 3

additional risk screen may impart a patina of refinement, 4

it is more likely to increase, rather than ameliorate, 5

the potential for error. 6

7

DCF Model 8

Q. How is the DCF model used to estimate the cost of equity? 9

10

A. DCF models attempt to replicate the market valuation 11

process that sets the price investors are willing to pay 12

for a share of a company’s stock. The model rests on the 13

assumption that investors evaluate the risks and expected 14

rates of return from all securities in the capital 15

markets. Given these expectations, the price of each 16

stock is adjusted by the market until investors are 17

adequately compensated for the risks they bear. 18

Therefore, we can look to the market to determine what 19

investors believe a share of common stock is worth. By 20

estimating the cash flows investors expect to receive 21

from the stock in the way of future dividends and capital 22

gains, we can calculate their required rate of return. 23

Thus, the cash flows that investors expect from a stock 24

are estimated, and given the stock’s current market 25


45

price, we can back into the discount rate, or cost of 1

equity, that investors implicitly used in bidding the 2

stock to that price. 3

4

Q. What market valuation process underlies DCF models? 5

6

A. DCF models assume that the price of a share of common 7

stock is equal to the present value of the expected cash 8

flows (i.e., future dividends and stock price) that will 9

be received while holding the stock, discounted at 10

investors’ required rate of return. Thus, the cost of 11

equity is the discount rate that equates the current 12

price of a share of stock with the present value of all 13

expected cash flows from the stock. 14

15

Q. What form of the DCF model is customarily used to 16

estimate the cost of equity in rate cases? 17

18

A. Rather than developing annual estimates of cash flows 19

into perpetuity, after making certain assumptions, the 20

DCF model can be simplified to a “constant growth” form: 21

22

23

24

25

gkDP

e −= 1

0


46

where: P0 = Current price per share; 1

D1 = Expected dividend per share in the 2 coming year; 3

ke = Cost of equity; 4 g = Investors’ long-term growth 5 expectations. 6

7

The cost of equity (ke) can be isolated by rearranging 8

terms: 9

10

11

12

This constant growth form of the DCF model recognizes 13

that the rate of return to stockholders consists of two 14

parts: 1) dividend yield (D1/P0); and 2) growth (g). In 15

other words, investors expect to receive a portion of 16

their total return in the form of current dividends and 17

the remainder through price appreciation. 18

19

Q. How did you calculate the dividend yield component of the 20

DCF model for the Regional Proxy Group? 21

22

A. Following Commission policy, average low and high 23

indicated dividend yields were calculated for each 24

electric utility during the six months October 2009 25

through March 2010. As indicated on Exhibit No. TEC-204, 26

these six-month average low and high historical dividend 27

gPDke +=

0

1


47

yields were also increased by one-half of the low and 1

high growth rates discussed subsequently (1 + 0.5g) to 2

convert them to adjusted dividend yields. 3

4

Q. What growth rates are used in the Commission's one-step 5

DCF method for electric utilities? 6

7

A. The one-step DCF method for electric utilities adopted by 8

the Commission employs two growth rates for each firm. 9

The first growth rate is a “sustainable” growth rate 10

calculated by the following formula: 11

12

g = br + sv 13

14

where: b = expected retention ratio; 15 r = expected earned rate of return; 16 s = percent of common equity expected to be 17

issued annually as new common stock; 18 v = equity accretion ratio. 19

20

The second growth rate is the IBES consensus five-year 21

earnings growth forecast. These two growth rates are 22

combined with the adjusted dividend yields to develop a 23

cost of equity range for each company. 24

25

Q. How did you calculate the sustainable growth rate? 26

27


48

A. For each electric utility, the expected retention ratio 1

(b) was calculated based on projected dividends and 2

earnings per share from Value Line for 2010, 2011, and 3

their 2013-2015 forecast horizon. Consistent with the 4

Commission’s DCF method, each firm's expected earned rate 5

of return (r) was based on Value Line’s end-of-year 6

forecasts.46 In Southern California Edison, the 7

Commission correctly recognized that if the rate of 8

return, or “r” component of the br+sv growth rate, is 9

based on end-of-year book values, such as those reported 10

by Value Line, it will understate actual returns because 11

of growth in common equity over the year.47 Accordingly, 12

consistent with the Commission’s findings and the theory 13

underlying this approach to estimating investors’ growth 14

expectations, an adjustment was incorporated to compute 15

an average rate of return.48 Finally, the percent of 16

common equity expected to be issued annually as new 17

common stock(s) was equal to the product of the projected 18

market-to-book ratio and growth in common shares 19

outstanding over Value Line’s forecast horizon, while the 20

equity accretion rate (v) was computed as 1 minus the 21

46 Bangor Hydro-Elec. Co., 122 FERC ¶ 61,265 at P 22 (2008).

47 Southern California Edison at 61,263 and n. 38.

48 Use of an average return in developing the sustainable growth rate is well supported. See, e.g., Morin, Roger A., “Regulatory Finance: Utilities’ Cost of Capital,” Public Utilities Reports, Inc. (1994), which discusses the need to adjust Value Line’s end-of-year data, consistent with the Commission’s findings in Southern California Edison. The Commission affirmed the need for this adjustment to “r” in Bangor Hydro Elec. Co., 122 FERC ¶ 61,265 (2008).


49

inverse of the projected market-to-book ratio. The 1

calculation of the sustainable growth rate for each 2

electric utility in the Regional Proxy Group is shown on 3

Exhibit No. TEC-205. 4

5

Q. What are investment analysts' projected growth rates for 6

the companies in the Regional Proxy Group? 7

8

A. The five-year IBES earnings growth forecasts for each 9

electric utility in the proxy group are shown in column 10

(d) on Exhibit No. TEC-204. 11

12

Q. What were the results of applying the Commission’s one-13

step DCF approach to the Regional Proxy Group? 14

15

A. As shown on Exhibit No. TEC-204, application of the 16

Commission’s DCF model to the Regional Proxy Group 17

resulted in current cost of equity estimates ranging from 18

7.9 percent to 13.6 percent. 19

20

Evaluation of DCF Results 21

Q. In evaluating the results of the constant growth DCF 22

model, is it appropriate to eliminate cost of equity 23

estimates that are extreme outliers? 24

25


50

A. Yes. In applying quantitative methods to estimate the 1

cost of equity, it is essential that the resulting values 2

pass fundamental tests of reasonableness and economic 3

logic. Accordingly, DCF estimates that are implausibly 4

low or high should be eliminated when evaluating the 5

results of this method. 6

7

Q. How did you evaluate DCF estimates at the low end of the 8

range? 9

10

A. It is a basic economic principle that investors can be 11

induced to hold more risky assets only if they expect to 12

earn a return to compensate them for their risk bearing. 13

As a result, the rate of return that investors require 14

from a utility’s common stock, the most junior and 15

riskiest of its securities, must be considerably higher 16

than the yield offered by senior, long-term debt. 17

Consistent with this principle, the DCF range must be 18

adjusted to eliminate cost of equity estimates that are 19

determined to be extreme low outliers when compared 20

against the yields available to investors from less risky 21

utility bonds. 22

23

Q. Has the Commission recognized that it is appropriate to 24

eliminate cost of equity estimates that fail to meet 25


51

threshold tests of economic logic? 1

2

A. Yes. In Southern California Edison, the Commission noted 3

that adjustments to the zone of reasonableness are 4

justified where applications of its preferred DCF 5

approach produce illogical results: 6

7

An adjustment to this data is appropriate in 8 the case of PG&E's low-end return of 8.42 9 percent, which is comparable to the average 10 Moody's "A" grade public utility bond yield of 11 8.06 percent, for October 1999. Because 12 investors cannot be expected to purchase stock 13 if debt, which has less risk than stock, yields 14 essentially the same return, this low-end 15 return cannot be considered reliable in this 16 case.49 17

18

Similarly, in its October 2006 decision in Kern River Gas 19

Transmission Company, the Commission noted that: 20

21 [T]he 7.31 and 7.32 percent costs of equity for 22 El Paso and Williams found by the ALJ are only 23 110 and 122 basis points above that average 24 yield for public utility debt.50 25

26

The Commission upheld the opinion of Staff and the 27

Administrative Law Judge that cost of equity estimates 28

for these two proxy group companies “were too low to be 29

credible.”51 30

49 Southern California Edison at 61,266 (note omitted).

50 Kern River Gas Transmission Company, 117 FERC ¶ 61,077 at P 140 and n. 227 (2006).

51 Id.


52

The practice of eliminating low-end outliers was affirmed 1

in PATH and VEPCO,52 and in its February 2008 decision in 2

Atlantic Path 15, the Commission disregarded a low-end 3

cost of equity estimate of 7.29 percent.53 In its 4

April 15, 2010 decision in SoCal Edison, FERC affirmed 5

that, “it is reasonable to exclude any company whose low-6

end ROE fails to exceed the average bond yield by about 7

100 basis points or more.”54 8

9

Q. What is the appropriate bond yield benchmark to evaluate 10

low-end DCF results? 11

12

A. The average S&P corporate credit rating for the firms in 13

the Regional Proxy Group is “BBB+”, with Tampa Electric 14

being rated “BBB”. Companies rated “BBB-”, “BBB”, and 15

“BBB+” are all considered part of the triple-B rating 16

category, with Moody’s monthly yields on triple-B utility 17

bonds averaging approximately 6.2 percent over the six-18

month period ending March 2010.55 19

20

Q. What else should be considered in evaluating DCF 21

estimates at the low end of the range? 22

52 PATH at P 98; VEPCO at P 64.

53 Atlantic Path 15, at P 20; Prepared Direct Testimony of James M. Coyne, Atlantic Path 15, Docket No. ER08-374 at Exhibit No. ATL-7.

54 Southern California Edison Co., 131 FERC ¶ 61,020 at P 55 (2010) (“SoCal Edison”).

55 Moody’s Investors Service, www.credittrends.com.


53

2011 2011-15Projected AA Utility Yield

IHS Global Insight (a) 5.84% 6.62%EIA (b) 6.43% 6.82%

Average 6.14% 6.72%

BBB - AA Yield Spread (c) 0.71% 0.71%

Implied BBB Utility Yield 6.85% 7.43%

(a)

(b)

(c)

Energy Information Administration, Annual Energy Outlook 2010 , Early Release (Dec. 5, 2009) at Table 20.

Based on monthly average bond yields for the six-month October 2009 - March 2010.

IHS Global Insight, The U.S. Economy: The 30-Year Focus (Third-Quarter 2009) at Table 34.

A. As indicated earlier, while corporate bond yields have 1

declined substantially as the worst of the financial 2

crisis has abated, it is generally expected that long-3

term interest rates will rise as the recession ends and 4

the economy returns to a more normal pattern of growth. 5

As shown in Table WEA-2 below, the most recent forecasts 6

of IHS Global Insight and the EIA imply an average 7

triple-B bond yield of 6.85 percent for 2011, or 7.43 8

percent over the five-year period 2011-2015: 9

10

TABLE WEA-2 11

IMPLIED BBB BOND YIELD 12

13

14

15

16

17

18

19

20

21

22

23

The increase in debt yields anticipated by IHS Global 24

Insight and EIA is also supported by the widely-25


54

referenced Blue Chip Financial Forecasts, which projects 1

that yields on corporate bonds will climb on the order of 2

70 basis points through the second quarter of 2011.56 3

Consistent with these forecasts, Fitch concluded, 4

“Interest rates are expected to rise over the course of 5

the year from very low levels.”57 6

7

Q. What does this test of logic imply with respect to the 8

DCF results for the Regional Proxy Group? 9

10

A. As shown on Exhibit No. TEC-204, the low-end DCF estimate 11

for Duke Energy Corporation (“Duke Energy”) was 7.9 12

percent. This value is barely 100 basis points above the 13

yield on triple-B utility bonds expected during 2010. In 14

light of the risk-return tradeoff principle and the tests 15

applied by the Commission in prior decisions, it is 16

inconceivable that investors are not requiring a 17

substantially higher rate of return for holding common 18

stock, which is the riskiest of a utility’s securities. 19

As a result, consistent with the test of economic logic 20

applied by FERC and the upward trend expected for utility 21

bond yields, this value provides little guidance as to 22

the returns investors require from utility common stocks 23

56 Blue Chip Financial Forecasts, Vol. 29, No. 2 (Feb. 1, 2010).



55

and should be excluded. 1

2

Q. Is there any basis to exclude cost of equity estimates at 3

the high end of the range of reasonableness? 4

5

A. The FERC’s DCF approach does allow for high-end DCF 6

estimates to be excluded if they are found to be extreme 7

outliers, but none of the values for the Regional Proxy 8

Group are affected by this test. Specifically, in a 9

November 2004 Order in Bangor Hydro, the Commission 10

determined that a cost of equity estimate at the high end 11

of the range of reasonableness might also be excluded if 12

it is determined to be an extreme outlier.58 The 13

Commission found that a 17.7 percent cost of equity 14

estimate for PPL was “extreme” and that including this 15

result would “skew the results.”59 The Commission also 16

expressed concern regarding the sustainability of the 17

underlying 13.3 percent growth estimate for PPL,60 and has 18

also referenced this threshold as a test of 19

reasonableness.61 20

21

As noted earlier, the upper end of the cost of equity 22

58 ISO New England, Inc., et al., 109 FERC ¶ 61,147 at P 205 (2004) (“RTO Rehearing Order”).

59 Id.

60 Id.

61 See, e.g., SoCal Edison at P 57.


56

range produced by the DCF analysis presented in Exhibit 1

No. TEC-204 was based on a cost of equity estimate of 2

13.6 percent. This high-end estimate falls far below the 3

17.7 percent threshold established in Bangor Hydro. 4

Similarly, the 7.9 percent growth rate underlying this 5

cost of equity estimate is also significantly less than 6

the 13.3 percent benchmark that has been used by the 7

Commission to evaluate values at the high end of the DCF 8

range.62 Moreover, the 13.6 percent upper end of my DCF 9

range is not an “extreme outlier” when compared with the 10

ROE ranges approved by the Commission in the past.63 11

Accordingly, this high-end cost of equity estimate is 12

properly included under the rationale adopted by the 13

Commission. 14

15

Q. What ROE range does your DCF results imply for the 16

Regional Proxy Group? 17

18

A. Eliminating the illogical low-end outlier shaded on 19

Exhibit No. TEC-204 resulted in an adjusted range of 20

reasonableness for the Regional Proxy Group ranging from 21

8.2 percent to 13.6 percent. The midpoint of this range 22

is 10.9 percent. As discussed subsequently, I do not 23

62 See, e.g., PATH at P 100.

63 For example, the upper-end of the DCF range approved by the Commission for Tallgrass Transmission, LLC and Prairie Wind Transmission, LLC was 16.9 percent. Tallgrass at P 78.


57

support or recommend reliance on the median to evaluate 1

the ROE for Tampa Electric. Nevertheless, as indicated 2

on Exhibit No. TEC-204, if the median is based on the 3

average of the high and low estimates for those proxy 4

group firms with no extreme outliers, the result is 10.7 5

percent.64 6

7

Q. What were the DCF results for the Ratings Screen Proxy 8

Group? 9

10

A. As discussed earlier, there are compelling reasons 11

supporting the use of the Regional Proxy Group to 12

estimate the cost of equity for Tampa Electric. 13

Nevertheless, Exhibit No. TEC-206 presents the results of 14

the Commission’s model for the Ratings Screen Proxy 15

Group. As indicated there, this analysis resulted in the 16

same 8.2 percent to 13.6 percent ROE zone of 17

reasonableness produced for the Regional Proxy Group, 18

with the midpoint again being 10.9 percent. Using the 19

methodology employed in VEPCO, the median would be 10.5 20

percent. 21

22

Q. Do the DCF results for the Ratings Screen Proxy Group 23

64 See, e.g., VEPCO at n. 58. The Commission determines the median after averaging the low and high DCF results for each of the firms in the proxy group with two valid estimates.


58

make economic sense? 1

2

A. No. Earlier, I explained that further restricting the 3

Regional Proxy Group based on credit ratings can lead to 4

greater potential for error as the number of companies is 5

narrowed. In developing the Ratings Screen Proxy Group, 6

I eliminated all companies from the Regional Proxy Group 7

with single-A credit ratings. As a result, the 8

investment risks of the Ratings Screen Proxy Group are 9

higher than those of the Regional Proxy Group. Given the 10

fundamental principle that investors are risk averse, 11

this implies that the cost of equity for the Ratings 12

Screen Proxy Group should be higher than for the firms in 13

the Regional Proxy Group. 14

15

The DCF results presented on Exhibits TEC-204 and TEC-206 16

do not follow this logical result. As shown there, 17

despite the fact that the investment risks of the Ratings 18

Screen Proxy Group are higher, the midpoint of the DCF 19

range of reasonableness is identical to that of the 20

Regional Proxy Group, with the median DCF value being 21

lower. Considering that investors require a higher 22

return to assume greater risk, this lower median cost of 23

equity for the Ratings Screen Proxy Group does not make 24

economic sense. 25


59

The greater breadth of the Regional Proxy Group helps to 1

ensure that the resulting DCF range reflects the risks 2

and requirements of investors. As a result, the zone of 3

reasonableness for this group of comparable-risk electric 4

utilities provides a reasonable basis to establish the 5

allowed ROE for Tampa Electric. 6

7

Evaluating an ROE Point Estimate 8

Q. What is the Commission’s policy in determining a point 9

estimate from within the ROE zone of reasonableness? 10

11

A. Historically, the Commission was consistent in using the 12

midpoint of the zone of reasonableness as the basis for 13

allowed ROEs for electric utilities, as evidenced by 14

Bangor Hydro, Midwest ISO, Southern California Edison, 15

and in a plethora of other previous electric cases. For 16

example, in Consumers Energy, the Commission reversed an 17

initial decision in which the Presiding Judge had relied 18

on the median of the zone of reasonableness, rather than 19

the midpoint. The Commission concluded that: 20

21

The precedent on which the judge and Staff rely 22 in this instance was developed in the context 23 of setting the rate of return for gas 24 pipelines. In this case, there has been no 25 reason provided to depart from our precedent in 26 Opinion Nos. 445 and 446, setting the return at 27


60

the midpoint of the zone of reasonableness.65 1

2

The Commission followed the same approach in Consumers 3

Energy Co.66 and Utah Power & Light Co.,67 finding the 4

midpoint to be the appropriate return for an electric 5

utility. In certain decisions, however, the Commission 6

has relied on the median rather than the midpoint.68 Most 7

recently, FERC concluded, “in this SoCal Edison 8

proceeding, for a single utility of average risk, the 9

best measure of central tendency is the median.”69 10

11

Q. What rationale did the Commission advance to support 12

adopting the median? 13

14

A. The Commission determined that the median 1) “takes into 15

account more of the companies in the proxy group”, and 2) 16

“minimizes the impact of a potentially skewed proxy 17

group.”70 18

19

Q. Do you agree that the median is a superior measure of 20

central tendency when evaluating the ROE for a stand-21

65 Consumers Energy Co., 98 FERC ¶ 61,333, at 62,416 (2002).

66 85 FERC ¶ 61,100 (1998).

67 44 FERC ¶ 61,166 (1988).

68 See, e.g., VEPCO, 123 FERC ¶ 61,098 (2008); Golden Spread Elec. Cooperative, Inc., et al., 123 FERC ¶ 61,047 (2008) (“Golden Spread”).

69 SoCal Edison at P 92.

70 Id. at P 87.


61

alone utility? 1

2

A. No. I disagree with both of the findings underlying the 3

Commission’s decision to rely on the median DCF estimate 4

when establishing the ROE for a single utility. 5

6

Q. Does the median “take into account more of the companies 7

in the proxy group” than does the midpoint? 8

9

A. No. The median actually considers less information about 10

the distribution of reasonable DCF results for the proxy 11

group than does the midpoint. The median is simply the 12

observation with an equal number of data values above and 13

below. For odd-numbered samples, the median relies on 14

only a single number, e.g., the sixth number in an 15

eleven-number set. If the number of estimates is an even 16

number, then the median is the arithmetic average of the 17

two numbers falling in the middle. Thus, if there were 18

twelve estimates, then the median would in fact be the 19

average of the sixth and seventh estimates arrayed from 20

highest to lowest. As such, the median doesn’t expressly 21

“take into account” any information regarding the 22

individual DCF estimates for the proxy companies that are 23

above or below the single number (or average of two 24

single numbers) that fall in the middle of the 25


62

distribution. 1

2

While arguments against the midpoint frequently hinge on 3

the contention that this value relies on only the top and 4

bottom numbers in the range and ignores the rest, this 5

argument is incorrect. As the D.C. Circuit has held, 6

“[t]he midpoint doesn’t ‘completely disregard the middle 7

three numbers’; the highest and lowest numbers achieve 8

their status by reference to all five numbers.”71 Consider 9

this example of a five-estimate sample to illustrate the 10

point made by the D.C. Circuit. The estimates are 8.0, 11

8.1, 8.2, 15.0, and 15.1 percent. The median is 8.2 12

percent, while the range is 8.0 percent to 15.1 percent, 13

with a midpoint of 11.55 percent. The median of 8.2 14

percent does not reflect the range of values nor does it 15

include information about the 15.0 and 15.1 percent 16

values that define the upper end of the range. 17

18

In fact, the median could be more readily criticized for 19

under-weighting the results of the proxy group analysis, 20

since it ignores the range of reasonable returns 21

entirely. As the D.C. Circuit observed in approving the 22

use of the midpoint for setting the ROE for the Midwest 23

ISO: 24

71

Canadian Association of Petroleum Producers v. FERC, 254 F.3d 289, 298 (D.C. Cir. 2001).


63

[P]etitioners [arguing in support of the 1 median] are correct in noting that all measures 2 of central tendency ‘consider’ the entire proxy 3 group range, in the sense that all are 4 influenced – at least indirectly – by each data 5 point in the range. But only the midpoint 6 emphasizes that range, as it is equally placed 7 between the top and bottom values.72 8

9

The purpose of the Commission’s DCF analysis is to 10

produce a zone of reasonableness, and the midpoint 11

provides a better representation of a single ROE 12

applicable to this range than does the median, which 13

ignores the boundaries of the range entirely. 14

15

Q. Do concerns over skewed DCF results favor the median over 16

the midpoint? 17

18

A. No. Calculation of the median does not involve any 19

examination of the reasonableness of individual cost of 20

equity estimates; rather, it is simply a single number 21

that divides a set of observed values in two equal 22

halves, so that half of the values are below it, and half 23

are above. Moreover, the Commission’s DCF approach 24

already establishes a framework to address concerns over 25

skewed results by evaluating and excluding individual 26

cost of equity estimates that are extreme outliers. In 27

72 Public Service Commission of the Commonwealth of Kentucky, v. FERC, 397 F.3d 1004, 1010 (D.C. Cir. 2005).


64

others words, eliminating illogical low and high-end DCF 1

estimates when evaluating the results of the Commission’s 2

DCF approach also negates this second rationale advanced 3

for reliance on the median. 4

5

Q. Does it make sense to distinguish between filings 6

involving individual companies and those involving groups 7

of regional utilities when evaluating central tendency? 8

9

A. No. As noted above, the outcome of the Commission’s DCF 10

approach is a zone of reasonableness that reflects 11

investors’ required rate of return for a proxy group that 12

is comparable in risk to the applicant, irrespective of 13

whether the filing concerns a stand-alone utility or 14

multiple members of a regional organization. In each 15

case the object of the analysis is to obtain a reasonable 16

and reliable range of the unobservable cost of equity 17

based on objective estimates that contain unknown errors. 18

Given the importance of the zone of reasonableness in 19

framing the ROE under the Commission’s precedent for 20

electric utilities, the midpoint is more relevant in 21

establishing a central point estimate that expressly 22

considers this range. 23

24

Moreover, establishing different measures of central 25


65

tendency based on whether the party is a single utility 1

or a joint filing made up of multiple companies within a 2

region creates the potential that different ROEs could be 3

established for the same utility, solely depending on the 4

nature of the filing. Such a perverse economic outcome 5

has no logical relationship to changes in underlying 6

capital market conditions or investors’ risk perceptions 7

or requirements, and it directly contradicts the 8

Commission’s well-articulated policy goals of reducing 9

regulatory impediments to investment in utility 10

infrastructure and encouraging new capital investment. 11

12

Q. How else might the Commission approach the determination 13

of a single point estimate from within the ROE range? 14

15

A. The paramount consideration that must be reflected in the 16

choice of a point estimate is the need to ensure that the 17

end result meets the standards mandated by the Supreme 18

Court to ensure that a utility can attract capital. This 19

determination is not a quest to ordain a single 20

statistical measure of central tendency. Rather, it 21

challenges the Commission to consider the available 22

evidence and identify an ROE that is just, reasonable, 23

and sufficient to support the Commission’s goal of 24

encouraging investment in wholesale utility 25


66

infrastructure. 1

2

While I believe the midpoint provides a better 3

representation of a single ROE applicable to the DCF zone 4

of reasonableness, the Commission and other stakeholders 5

might be better served by abandoning a policy of 6

mechanistically determining the point estimate on a 7

single statistic. Both the midpoint and the median are 8

recognized statistical measures of central tendency and 9

the Commission is free to weigh both values in its 10

assessment of a fair ROE. Such a policy would be 11

consistent with statistical principles, which favor 12

retaining and evaluating all useful information in order 13

to obtain the most reliable conclusion. Moreover, 14

consideration of both the midpoint and the median 15

recognizes the inherent imprecision in estimating the 16

cost of equity and the important role of informed 17

judgment in evaluating the results of any quantitative 18

analysis. 19

20

Q. Would the Commission increase regulatory risk by electing 21

to consider more than one statistical indicator when 22

determining a fair ROE? 23

24

A. No. While the degree of regulatory support is clearly 25


67

one of the most significant considerations for investors, 1

they are far more concerned with the end-result and the 2

implications for the utility’s finances than with 3

adherence to specific rules or precedent, no matter what 4

the outcome. As S&P noted: 5

6

As much as possible, regulators should, in our 7 opinion, have the flexibility to react quickly 8 and prudently to new situations as they 9 develop. This is the sort of flexibility that 10 we believe comes under principles-based 11 regulation rather than rules-based regulation. 12 In the latter, a regulator may attempt to set 13 down every possible rule that can apply to a 14 given situation that may arise in an industry. 15 In the former, the regulator generally has the 16 authority to achieve certain ends and some 17 flexibility in how to achieve them.73 18

19

Similarly, a mechanical policy of referencing only the 20

median of the DCF estimates leaves the Commission with 21

little flexibility when the result fails to reflect a 22

fair and reasonable ROE. In this instance, any benefit 23

of consistency is more than overwhelmed by the risks that 24

an unresponsive, mechanical policy will lead to 25

inadequate returns. 26

27

Flotation Costs 28

Q. What other considerations are relevant in evaluating the 29

73 Standard & Poor’s Corporation, “Executive Comment: What Characterizes Effective Regulation? Understanding, Manageability, and Consistency,” RatingsDirect (May 5, 2010).


68

ROE for a utility? 1

2

A. The common equity used to finance the investment in 3

utility assets is provided from either the sale of stock 4

in the capital markets or from retained earnings not paid 5

out as dividends. When equity is raised through the sale 6

of common stock, there are costs associated with 7

"floating" the new equity securities. These flotation 8

costs include services such as legal, accounting, and 9

printing, as well as the fees and discounts paid to 10

compensate brokers for selling the stock to the public. 11

Also, some argue that the "market pressure" from the 12

additional supply of common stock and other market 13

factors may further reduce the amount of funds a utility 14

nets when it issues common equity. 15

16

Equity flotation costs are not included in a utility’s 17

rate base because neither that portion of the gross 18

proceeds from the sale of common stock used to pay 19

flotation costs is available to invest in plant and 20

equipment, nor are flotation costs capitalized as an 21

intangible asset. Unless some provision is made to 22

recognize these issuance costs, a utility’s revenue 23

requirements will not fully reflect all of the costs 24

incurred for the use of investors’ funds, with the need 25


69

for a flotation cost adjustment having been documented in 1

the financial literature.74 2

3

Q. What is the magnitude of the adjustment to the “bare 4

bones” cost of common equity to account for issuance 5

costs? 6

7

A. While there are a number of ways in which a flotation 8

cost adjustment can be calculated, one of the most common 9

methods used to account for flotation costs in regulatory 10

proceedings is to apply an average flotation-cost 11

percentage to a utility’s dividend yield. A review of the 12

finance literature and other studies of issuance costs 13

prepared by the investment community suggest an average 14

flotation cost percentage in the range of 3.6 percent to 15

10 percent.75 Applying these expense percentages to a 16

representative dividend yield for a utility of 5.0 17

percent implies a flotation cost adjustment on the order 18

of 18 to 50 basis points. While my DCF zone of 19

reasonableness recommendation does not include an 20

adjustment for flotation costs, this is a legitimate 21

74 See, e.g., Brigham, E.F., Aberwald, D.A., and Gapenski, L.C., “Common Equity Flotation Costs and Rate Making,” Public Utilities Fortnightly (May, 2, 1985); Morin, Roger A., “Regulatory Finance: Utilities’ Cost of Capital,” Public Utilities Reports at 175 (1994).

75 See, e.g., Morin, Roger A., “Regulatory Finance: Utilities’ Cost of Capital,” Public Utilities Reports (1994) at 166; Application of Yankee Gas Services Company for a Rate Increase, DPUC Docket No. 04-06-01, Direct Testimony of George J. Eckenroth (Jul. 2, 2004) at Exhibit GJE-11.1.


70

factor that supports the reasonableness of the ROE 1

requested by Tampa Electric in this case. 2

3

ROE BENCHMARKS 4

Q. What other analyses did you conduct to estimate the cost 5

of equity? 6

7

A. I also evaluated the cost of equity for Tampa Electric 8

against ROE benchmarks developed by applying the DCF 9

model to a group of non-utility companies and by 10

reference to expected earned rates of return for 11

utilities. 12

13

Q. What evidence supports your reference to alternative ROE 14

benchmarks? 15

16

A. I am well aware that the Commission has narrowed the 17

focus of its ROE evaluation to a particular variant of 18

the DCF approach. Nevertheless, because the cost of 19

equity is unobservable, no single method should be viewed 20

in isolation. Regulators have customarily considered the 21

results of alternative approaches in determining allowed 22

returns.76 It is widely recognized that no single method 23

76 For example, a NARUC survey reported that 26 regulatory jurisdictions ascribe to no specific method for setting allowed ROEs, with the results of all approaches being considered. “Utility Regulatory Policy in the U.S. and Canada, 1995-1996,” National Association of Regulatory Utility Commissioners (December 1996).


71

can be regarded as a panacea; with all approaches having 1

advantages and shortcomings. For example, a publication 2

of the Society of Utility and Financial Analysts 3

(formerly the National Society of Rate of Return 4

Analysts), concluded that: 5

6

Each model requires the exercise of judgment as 7 to the reasonableness of the underlying 8 assumptions of the methodology and on the 9 reasonableness of the proxies used to validate 10 the theory. Each model has its own way of 11 examining investor behavior, its own premises, 12 and its own set of simplifications of reality. 13 Each method proceeds from different fundamental 14 premises, most of which cannot be validated 15 empirically. Investors clearly do not 16 subscribe to any singular method, nor does the 17 stock price reflect the application of any one 18 single method by investors.77 19

20

As the Federal Communications Commission recognized: 21

22

Equity prices are established in highly 23 volatile and uncertain capital markets... 24 Different forecasting methodologies compete 25 with each other for eminence, only to be 26 superseded by other methodologies as conditions 27 change... In these circumstances, we should not 28 restrict ourselves to one methodology, or even 29 a series of methodologies, that would be 30 applied mechanically. Instead, we conclude 31 that we should adopt a more accommodating and 32 flexible position.78 33

34

77 Parcell, David C., “The Cost of Capital – A Practitioner’s Guide,” Society of Utility and Regulatory Financial Analysts (1997) at Part 2, p. 4.

78 Federal Communications Commission, Report and Order 42-43, CC Docket No. 92-133 (1995).


72

Q. Has the Commission also recognized that it may be 1

appropriate to consider the results of alternative 2

methods? 3

4

A. Yes. For example, the Commission concluded in Distrigas 5

of Massachusetts Corp. that, “no one methodology is 6

preferred to the exclusion of all others. The DCF 7

methodology, which we endorse, is but one analytical 8

tool.”79 FERC has also granted that “[i]n some instances, 9

the DCF methodology alone may be inappropriate.”80 While 10

electing not to make “broadly applicable changes to how 11

the Commission has traditionally performed its DCF 12

analysis,” Order No. 679 noted the opinion that “there is 13

a benefit to introducing more information into the 14

analysis process,” and FERC indicated a willingness to 15

consider modification to its standard approach on a case-16

by-case basis.81 More recently, in SoCal Edison, the 17

Commission recognized that additional methods could be 18

used to test or corroborate the results of its preferred 19

DCF approach.82 20

21

79 Distrigas of Massachusetts Corp., 41 FERC ¶ 61,205 at 61,550 (1987), modified on reh’g, 42 FERC ¶ 61,225 (1988).

80 Williston Basin Interstate Pipeline Co., 50 FERC ¶ 61,284 at 61,913 n.90 (1990), vacated on other grounds, 931 F.2d 949 (D.C. Cir. 1991).

81 Order No. 679, 116 FERC ¶ 61,057 at P 102 (2006); Order No. 679-A, 117 FERC ¶ 61,327 at P 63 (2006).

82 SoCal Edison at P 116.


73

Non-Utility DCF Model 1

Q. What other proxy group did you consider in evaluating a 2

fair ROE for Tampa Electric? 3

4

A. Consistent with underlying economic and regulatory 5

standards, I also applied the DCF model to a reference 6

group of comparable risk companies in the non-utility 7

sectors of the economy. I refer to this group as the 8

“Non-Utility Proxy Group”. 9

10

Q. Do utilities have to compete with non-regulated firms for 11

capital? 12

13

A. Yes. The cost of capital is an opportunity cost based on 14

the returns that investors could realize by putting their 15

money in other alternatives. Clearly the total capital 16

invested in utility stocks is only the tip of the iceberg 17

of total common stock investment, and there are a 18

plethora of other enterprises available to investors 19

beyond those in the utility industry. Utilities must 20

compete for capital, not just against firms in their own 21

industry, but with other investment opportunities of 22

comparable risk. With regulation taking the place of 23

competitive market forces, required returns for utilities 24

should be in line with those of non-utility firms of 25


74

comparable risk operating under the constraints of free 1

competition. 2

3

Q. Is it consistent with the Bluefield and Hope cases to 4

consider required returns for non-utility companies? 5

6

A. Yes. Returns in the competitive sector of the economy 7

form the very underpinning for utility ROEs because 8

regulation purports to serve as a substitute for the 9

actions of competitive markets. The Supreme Court has 10

recognized that it is the degree of risk, not the nature 11

of the business, which is relevant in evaluating an 12

allowed ROE for a utility. The Bluefield case refers to 13

“business undertakings attended with comparable risks and 14

uncertainties.” It does not restrict consideration to 15

other utilities. Indeed, if the requirement is business 16

in the same part of the country and the utility has the 17

exclusive franchise, then the Court could only be 18

referring to non-utility businesses and any nearby 19

utilities. Similarly, the Hope case states: 20

21

By that standard the return to the equity owner 22 should be commensurate with returns on 23 investments in other enterprises having 24 corresponding risks. 25

26

As in the Bluefield decision, there is nothing to 27


75

restrict “other enterprises” solely to the utility 1

industry. 2

3

Indeed, in teaching regulatory policy I usually observe 4

that in the early applications of the comparable earnings 5

approach, utilities were explicitly eliminated due to a 6

concern about circularity. In other words, soon after 7

the Hope decision regulatory commissions did not want to 8

get involved in circular logic by looking to the returns 9

of utilities that were established by the same or similar 10

regulatory commissions in the same geographic region. To 11

avoid circularity, regulators looked only to the returns 12

of non-utility companies. 13

14

Q. Does consideration of the results for the Non-Utility 15

Proxy Group make the estimation of the cost of equity 16

using the DCF model more reliable? 17

18

A. Yes. The estimates of growth from the DCF model depend 19

on analysts’ forecasts. It is possible for utility 20

growth rates to be distorted by short-term trends in the 21

industry or the industry falling into favor or disfavor 22

by analysts. The result of such distortions would be to 23

bias the DCF estimates for utilities. For example, Value 24

Line recently observed that near-term growth rates 25


76

understate the longer-term expectations for gas 1

utilities: 2

3

Natural Gas Utility stocks have fallen near the 4 bottom of our Industry spectrum for Timeliness. 5 Accordingly, short-term investors would 6 probably do best to find a group with better 7 prospects over the coming six to 12 months. 8 Longer-term, we expect these businesses to 9 rebound. An improved economic environment, 10 coupled with stronger pricing, should boost 11 results across this sector over the coming 12 years.83 13

14

Because the Non-Utility Proxy Group includes low risk 15

companies from many industries, it diversifies away any 16

distortion that may be caused by the ebb and flow of 17

enthusiasm for a particular sector. 18

19

Q. What criteria did you apply to develop the Non-Utility 20

Proxy Group? 21

22

A. My comparable risk proxy group was composed of those U.S. 23

companies followed by Value Line that: 1) pay common 24

dividends; 2) have a Safety Rank of “1”; 3) have a 25

Financial Strength Rating of “B++” or greater; 4) have a 26

beta less than 1.00; and, 5) have investment grade credit 27

ratings from S&P. While any differences in investment 28

83 The Value Line Investment Survey at 445 (Mar. 12, 2010).


77

S&P Value Line Credit

Rating Safety

Rank Financial Strength

Beta

Non-Utility Proxy Group A 1 A+ 0.75

Regional Proxy Group BBB+ 2 B++ 0.70

Ratings Screen Proxy Group BBB 2 B++ 0.73

Tampa Electric BBB 3 B 0.85

risk attributable to regulation should already be 1

reflected in these objective measures, my analyses 2

nevertheless conservatively focus on a lower-risk group 3

of non-utility firms. 4

5

Q. How do the overall risks of this Non-Utility Proxy Group 6

compare with Tampa Electric? 7

8

A. Table WEA-3 compares the Non-Utility Proxy Group with the 9

Regional Proxy Group, the Ratings Screen Proxy Group, and 10

Tampa Electric across four key indicators of investment 11

risk. Because Tampa Electric has no publicly traded 12

common stock, the Value Line risk measures shown reflect 13

those published for its parent, TECO Energy: 14

15

TABLE WEA-3 16

COMPARISON OF RISK INDICATORS 17

18

19

20

21

22

23

24

As shown above, the average credit ratings, Safety Rank, 25


78

and Financial Strength Rating for the Non-Utility Proxy 1

Group suggest less risk than for the proxy groups of 2

utilities, with its 0.75 average beta indicating somewhat 3

greater risk. Thus, while the impact of differences in 4

regulation is already reflected in objective risk 5

measures, my analyses conservatively focus on a lower-6

risk group of non-utility firms. Considered together, a 7

comparison of these objective measures, which consider a 8

broad spectrum of risks, including financial and business 9

position, relative size, and exposure to company-specific 10

factors, indicates that investors would likely conclude 11

that the overall investment risks for Tampa Electric are 12

greater than those of the firms in the Utility and Non-13

Utility Proxy Groups. 14

15

My Non-Utility Proxy Group is comprised of 59 of the 16

best-known and most stable corporations in America and 17

has risk measures that are comparable to, or less than 18

the proxy groups of electric utilities referenced in my 19

analyses. While these companies do not have the 20

regulatory protections that utilities have, neither do 21

they bear the burdens of losing control over their 22

prices, undertaking the obligation to serve, and having 23

to invest in infrastructure even in unfavorable market 24

conditions. Tampa Electric can’t relocate its service 25


79

territory to an area with higher prospects for economic 1

growth or less exposure to storm damage, postpone capital 2

spending necessary to maintain reliability and 3

accommodate growth, or abandon customers when turmoil 4

roils energy or capital markets. 5

6

Q. What were the results of your DCF analysis for the Non-7

Utility Proxy Group? 8

9

A. The results of my DCF analysis for the Non-Utility Proxy 10

Group are presented in Exhibit TEC-207, with the 11

sustainable, br+sv growth rates being developed on 12

Exhibit TEC-208. As shown there, after eliminating 13

illogical low and high-end values, application of the 14

constant growth DCF model resulted in an ROE range of 15

reasonableness of 8.6 percent to 16.5 percent, with a 16

midpoint of 12.5 percent. Calculating the median based 17

on the average of the low and high DCF estimates for each 18

company with no extreme outliers resulted in an indicated 19

cost of equity of 12.6 percent.84 20

21

Expected Earnings Approach 22

Q. What other benchmarks did you develop to evaluate the ROE 23

84 This is identical to the approach used by the Commission and applied earlier to the Regional Proxy Group.


80

for Tampa Electric? 1

2

A. As I noted earlier, I also evaluated the ROE by reference 3

to expected rates of return for electric utilities. 4

Reference to rates of return available from alternative 5

investments of comparable risk can provide an important 6

benchmark in assessing the return necessary to assure 7

confidence in the financial integrity of a firm and its 8

ability to attract capital. This approach is consistent 9

with the economic underpinnings for a fair rate of 10

return, as reflected in the comparable earnings test 11

established by the Supreme Court in Hope and Bluefield. 12

Moreover, it avoids the complexities and limitations of 13

capital market methods and instead focuses on the returns 14

earned on book equity, which are readily available to 15

investors. 16

17

Q. What economic premise underlies the expected earnings 18

approach? 19

20

A. The simple, but powerful concept underlying the expected 21

earnings approach is that investors compare each 22

investment alternative with the next best opportunity. 23

If the utility is unable to offer a return similar to 24

that available from other opportunities of comparable 25


81

risk, investors will become unwilling to supply the 1

capital on reasonable terms. For existing investors, 2

denying the utility an opportunity to earn what is 3

available from other similar risk alternatives prevents 4

them from earning their opportunity cost of capital. In 5

this situation the government is effectively taking the 6

value of investors’ capital without adequate 7

compensation. 8

9

Q. How is the comparison of opportunity costs typically 10

implemented? 11

12

A. The traditional comparable earnings test identifies a 13

group of companies that are believed to be comparable in 14

risk to the utility. The actual earnings of those 15

companies on the book value of their investment are then 16

compared to the allowed return of the utility. While the 17

traditional comparable earnings test is implemented using 18

historical data taken from the accounting records, it is 19

also common to use projections of returns on book 20

investment, such as those published by recognized 21

investment advisory publications (e.g., Value Line). 22

Because these returns on book value equity are analogous 23

to the allowed return on a utility’s rate base, this 24

measure of opportunity costs results in a direct, “apples 25


82

to apples” comparison. 1

2

Moreover, regulators do not set the returns that 3

investors earn in the capital markets – they can only 4

establish the allowed return on the value of a utility’s 5

investment, as reflected on its accounting records. As a 6

result, the expected earnings approach provides a direct 7

guide to ensure that the allowed ROE is similar to what 8

other utilities of comparable risk will earn on invested 9

capital. This opportunity cost test does not require 10

theoretical models to indirectly infer investors’ 11

perceptions from stock prices or other market data. As 12

long as the proxy companies are similar in risk, their 13

expected earned returns on invested capital provide a 14

direct benchmark for investors’ opportunity costs that is 15

independent of fluctuating stock prices, market-to-book 16

ratios, debates over DCF growth rates, or the limitations 17

inherent in any theoretical model of investor behavior. 18

19

Q. What rates of return on equity are indicated for electric 20

utilities based on the expected earnings approach? 21

22

A. Value Line reports that its analysts anticipate an 23

average rate of return on common equity for the electric 24

utility industry of 11.0 percent in 2010 and 2011, and 25


83

11.5 percent over its 2013-2015 forecast horizon.85 1

Meanwhile, for the firms in the Regional Proxy Group 2

specifically, the returns on common equity projected by 3

Value Line over its forecast horizon are shown on page 1 4

of Exhibit TEC-209. Consistent with the rationale 5

underlying the development of the br+sv growth rates, 6

these year-end values were converted to average returns 7

using the same adjustment factor discussed earlier and 8

developed on Exhibit TEC-205. As shown on page 1 of 9

Exhibit TEC-209, Value Line’s projections for the 10

Regional Proxy Group suggest an average ROE of 11.5 11

percent, or 12.9 percent after eliminating low-end 12

outliers. With respect to the Ratings Screen Proxy 13

Group, Value Line’s projections imply an expected rate of 14

return of 10.8 percent, or 11.6 percent after excluding 15

illogical values (Exhibit TEC-209, page 2). 16

17

ROE FOR TAMPA ELECTRIC 18

Q. What is the purpose of this section? 19

20

A. This section presents my conclusions regarding a 21

reasonable ROE for Tampa Electric. It examines other 22

factors properly considered in determining a fair rate of 23

return, including the relationship between ROE and 24

85 The Value Line Investment Survey at 901 (Mar. 26, 2010).


84

preservation of a utility’s financial integrity and the 1

ability to attract capital. 2

3

Implications for Financial Integrity 4

Q. Why is it important to allow Tampa Electric an adequate 5

ROE? 6

7

A. Given the social and economic importance of the utility 8

industry, it is essential to maintain reliable and 9

economical service to all consumers. While it is 10

customers that ultimately realize the benefits of 11

increased investment in wholesale utility infrastructure, 12

a utility’s ability to fulfill its mandate can be 13

compromised if it lacks the necessary financial 14

wherewithal or is unable to earn a return sufficient to 15

attract capital. 16

17

As documented earlier, the major rating agencies have 18

warned of exposure to uncertainties associated with 19

political and regulatory developments, especially in view 20

of current financial and operating pressures in the 21

utility industry. Investors understand just how swiftly 22

unforeseen circumstances can lead to deterioration in a 23

utility’s financial condition, and stakeholders have 24

discovered firsthand how difficult and complex it can be 25


85

to remedy the situation after the fact. Investors’ 1

increased reticence to supply additional capital during 2

times of crisis highlights the need to preserve financial 3

flexibility and the importance of allowing an adequate 4

ROE. 5

6

Q. What role does regulation play in ensuring access to 7

capital for Tampa Electric? 8

9

A. Considering investors’ heightened awareness of the risks 10

associated with the utility industry and the damage that 11

results when a utility’s financial flexibility is 12

compromised, fair and balanced regulation remains crucial 13

to the Company’s access to capital. Investors recognize 14

that regulation has its own risks, and that constructive 15

regulation is a key ingredient in supporting utility 16

credit ratings and financial integrity, particularly 17

during times of adverse conditions. 18

19

Fitch concluded, “[G]iven the lingering rate of 20

unemployment and voter concerns about the economy, there 21

could well be pockets of adverse rate decisions, and 22

those companies with little financial cushion could 23

suffer adverse effects.”86 Moody’s has also emphasized 24

86 Fitch Ratings Ltd., “U.S. Utilities, Power and Gas 2010 Outlook,” Global Power North America Special Report (Dec. 4, 2009).


86

the need for regulatory support, concluding: 1

2 For the longer term, however, we are becoming 3 increasingly concerned about possible changes 4 to our fundamental assumptions about regulatory 5 risk, particularly the prospect of a more 6 adversarial political (and therefore 7 regulatory) environment. A prolonged 8 recessionary climate with high unemployment, or 9 an intense period of inflation, could make cost 10 recovery more uncertain.87 11

12

S&P noted “the quality of regulation is at the forefront 13

of our analysis of utility creditworthiness.”88 14

15

With respect to Florida specifically, in October 2009 16

Moody’s expressed concern regarding the state’s 17

regulatory climate: 18

19 Moody’s views the highly politicized atmosphere 20 surrounding the base rate proceedings of 21 Florida Power & Light Company … as negative to 22 the credit quality … and an indication that the 23 political and regulatory environment for 24 investor-owned utilities in Florida may be 25 deteriorating. … Moody’s views political 26 intervention in the utility regulatory process 27 as detrimental to credit quality, sometimes 28 resulting in adverse rate case outcomes. In 29 some cases this has led to multi-notch credit 30 rating downgrades of utilities in states where 31 this has occurred….89 32

Similarly, S&P noted that, “Regulatory developments 33

87 Moody’s Investors Service, “U.S. Regulated Electric Utilities, Six-Month Update,” Industry Outlook (July 2009).

88 Standard & Poor’s Corporation, “Assessing U.S. Utility Regulatory Environments,” RatingsDirect (Nov. 7, 2008).

89 Moody’s Investors Service, “Issuer Comment: Moody’s Views Politicized Florida Rate Cases as Credit Negative,” Global Credit Research (Oct. 7, 2009).


87

unrelated to TECO have raised questions about the 1

regulatory risk in Florida.”90 While recognizing that 2

Tampa Electric’s near-term exposure to these 3

uncertainties is limited, Moody’s concluded that 4

deterioration of the Florida regulatory environment could 5

undermine Tampa Electric’s credit profile and lead to 6

lower ratings.91 7

8

Q. Does the fact that Tampa Electric operates under various 9

cost adjustment mechanisms warrant any adjustment in your 10

evaluation of a fair ROE? 11

12

A. No. Investors recognize that Tampa Electric is exposed 13

to significant risks associated with energy price 14

volatility, and rising costs and concerns over these 15

risks have become increasingly pronounced in the 16

industry. The FPSC’s cost adjustment mechanisms are a 17

valuable means of mitigating those risks, but they do not 18

eliminate exposure to volatility and uncertainties over 19

cost recovery. Investors also recognize the potential 20

that regulators can discontinue rate mechanisms. As 21

noted above, of particular concern to investors is the 22

impact of regulatory lag and cost-recovery on the 23

90 Standard & Poor’s Corporation, “Summary: Tampa Electric Co.,” RatingsDirect (Dec. 28, 2009).

91 Moody’s Investors Service, “Credit Opinion: Tampa Electric Company,” Global Credit Research (May 14, 2010).


88

utility’s ability to earn its authorized return. While 1

the adjustment mechanisms approved for Tampa Electric 2

partially attenuate exposure to attrition in an era of 3

rising costs, this leveling of the playing field only 4

serves to preserve Tampa Electric’s opportunity to earn 5

its authorized return, as required by established 6

regulatory standards. 7

8

Moreover, adjustment mechanisms and contractual 9

arrangements that enable utilities to implement rate 10

changes to pass-through fluctuations in fuel costs have 11

been widely prevalent in the industry, and utilities 12

increasingly benefit from a wide variety of mechanisms 13

designed to mitigate against the risks associated with 14

fluctuations in costs and regulatory lag. While not 15

always directly analogous to the specific mechanisms in 16

effect for Tampa Electric, the objective is similar; 17

namely, to allow the utility an opportunity to earn a 18

fair rate of return and partially attenuate exposure to 19

attrition in an era of rising costs. Reflective of this 20

industry trend, the companies in the proxy group operate 21

under a variety of cost adjustment mechanisms, which 22

range from riders to recover bad debt expense and post-23

retirement employee benefit costs to adjustment clauses 24

designed to address the rising costs of environmental 25


89

compliance measures. As a result, the mitigation in 1

risks associated with utilities’ ability to attenuate the 2

impact of fluctuations in costs is already reflected in 3

the cost of equity estimates developed earlier. 4

5

Q. Do the exposures unique to Tampa Electric highlight the 6

need for ongoing support of the Company’s financial 7

strength and ability to attract capital? 8

9

A. Most definitely. As discussed earlier, Tampa Electric 10

faces a number of potential challenges that might require 11

the relatively swift commitment of considerable capital 12

resources in order to maintain the high level of service 13

to which its customers have become accustomed. For 14

example, shutdowns of generating facilities in response 15

to security threats or other catastrophic events would 16

impose significant reliance on wholesale power markets to 17

meet energy shortfalls. Tampa Electric’s relative 18

geographic isolation on the Florida peninsula also 19

imposes increased vulnerability to fuel supply 20

disruptions. Similarly, any interruption of gas supplies 21

due to deliverability constraints imposed on Tampa 22

Electric’s suppliers could also result in the need for a 23

considerable financial commitment for an alternative fuel 24

source or replacement power. 25


90

Given the potential for significant volatility in 1

wholesale energy markets and Tampa Electric’s lack of 2

control over the timing of such events, Tampa Electric 3

must have the wherewithal to meet these challenges even 4

when capital and energy market conditions are 5

unfavorable. In addition, it is crucial that Tampa 6

Electric maintain its ability to meet the significant 7

liquidity requirements necessary for storm restoration, 8

as well as the requirements of other programs such as 9

fuel hedging. Apart from exposure to the vagaries of 10

capital and energy market conditions, Tampa Electric must 11

simultaneously meet the long-term energy needs of its 12

retail service area and wholesale customers. To continue 13

to meet these challenges successfully and economically, 14

it is crucial that Tampa Electric receive adequate 15

support for its credit standing. 16

17

Q. Do customers benefit by enhancing the utility’s financial 18

flexibility? 19

20

A. Yes. Providing an ROE that is sufficient to compensate 21

investors and maintain Tampa Electric’s ability to 22

attract capital, even under duress, is consistent with 23

the economic requirements embodied in the Supreme Court’s 24

Hope and Bluefield decisions, but it is also in 25


91

customers’ best interests. Ultimately, it is customers 1

and the service area economy that enjoy the benefits that 2

come from ensuring that regional utilities have the 3

financial wherewithal to take whatever actions are 4

required to ensure a reliable energy supply. By the same 5

token, customers also bear a significant burden when the 6

ability to attract capital for system enhancements is 7

impaired and service quality is compromised. 8

9

Q. What evidence illustrates the benefits of maintaining 10

Tampa Electric’s ability to attract capital? 11

12

A. In recent years, Tampa Electric has invested the 13

substantial capital required to add the new generation 14

and transmission capacity dictated by the demands of a 15

vibrant service area and wholesale demand in peninsular 16

Florida and repair the devastation wrought by tropical 17

storms. Despite the associated complexities, including 18

volatile conditions in energy and capital markets, Tampa 19

Electric has effectively and economically responded to 20

these challenges, in part due to its strong financial 21

position. 22

23

While Tampa Electric's consistent efforts to keep pace 24

with the needs of its service area has benefited 25


92

customers and provided a strong platform for continued 1

success, actions that serve to erode financial strength 2

or impair financial flexibility could have swift and 3

damaging consequences. The cost of providing Tampa 4

Electric an adequate return is small relative to the 5

potential benefits that a strong utility can have in 6

providing reliable service and fostering growth. 7

8

Capital Structure 9

Q. Is an evaluation of the capital structure maintained by a 10

utility relevant in assessing its ROE? 11

12

A. Yes. Other things being equal, a higher debt ratio, or 13

lower common equity ratio, translates into increased 14

financial risk for all investors. A greater amount of 15

debt means more investors have a senior claim on 16

available cash flow, thereby reducing the certainty that 17

each will receive his contractual payments. This 18

increases the risks to which lenders are exposed, and 19

they require correspondingly higher rates of interest. 20

From common shareholders’ standpoint, a higher debt ratio 21

means that there are proportionately more investors ahead 22

of them, thereby increasing the uncertainty as to the 23

amount of cash flow, if any that will remain. 24

25


93

Q. What common equity ratio will be used to establish the 1

Company’s overall rate of return? 2

3

A. Tampa Electric’s capitalization reflects a common equity 4

ratio of 50.9 percent in this filing, which is based on 5

the Company’s actual capital structure reported in its 6

2009 FERC Form No. 1 Report. 7

8

Q. How does this compare with common equity ratios 9

maintained by the proxy groups of other electric 10

utilities? 11

12

A. As shown on page 1 of Exhibit No. TEC-210, common equity 13

ratios for the individual firms in the Regional Proxy 14

Group ranged from a low of 38.7 percent to a high of 56.3 15

percent at year-end 2009, with the average being 44.9 16

percent. For the Ratings Screen Proxy Group, the average 17

equity ratio at year-end 2009 was 44.0 percent (page 2 of 18

Exhibit No. TEC-210). 19

20

Q. What capitalization is representative for the proxy 21

groups going forward? 22

23

A. As shown on pages 1 and 2 of Exhibit No. TEC-210, Value 24

Line expects an average common equity ratio of 46.5 25


94

percent for its three-to-five-year forecast horizon for 1

the Regional Proxy Group and 46.9 percent for the Ratings 2

Screen Proxy Group. 3

4

Q. What capitalization ratios are maintained by other 5

electric utility operating companies? 6

7

A. Exhibit No. TEC-211 displays capital structure data at 8

year-end 2009 for the group of electric utility operating 9

companies owned by the firms in the Regional Proxy Group. 10

As shown there, common equity ratios for this group of 11

electric utility operating companies ranged from 33.7 12

percent to 73.7 percent and averaged 51.5 percent. 13

14

Q. What implication does the increasing risk of the industry 15

have for the capital structures maintained by utilities? 16

17

A. As discussed earlier, utilities are facing energy market 18

volatility, rising cost structures, the need to finance 19

significant capital investment plans, uncertainties over 20

accommodating future environmental mandates, and ongoing 21

regulatory risks. Coupled with the potential for turmoil 22

in capital markets, these considerations warrant a 23

stronger balance sheet to deal with an increasingly 24

uncertain environment. A more conservative financial 25


95

profile, in the form of a higher common equity ratio, is 1

consistent with increasing uncertainties and the need to 2

maintain the continuous access to capital that is 3

required to fund operations and necessary system 4

investments, even during times of adverse capital market 5

conditions. 6

7

Moody’s has repeatedly warned investors of the risks 8

associated with debt leverage and fixed obligations and 9

advised utilities not to squander the opportunity to 10

strengthen the balance sheet as a buffer against future 11

uncertainties.92 More recently, Moody’s concluded: 12

13

From a credit perspective, we believe a strong 14 balance sheet coupled with abundant sources of 15 liquidity represents one of the best defenses 16 against business and operating risk and 17 potential negative ratings actions.93 18

19

Similarly, S&P recently noted that, “we generally 20

consider a debt to capital level of 50% or greater to be 21

aggressive or highly leveraged for utilities.”94 Fitch 22

affirmed that it expects regulated utilities “to extend 23

their conservative balance sheet stance in 2010,” and 24

92 Moody’s Investors Service, “Storm Clouds Gathering on the Horizon for the North American Electric Utility Sector,” Special Comment (Aug. 2007); “U.S. Electric Utility Sector,” Industry Outlook (Jan. 2008).


94 Standard & Poor’s Corporation, “Ratings Roundup: U.S. Electric Utility Sector Maintained Strong Credit Quality In A Gloomy 2009,” RatingsDirect (Jan. 26, 2010).


96

employ “a judicious mix of debt and equity to finance 1

high levels of planned investments.”95 2

3

Q. What other factors do investors consider in their 4

assessment of capital structure? 5

6

A. Depending on their specific attributes, contractual 7

agreements that obligate the utility to make specified 8

payments may be treated as debt in evaluating a utility’s 9

financial risk. Because such obligations typically 10

require the utility to make specified minimum contractual 11

payments akin to those associated with traditional debt 12

financing, investors consider a portion of these 13

commitments as debt in evaluating total financial risks. 14

The implications of these obligations have been 15

repeatedly cited by major bond rating agencies in 16

connection with assessments of utility financial risks. 17

Because bond ratings agencies and investors consider the 18

debt impact of such fixed obligations in assessing a 19

utility’s financial position, they imply greater risk and 20

reduced financial flexibility.96 21

22

Q. What does this evidence suggest with respect to Tampa 23


96 The capital structure ratios presented earlier do not include imputed debt associated with power purchase agreements or the impact of other off-balance sheet obligations.


97

Electric’s proposed capital structure? 1

2

A. Based on my evaluation, I concluded that Tampa Electric’s 3

proposed capital structure represents a reasonable mix of 4

capital sources from which to calculate Tampa Electric’s 5

overall rate of return. While a capital structure 6

consisting of 50.9 percent common equity exceeds the 7

average maintained by the companies in the Regional and 8

Ratings Screen Proxy Groups, it falls within the bounds 9

of the ranges for the two proxy groups and below the 10

average equity ratio maintained by the corresponding 11

electric utility operating companies. Moreover, long-12

standing Commission precedent reflects a clear preference 13

for using the actual capital structure of the utility in 14

establishing the overall rate of return.97 As the 15

Commission stated in Kentucky West Virginia, for example: 16

17

In our opinion a utility should be regulated on 18 the basis of its being an independent entity; 19 that is, a utility should be considered as 20 nearly as possible on its own merits.98 21

22

In fact, the Commission has specifically rejected the 23

notion that a utility’s capital structure must fall 24

97 See, e.g., Kentucky West Virginia, Opinion No. 7, 2 FERC ¶ 61,139 (1978); Transcontinental Gas Pipeline Corp., 84 FERC ¶ 61,084 (1998).

98 Kentucky West Virginia, Opinion No. 7, 2 FERC ¶ 61,139 at 61,325 (1978); quoting Fla. Gas Transmission Co., 47 FPC 341, (1972).


98

within the range of the proxy group to be considered 1

reasonable. In Transcontinental Gas Pipeline Corp, the 2

Commission noted that an appropriate capital structure 3

“can fall within a very broad range,” and concluded, 4

“[T]he Commission has determined that it will not 5

continue to require that a pipeline’s equity ratio be 6

within the range established by the proxy companies in 7

order to use the pipeline’s own capital structure.”99 The 8

Commission has affirmed application of these guidelines 9

in evaluating the capital structure of electric 10

utilities.100 11

12

While industry averages provide one benchmark for 13

comparison, each firm must select its capitalization 14

based on the risks and prospects it faces, as well as its 15

specific needs to access the capital markets. Financial 16

flexibility plays a crucial role in ensuring the 17

wherewithal to meet the needs of customers, and utilities 18

with higher leverage may be foreclosed from additional 19

borrowing, especially during times of stress. Because of 20

the Company’s obligation to serve, Tampa Electric must 21

maintain ready access to capital under reasonable terms 22

so that it can meet the service requirements of its 23

99 Transcontinental Gas Pipeline Corp., 84 FERC ¶ 61,084 at pp. 16-17 (1998). 100

See, e.g., Allegheny Power, Opinion No. 469, 106 FERC ¶ 61,241 (2004); Milford Power Co., LLC, 110 FERC ¶61,299 at P 73 (2005) (ruling that actual debt/equity ratios that can be substantiated are preferred over a proxy capital structure).


99

wholesale and retail customers. The need for access 1

becomes even more important when the company has capital 2

requirements over a period of years, and financing must 3

be continuously available, even during unfavorable 4

capital market conditions. 5

6

ROE Recommendation 7

Q. Please summarize the results of your analyses. 8

9

A. The cost of common equity estimates produced by the 10

various capital market oriented analyses described in my 11

testimony are summarized in Table WEA-4, below: 12

13

14

15

16

17

18

19

20

21

22

23

24

25


100

Low High

Regional Proxy GroupRange of Reasonableness 8.2% -- 13.6%

MidpointMedian

Ratings Screen Proxy GroupRange of Reasonableness 8.2% -- 13.6%

MidpointMedian

Non-Utility DCFRange of Reasonableness 8.6% -- 16.5%

MidpointMedian

Expected Earnings ApproachValue Line Electric Utilities

201020112013-15

Regional Proxy GroupRange of Reasonableness 9.0% -- 16.2%

MidpointMedian

Ratings Screen Proxy GroupRange of Reasonableness 9.0% -- 14.1%

MidpointMedian

11.5%11.6%

Implied Cost of Equity

10.9%10.7%

10.9%10.5%

11.0%11.0%11.5%

12.5%12.6%

12.6%12.9%

TABLE WEA-4 1

SUMMARY OF COST OF EQUITY ESTIMATES 2

3

4

5

6

7

8

9

10

11

12

13

14

15

16

17

18

19

Q. What is your conclusion regarding a reasonable ROE for 20

Tampa Electric? 21

22

A. Based on my assessment of the relative strengths and 23

weaknesses inherent in the alternative results, it is my 24

opinion that 11.25 percent represents a fair and 25


101

reasonable ROE for Tampa Electric. While my 11.25 percent 1

ROE recommendation exceeds the midpoint and median 2

produced for the Regional and Ratings Screen Proxy Groups 3

using the Commission’s DCF approach, it falls within the 4

ROE zones of reasonableness produced by these analyses. 5

Moreover, an ROE above the midpoint and median values 6

indicated by the Commission’s DCF method is supported by 7

reference to alternative ROE benchmarks, which 8

consistently support a higher allowed return. 9

10

Q. What other evidence is relevant in evaluating the results 11

of the Commission’s DCF approach? 12

13

A. Reference to the allowed rate of return for Tampa 14

Electric’s state-jurisdictional operations also provides 15

a useful guideline that can be used to assess the extent 16

to which the results of the FERC’s DCF approach are 17

comparable and sufficient. Currently, the FPSC has 18

established an ROE range of 10.25 percent to 12.25 19

percent for Tampa Electric, with a midpoint of 11.25 20

percent. These values were set by the FPSC in March 2009 21

as part of Tampa Electric’s base rate proceeding filed in 22

August 2008. 23

24

While the findings of the FPSC certainly do not limit the 25


102

Commission’s authority with respect to ROE, there would 1

be a disincentive to invest in FERC-jurisdictional 2

infrastructure if these utility assets would result in a 3

lower ROE. Moreover, the Commission’s long-standing 4

policy objective, as reflected in Order No. 679 and 5

numerous other decisions, has been to increase the level 6

of capital investment in electric utility facilities. In 7

allowing an incentive-based ROE for investments in new 8

transmission facilities, for example, the Commission 9

recognized the importance of providing an ROE that 10

overcomes obstacles to new projects and encourages 11

investment.101 The Commission noted that FERC-12

jurisdictional projects must compete for capital, and 13

that an incentive ROE would provide an effective tool to 14

foster new investment. 15

16

The level of past investment in wholesale utility 17

infrastructure has generally been deemed insufficient and 18

while there is no doubt a variety of strategic and 19

regulatory explanations for the reluctance of integrated 20

utilities to commit capital, there is also the 21

possibility that the ROE levels allowed in the past have 22

not been sufficient to attract new capital investment. 23

Hence, the prudent regulatory policy is to consider the 24

11.25 percent ROE that is currently allowed on Tampa 25

101 Order No. 679 at P 91.


103

Electric’s integrated utility assets. 1

2

Apart from the results of these quantitative methods, it 3

is crucial to recognize the importance of maintaining the 4

company’s financial position so that Tampa Electric 5

remains prepared to respond to unforeseen events that may 6

materialize in the future. While this imperative is 7

reinforced by recent capital market conditions, it 8

extends well beyond the financial markets and includes 9

the company’s ability to absorb potential shocks 10

associated with devastating hurricanes, volatile fuel 11

pricing, and disruptions in energy supply. My 12

conclusions are reinforced by the need to consider 13

flotation costs, and the fact that current cost of 14

capital estimates are likely to understate investors’ 15

requirements at the time the outcome of this proceeding 16

becomes effective and beyond. Coupled with the need to 17

provide an ROE that supports Tampa Electric’s credit 18

standing while funding necessary investments in utility 19

infrastructure, these considerations indicate that an 20

11.25 percent ROE is reasonable and appropriate. 21

22

Q. Does this conclude your direct testimony in this case? 23

24

A. Yes, it does. 25

DOCKET NO. ER10-____-000 WITNESS: AVERA

104

EXHIBITS

OF

WILLIAM E. AVERA

ON BEHALF OF TAMPA ELECTRIC COMPANY


105

Table of Contents

EXHIBIT NO. TITLE PAGE

TEC-201 Qualifications of William E. Avera 106

TEC-202 Risk Measures – Regional Proxy Group 112

TEC-203 Risk Measures – Ratings Screen Proxy

Group 113

TEC-204 FERC DCF Model – Regional Proxy Group 114

TEC-205 “br + sv” Growth Rate – Regional Proxy

Group 115

TEC-206 FERC DCF Model – Ratings Screen Proxy

Group 118

TEC-207 DCF Model – Non-Utility Proxy Group 119

TEC-208 “br + sv” Growth Rate – Non-Utility

Proxy Group 121

TEC-209 Expected Earnings Approach – Regional

and Ratings Screen Proxy Group 124

TEC-210 Capital Structure – Regional and

Ratings Screen Proxy Groups 126

TEC-211 Capital Structure – Operating Companies 128

WILLIAM E. AVERA

FINCAP, INC. 3907 Red River Financial Concepts and Applications Austin, Texas 78751 Economic and Financial Counsel (512) 458–4644 FAX (512) 458–4768 [email protected] Summary of Qualifications Ph.D. in economics and finance; Chartered Financial Analyst (CFA ®) designation; extensive expert witness testimony before courts, alternative dispute resolution panels, regulatory agencies and legislative committees; lectured in executive education programs around the world on ethics, investment analysis, and regulation; undergraduate and graduate teaching in business and economics; appointed to leadership positions in government, industry, academia, and the military. Employment

Principal, FINCAP, Inc. (Sep. 1979 to present)

Financial, economic and policy consulting to business and government. Perform business and public policy research, cost/benefit analyses and financial modeling, valuation of businesses (almost 200 entities valued), estimation of damages, statistical and industry studies. Provide strategy advice and educational services in public and private sectors, and serve as expert witness before regulatory agencies, legislative committees, arbitration panels, and courts.

Director, Economic Research Division, Public Utility Commission of Texas (Dec. 1977 to Aug. 1979)

Responsible for research and testimony preparation on rate of return, rate structure, and econometric analysis dealing with energy, telecommunications, water and sewer utilities. Testified in major rate cases and appeared before legislative committees and served as Chief Economist for agency. Administered state and federal grant funds. Communicated frequently with political leaders and representatives from consumer groups, media, and investment community.

Manager, Financial Education, International Paper Company New York City (Feb. 1977 to Nov. 1977)

Directed corporate education programs in accounting, finance, and economics. Developed course materials, recruited and trained instructors, liaison within the company and with academic institutions. Prepared operating budget and designed financial controls for corporate professional development program.

DOCKET NO. ER10-____-000EXHIBIT NO. TEC-201WITNESS: AVERAFILED: 07/30/2010PAGE 1 OF 6

106

Lecturer in Finance, The University of Texas at Austin (Sep. 1979 to May 1981) Assistant Professor of Finance, (Sep. 1975 to May 1977)

Taught graduate and undergraduate courses in financial management and investment theory. Conducted research in business and public policy. Named Outstanding Graduate Business Professor and received various administrative appointments.

Assistant Professor of Business, University of North Carolina at

Chapel Hill (Sep. 1972 to Jul. 1975)

Taught in BBA, MBA, and Ph.D. programs. Created project course in finance, Financial Management for Women, and participated in developing Small Business Management sequence. Organized the North Carolina Institute for Investment Research, a group of financial institutions that supported academic research. Faculty advisor to the Media Board, which funds student publications and broadcast stations.

Education Ph.D., Economics and Finance, University of North Carolina at

Chapel Hill (Jan. 1969 to Aug. 1972)

Elective courses included financial management, public finance, monetary theory, and econometrics. Awarded the Stonier Fellowship by the American Bankers' Association and University Teaching Fellowship. Taught statistics, macroeconomics, and microeconomics. Dissertation: The Geometric Mean Strategy as a Theory of Multiperiod Portfolio Choice

B.A., Economics, Emory University, Atlanta, Georgia (Sep. 1961 to Jun. 1965)

Active in extracurricular activities, president of the Barkley Forum (debate team), Emory Religious Association, and Delta Tau Delta chapter. Individual awards and team championships at national collegiate debate tournaments.

Professional Associations Received Chartered Financial Analyst (CFA) designation in 1977; Vice President for Membership, Financial Management Association; President, Austin Chapter of Planning Executives Institute; Board of Directors, North Carolina Society of Financial Analysts; Candidate Curriculum Committee, Association for Investment Management and Research; Executive Committee of Southern Finance Association; Vice Chair, Staff Subcommittee on Economics and National Association of Regulatory Utility Commissioners (NARUC); Appointed to NARUC Technical Subcommittee on the National Energy Act. Teaching in Executive Education Programs University-Sponsored Programs: Central Michigan University, Duke University, Louisiana State University, National Defense University, National University of Singapore, Texas A&M University, University of Kansas, University of North Carolina, University of Texas.


107

Business and Government-Sponsored Programs: Advanced Seminar on Earnings Regulation, American Public Welfare Association, Association for Investment Management and Research, Congressional Fellows Program, Cost of Capital Workshop, Electricity Consumers Resource Council, Financial Analysts Association of Indonesia, Financial Analysts Review, Financial Analysts Seminar at Northwestern University, Governor's Executive Development Program of Texas, Louisiana Association of Business and Industry, National Association of Purchasing Management, National Association of Tire Dealers, Planning Executives Institute, School of Banking of the South, State of Wisconsin Investment Board, Stock Exchange of Thailand, Texas Association of State Sponsored Computer Centers, Texas Bankers' Association, Texas Bar Association, Texas Savings and Loan League, Texas Society of CPAs, Tokyo Association of Foreign Banks, Union Bank of Switzerland, U.S. Department of State, U.S. Navy, U.S. Veterans

dministration, in addition to Texas state agencies and major corporations. A Presented papers for Mills B. Lane Lecture Series at the University of Georgia and Heubner Lectures at the University of Pennsylvania. Taught graduate courses in finance and economics for evening program at St. Edward's University in Austin from January 1979 through 1998. Expert Witness Testimony Testified in over 300 cases before regulatory agencies addressing cost of capital, regulatory policy, ate design, and other economic and financial issues. r

Federal Agencies: Federal Communications Commission, Federal Energy Regulatory Commission, Surface Transportation Board, Interstate Commerce Commission, and the Canadian

adio-Television and Telecommunications Commission. R State Regulatory Agencies: Alaska, Arizona, Arkansas, California, Colorado, Connecticut, Delaware, Florida, Georgia, Hawaii, Idaho, Illinois, Indiana, Iowa, Kansas, Kentucky, Maryland, Michigan, Missouri, Nevada, New Mexico, Montana, North Carolina, Ohio, Oklahoma, Oregon, Pennsylvania, South Carolina, South Dakota, Texas, Utah, Virginia, Washington, West Virginia,

isconsin, and Wyoming. W Testified in 42 cases before federal and state courts, arbitration panels, and alternative dispute tribunals (88 depositions given) regarding damages, valuation, antitrust liability, fiduciary duties, and other economic and financial issues. Board Positions and Other Professional Activities Audit Committee and Outside Director, Georgia System Operations Corporation (electric system operator for member-owned electric cooperatives in Georgia); Chairman, Board of Print Depot, Inc. and FINCAP, Inc.; Co-chair, Synchronous Interconnection Committee, appointed by Public Utility Commission of Texas and approved by governor; Appointed by Hays County Commission to Citizens Advisory Committee of Habitat Conservation Plan, Operator of AAA Ranch, a certified organic producer of agricultural products; Appointed to Organic Livestock Advisory Committee by Texas Agricultural Commissioner Susan Combs; Appointed by Texas Railroad Commissioners to study group for The UP/SP Merger: An Assessment of the Impacts on the State of Texas; Appointed by Hawaii Public Utilities Commission to team reviewing affiliate relationships of Hawaiian Electric Industries; Chairman, Energy Task Force, Greater Austin-San Antonio Corridor Council; Consultant to Public Utility Commission of Texas on cogeneration policy and other matters; Consultant to


108

Public Service Commission of New Mexico on cogeneration policy; Evaluator of Energy Research Grant Proposals for Texas Higher Education Coordinating Board. Community Activities Board of Directors, Sustainable Food Center; Chair, Board of Deacons, Finance Committee, and Elder, Central Presbyterian Church of Austin; Founding Member, Orange-Chatham County (N.C.) Legal Aid Screening Committee. Military Captain, U.S. Naval Reserve (retired after 28 years service); Commanding Officer, Naval Special Warfare Engineering (SEAL) Support Unit; Officer-in-Charge of SWIFT patrol boat in Vietnam; Enlisted service as weather analyst (advanced to second class petty officer). Bibliography M onographs

Ethics and the Investment Professional (video, workbook, and instructor’s guide) and Ethics Challenge Today (video), Association for Investment Management and Research (1995)

“Definition of Industry Ethics and Development of a Code” and “Applying Ethics in the Real World,” in Good Ethics: The Essential Element of a Firm’s Success, Association for Investment Management and Research (1994)

“On the Use of Security Analysts’ Growth Projections in the DCF Model,” with Bruce H. Fairchild in Earnings Regulation Under Inflation, J. R. Foster and S. R. Holmberg, eds. Institute for Study of Regulation (1982)

An Examination of the Concept of Using Relative Customer Class Risk to Set Target Rates of Return in Electric Cost-of-Service Studies, with Bruce H. Fairchild, Electricity Consumers Resource Council (ELCON) (1981); portions reprinted in Public Utilities Fortnightly (Nov. 11, 1982)

“Usefulness of Current Values to Investors and Creditors,” Research Study on Current-Value Accounting Measurements and Utility, George M. Scott, ed., Touche Ross Foundation (1978)

“The Geometric Mean Strategy and Common Stock Investment Management,” with Henry A. Latané in Life Insurance Investment Policies, David Cummins, ed. (1977)

Investment Companies: Analysis of Current Operations and Future Prospects, with J. Finley Lee and Glenn L. Wood, American College of Life Underwriters (1975)

A rticles

“Should Analysts Own the Stocks they Cover?” The Financial Journalist, (March 2002) “Liquidity, Exchange Listing, and Common Stock Performance,” with John C. Groth and Kerry

Cooper, Journal of Economics and Business (Spring 1985); reprinted by National Association of Security Dealers

“The Energy Crisis and the Homeowner: The Grief Process,” Texas Business Review (Jan.–Feb. 1980); reprinted in The Energy Picture: Problems and Prospects, J. E. Pluta, ed., Bureau of Business Research (1980)

“Use of IFPS at the Public Utility Commission of Texas,” Proceedings of the IFPS Users Group Annual Meeting (1979)


109

"Production Capacity Allocation: Conversion, CWIP, and One-Armed Economics,” Proceedings of the NARUC Biennial Regulatory Information Conference (1978)

"Some Thoughts on the Rate of Return to Public Utility Companies,” with Bruce H. Fairchild in Proceedings of the NARUC Biennial Regulatory Information Conference (1978)

"A New Capital Budgeting Measure: The Integration of Time, Liquidity, and Uncertainty,” with David Cordell in Proceedings of the Southwestern Finance Association (1977)

"Usefulness of Current Values to Investors and Creditors,” in Inflation Accounting/Indexing and Stock Behavior (1977)

"Consumer Expectations and the Economy,” Texas Business Review (Nov. 1976) "Portfolio Performance Evaluation and Long-run Capital Growth,” with Henry A. Latané in

Proceedings of the Eastern Finance Association (1973) Book reviews in Journal of Finance and Financial Review. Abstracts for CFA Digest. Articles in

Carolina Financial Times. S elected Papers and Presentations

“Economic Perspective on Water Marketing in Texas,” 2009 Water Law Institute, The University of Texas School of Law, Austin, TX (Dec. 2009).

“Estimating Utility Cost of Equity in Financial Turmoil,” SNL EXNET 15th Annual FERC Briefing, Washington, D.C. (Mar. 2009)

"The Who, What, When, How, and Why of Ethics," San Antonio Financial Analysts Society (Jan. 16, 2002). Similar presentation given to the Austin Society of Financial Analysts (Jan. 17, 2002)

“Ethics for Financial Analysts,” Sponsored by Canadian Council of Financial Analysts: delivered in Calgary, Edmonton, Regina, and Winnipeg, June 1997. Similar presentations given to Austin Society of Financial Analysts (Mar. 1994), San Antonio Society of Financial Analysts (Nov. 1985), and St. Louis Society of Financial Analysts (Feb. 1986)

“Cost of Capital for Multi-Divisional Corporations,” Financial Management Association, New Orleans, Louisiana (Oct. 1996)

"Ethics and the Treasury Function,” Government Treasurers Organization of Texas, Corpus Christi, Texas (Jun. 1996)

"A Cooperative Future,” Iowa Association of Electric Cooperatives, Des Moines (December 1995). Similar presentations given to National G & T Conference, Irving, Texas (June 1995), Kentucky Association of Electric Cooperatives Annual Meeting, Louisville (Nov. 1994), Virginia, Maryland, and Delaware Association of Electric Cooperatives Annual Meeting, Richmond (July 1994), and Carolina Electric Cooperatives Annual Meeting, Raleigh (Mar. 1994)

"Information Superhighway Warnings: Speed Bumps on Wall Street and Detours from the Economy,” Texas Society of Certified Public Accountants Natural Gas, Telecommunications and Electric Industries Conference, Austin (Apr. 1995)

"Economic/Wall Street Outlook,” Carolinas Council of the Institute of Management Accountants, Myrtle Beach, South Carolina (May 1994). Similar presentation given to Bell Operating Company Accounting Witness Conference, Santa Fe, New Mexico (Apr. 1993)

"Regulatory Developments in Telecommunications,” Regional Holding Company Financial and Accounting Conference, San Antonio (Sep. 1993)


110

“Estimating the Cost of Capital During the 1990s: Issues and Directions,” The National Society of Rate of Return Analysts, Washington, D.C. (May 1992)

“Making Utility Regulation Work at the Public Utility Commission of Texas,” Center for Legal and Regulatory Studies, University of Texas, Austin (June 1991)

"Can Regulation Compete for the Hearts and Minds of Industrial Customers,” Emerging Issues of Competition in the Electric Utility Industry Conference, Austin (May 1988)

"The Role of Utilities in Fostering New Energy Technologies,” Emerging Energy Technologies in Texas Conference, Austin (Mar. 1988)

"The Regulators’ Perspective,” Bellcore Economic Analysis Conference, San Antonio (Nov. 1987) "Public Utility Commissions and the Nuclear Plant Contractor,” Construction Litigation

Superconference, Laguna Beach, California (Dec. 1986) "Development of Cogeneration Policies in Texas,” University of Georgia Fifth Annual Public

Utilities Conference, Atlanta (Sep. 1985) "Wheeling for Power Sales,” Energy Bureau Cogeneration Conference, Houston (Nov. 1985). "Asymmetric Discounting of Information and Relative Liquidity: Some Empirical Evidence for

Common Stocks" (with John Groth and Kerry Cooper), Southern Finance Association, New Orleans (Nov. 1982)

“Used and Useful Planning Models,” Planning Executive Institute, 27th Corporate Planning Conference, Los Angeles (Nov. 1979)

"Staff Input to Commission Rate of Return Decisions,” The National Society of Rate of Return Analysts, New York (Oct. 1979)

""Discounted Cash Life: A New Measure of the Time Dimension in Capital Budgeting,” with David Cordell, Southern Finance Association, New Orleans (Nov. 1978)

“The Relative Value of Statistics of Ex Post Common Stock Distributions to Explain Variance,” with Charles G. Martin, Southern Finance Association, Atlanta (Nov. 1977)

“An ANOVA Representation of Common Stock Returns as a Framework for the Allocation of Portfolio Management Effort,” with Charles G. Martin, Financial Management Association, Montreal (Oct. 1976)

“A Growth-Optimal Portfolio Selection Model with Finite Horizon,” with Henry A. Latané, American Finance Association, San Francisco (Dec. 1974)

“An Optimal Approach to the Finance Decision,” with Henry A. Latané, Southern Finance Association, Atlanta (Nov. 1974)

“A Pragmatic Approach to the Capital Structure Decision Based on Long-Run Growth,” with Henry A. Latané, Financial Management Association, San Diego (Oct. 1974)

“Growth Rates, Expected Returns, and Variance in Portfolio Selection and Performance Evaluation,” with Henry A. Latané, Econometric Society, Oslo, Norway (Aug. 1973)


111

IBES (d

)Val

Li

REGIONAL PROXY GROUP

RISK MEASURES

(a)

(b)

S&P

Value

Industry Classification

neCredit

Safety

Financial

ue Line (b

)S&P (c)

Company

SYM

Rating

Rank

Strength

Beta

Sector

Sub‐Industry

Sector

Sub‐Industry

Sector

Sub‐Industry

1

Ameren Corp.

AEE

BBB‐

3B+

+0.80

Electric Ut ility

Central

Utilities

Multi‐Utilities

Utilities

Multiu

tilities

2

Dom

inion Re

sources

DA‐

2B+

+0.70

Electric Ut ilit y

East

Utilities

Multi‐Utilities

Utilities

Electricity

3

Duk

e En

ergy Corp.

DUK

A‐

2A

0.65

Electric Utility

East

Utilities

Electric Utilities

Utilities

Multiu

tilities

4

Entergy Corp.

ETR

BBB

2A

0.70

Electric Ut ilit y

Central

Utilities

Electric Utilities

Utilities

Electricity

5

FPL Group

FPL

A‐

1A+

0.75

Electric Utility

East

Utilities

Electric Utilities

Utilities

Electricity

6

Prog

ress Energy

PGN

BBB+

2B+

+0.65

Electric Utility

East

Utilities

Electric Utilities

Utilities

Electricity

7

SCANA Corp.

SCG

BBB+

2A

0.65

Electric Utility

East

Utilities

Multi‐Utilities

Utilities

Multiu

tilities

8

Southern Co.

SOA

1A

0.55

Electric Ut ilit y

East

Utilities

Electric Utilities

Utilities

Electricity

9

TECO Energy

TEBB

B3

B0.85

Electric Utility

East

Utilities

Multi‐Utilities

Utilities

Electricity

Average

BBB+

2B++

0.70

(a)

www.stand

arda

ndpo

ors.com (retrieved Apr. 9, 2009).

(b)

The Value Line Investment S

urvey (Feb. 26 & M

ar. 26, 2010).

(c)

Stan

dard and Poorʹs Corpo

ratio

n, Stock Report (retrieved from w

ww.fide

lity.com Apr. 9, 2010).

(d)Thompson Reuters Company in Context Report (A

pr. 8, 2010).


112

IBES (d

)Val

Li

RATINGS SCREEN PROXY GROUP

RISK MEASURES

(a)

(b)

S&P

Value

Industry Classification

neCredit

Safety

Financial

ue Line (b

)S&P (c)

Company

SYM

Rating

Rank

Strength

Beta

Sector

Sub‐Industry

Sector

Sub‐Industry

Sector

Sub‐Industry

1

Ameren Corp.

AEE

BBB‐

3B+

+0.80

Electric Ut ility

Central

Utilities

Multi‐Utilities

Utilities

Multiu

tilities

2

Entergy Corp.

ETR

BBB

2A

0.70

Electric Ut ilit y

Central

Utilities

Electric Utilities

Utilities

Electricity

3

Prog

ress Energy

PGN

BBB+

2B+

+0.65

Electric Utility

East

Utilities

Electric Utilities

Utilities

Electricity

4

SCANA Corp.

SCG

BBB+

2A

0.65

Electric Utility

East

Utilities

Multi‐Utilities

Utilities

Multiu

tilities

5

TECO Energy

TEBB

B3

B0.85

Electric Utility

East

Utilities

Multi‐Utilities

Utilities

Electricity

Average

BBB

2B++

0.73

(a)

www.stand

arda

ndpo

ors.com (retrieved Apr. 9, 2009).

(b)


urvey (Feb. 26 & M

ar. 26, 2010).

(c)

Stan

dard and Poorʹs Corpo

ratio

n, Stock Report (retrieved from w

ww.fide

lity.com Apr. 9, 2010).

(d)Thompson Reuters Company in Context Report (A

pr. 8, 2010).


113


FERC DCF MODEL

(a)

(b)

(c)

(d)

(e)

(f)


Company

Low

High

Low

High

br + sv

IBES

Low

High

1 A

meren Corp.

5.7%

6.2%

5.8%

6.3%

3.2%

3.0%

8.8%

‐‐9.5%

2 D

ominion Resou

rces

4.6%

5.0%

4.7%

5.2%

7.8%

4.2%

8.9%

‐‐12.9%

3 D

uke En

ergy Corp.

5.7%

6.0%

5.7%

6.1%

2.1%

4.3%

7.9%

‐‐10.4%

4 E

ntergy Corp.

3.7%

3.9%

3.8%

4.1%

7.3%

7.0%

10.8%

‐‐11.3%

5 F

PL Group

3.7%

4.0%

3.8%

4.2%

7.0%

7.3%

10.8%

‐‐11.5%

6 P

rogress En

ergy

6.2%

6.6%

6.2%

6.7%

2.0%

3.7%

8.2%

‐‐10.4%

7 S

CANA Corp.

5.1%

5.4%

5.2%

5.6%

5.0%

5.3%

10.2%

‐‐10.9%

8 S

outhern Co.

5.2%

5.6%

5.4%

5.7%

4.9%

4.8%

10.2%

‐‐10.6%

9 T

ECO Energy

5.0%

5.5%

5.2%

5.7%

5.2%

7.9%

10.3%

‐‐13.6%

Range of Reasonableness

7.9%

‐‐13.6%

Adjusted Range of Reasonableness (g)

8.2%

‐‐13.6%

Midpoint

Median (h)

(a)

(b)

Six‐mon

th dividend yield ad

justed fo

r one‐half y

earsʹ growth.

(c)

Exhibit T

EC‐205.

(d)

Long‐te

rm IB

ES growth fo

recast from Thompson Reuters Company in Context Report (A

pr. 8, 2010).

(e)

Sum of low growth ra

te and correspon

ding adjusted divide

nd yield.

(f)Su

m of h

igh grow

th ra

te and correspon


nd yield.

(g)

Exclud

es highlighted values.

(h)

Equa

l to the med

ian of th

e average of th

e low and high DCF estim

ates fo

r all compa

nies with tw

o valid observatio

ns.

Six‐mon

th average dividend yield for O

ctob

er 2009 ‐ M

arch 2010.

6 Mo.Div. Yield

Adjusted Div. Yield

Growth Rates

10.7%

10.9%


114


BR + SV GROWTH RATE

(a)

(a)

(b)

(a)

(a)

(a)

(a)

(a)

(a)

(a)

(a)

(a)

Company

High

Low

Avg.

2010

2011

2013‐15

2010

2011

2013‐15

2010

2011

2013‐15

1

Ameren Corp.

$45.00

$35.00

$40.00

$2.50

$2.60

$3.00

$1.54

$1.58

$1.70

7.5%

7.5%

8.0%

2

Dom

inion Re

sources

$60.00

$45.00

$52.50

$3.30

$3.40

$4.00

$1.83

$1.91

$2.15

16.5%

15.5%

14.5%

3

Duk

e En

ergy Corp.

$25.00

$18.00

$21.50

$1.30

$1.35

$1.50

$0.97

$0.99

$1.10

7.5%

8.0%

8.0%

4

Entergy Corp.

$125.00

$95.00

$110.00

$6.75

$7.15

$8.00

$3.00

$3.00

$3.60

14.5%

14.0%

12.5%

5

FPL Group

$80.00

$60.00

$70.00

$4.25

$4.30

$4.75

$2.00

$2.10

$2.40

12.5%

12.0%

11.5%

6

Prog

ress Energy

$50.00

$35.00

$42.50

$3.00

$3.15

$3.55

$2.50

$2.52

$2.58

8.5%

9.0%

9.0%

7

SCANA Corp.

$50.00

$40.00

$45.00

$2.95

$3.05

$3.50

$1.90

$1.92

$2.05

10.0%

10.0%

10.0%

8

Southern Co.

$45.00

$40.00

$42.50

$2.35

$2.50

$3.00

$1.79

$1.85

$2.10

12.5%

12.5%

13.0%

9

TECO Energy

$25.00

$16.00

$20.50

$1.20

$1.35

$1.60

$0.80

$0.82

$0.95

12.0%

13.0%

12.5%

2013‐15 Market Price

Earnings Per Share

Dividends Per Share

Return on Equity (ʺrʺ)


115


BR + SV GROWTH RATE

(c)

(c)

(c)

(d)

(d)

(a)

(a)

(e)

(a)

(a)

(e)

(f)(g)

(h)

Total

EquityCommon

Total

EquityCommon

Chg in

Adj.

Adj.

Company

2010

2011

2013‐15

br

Capital

Ratio

Equity

Capital

Ratio

Equity

Equity

Factor

r

1

Ameren Corp.

38.4%

39.2%

43.3%

40.3%

7.7%

$15,991

49.1%

$7,852

$18,500

52.5%

$9,713

4.3%

1.0213

7.8%

2

Dom

inion Re

sources

44.5%

43.8%

46.3%

44.9%

15.5%

$26,976

41.7%

$11,249

$38,100

45.5%

$17,336

9.0%

1.0432

16.2%

3

Duk

e En

ergy Corp.

25.4%

26.7%

26.7%

26.2%

7.8%

$37,999

57.6%

$21,887

$49,000

51.0%

$24,990

2.7%

1.0133

7.9%

4

Entergy Corp.

55.6%

58.0%

55.0%

56.2%

13.7%

$19,985

43.1%

$8,614

$26,700

44.5%

$11,882

6.6%

1.0322

14.1%

5

FPL Group

52.9%

51.2%

49.5%

51.2%

12.0%

$29,272

44.3%

$12,967

$43,800

43.0%

$18,834

7.8%

1.0373

12.4%

6

Prog

ress Energy

16.7%

20.0%

27.3%

21.3%

8.8%

$20,530

46.0%

$9,444

$23,700

47.5%

$11,258

3.6%

1.0176

9.0%

7

SCANA Corp.

35.6%

37.0%

41.4%

38.0%

10.0%

$7,891

43.2%

$3,409

$11,125

46.5%

$5,173

8.7%

1.0417

10.4%

8

Southern Co.

23.8%

26.0%

30.0%

26.6%

12.7%

$34,225

43.5%

$14,888

$46,000

44.5%

$20,470

6.6%

1.0318

13.1%

9

TECO Energy

33.3%

39.3%

40.6%

37.7%

12.5%

$5,287

39.4%

$2,083

$6,375

43.5%

$2,773

5.9%

1.0286

12.9%

2009

2013‐15

Retention Ratio ʺbʺ

Average

Adjusted ʺrʺ


116


BR + SV GROWTH RATE

(a)

(a)

(f)(a)

(i)(j)

(k)

(l)(m

)

2013‐15

M/B

Average

Company

2009

2013‐15Change

BVPS

Ratio

sv

svbr + sv

1

Ameren Corp.

238.00

255.00

1.39%

$38.25

1.05

0.0145

0.0438

0.06%

3.2%

2

Dom

inion Re

sources

598.00

616.00

0.59%

$28.00

1.88

0.0112

0.4667

0.52%

7.8%

3

Duk

e En

ergy Corp.

1309.00

1335.00

0.39%

$18.75

1.15

0.0045

0.1279

0.06%

2.1%

4

Entergy Corp.

189.12

180.00

‐0.98%

$65.75

1.67

(0.0165)

0.4023

‐0.66%

7.3%

5

FPL Group

408.92

432.00

1.10%

$43.50

1.61

0.0178

0.3786

0.67%

7.0%

6

Prog

ress Energy

280.00

290.00

0.70%

$38.95

1.09

0.0077

0.0835

0.06%

2.0%

7

SCANA Corp.

124.00

148.00

3.60%

$34.75

1.29

0.0466

0.2278

1.06%

5.0%

8

Southern Co.

820.00

890.00

1.65%

$23.00

1.85

0.0305

0.4588

1.40%

4.9%

9

TECO Energy

213.90

219.00

0.47%

$12.50

1.64

0.0077

0.3902

0.30%

5.2%

(a)


urvey (Feb. 26 & M

ar. 26, 2010).

(b)

Average of H

igh an

d Lo

w exp

ected market p

rices.

(c)

Com

puted at (E

PS ‐ DPS

) / EPS

.(d)

Average of v

alues for 2

010, 2011, and 2013‐15.

(e)

Prod

uct o

f total cap

ital and equ

ity ra

tio.

(f)Five‐year rate of cha

nge.

(g)

Com

puted using the form

ula 2*(1+5‐Yr. Cha

nge in Equ

ity)/(2+5 Yr. C

hang

e in Equ

ity).

(h)

Prod

uct o

f average year‐end ʺrʺ for 2010, 2011, and 2013‐15 and Adjustm

ent F

actor.

(i)Average of H

igh an

d Lo

w exp

ected market p

rices divide

d by 2013‐15 BVPS

.(j)

Prod

uct o

f cha

nge in com

mon sha

res ou

tstand

ing an

d M/B Ratio.

(k)

Com

puted as 1 ‐ B/M Ratio.

(l)Prod

uct o

f ʺsʺ and ʺvʺ.

(m)Prod

uct o

f average ʺbʺ a

nd adjusted ʺrʺ, plus ʺsvʺ.

ʺsvʺ Factor

Outstanding

Common Shares


117


FERC DCF MODEL

(a)

(b)

(c)

(d)

(e)

(f)


Company

Low

High

Low

High

br + sv

IBES

Low

High

1

Ameren Corp.

5.7%

6.2%

5.8%

6.3%

3.2%

3.0%

8.8%

‐‐9.5%

2

Entergy Corp.

3.7%

3.9%

3.8%

4.1%

7.3%

7.0%

10.8%

‐‐11.3%

3

Prog

ress Energy

6.2%

6.6%

6.2%

6.7%

2.0%

3.7%

8.2%

‐‐10.4%

4

SCANA Corp.

5.1%

5.4%

5.2%

5.6%

5.0%

5.3%

10.2%

‐‐10.9%

5

TECO Energy

5.0%

5.5%

5.2%

5.7%

5.2%

7.9%

10.3%

‐‐13.6%


8.2%

‐‐13.6%

Midpoint

Median (g)

(a)

(b)

Six‐mon

th dividend yield ad

justed fo

r one‐half y

earsʹ growth.

(c)

Exhibit T

EC‐205.

(d)

Long‐te

rm IB

ES growth fo

recast from Thompson Reuters Company in Context Report (A

pr. 8, 2010).

(e)

Sum of low growth ra

te and correspon


nd yield.

(f)Su

m of h

igh grow

th ra

te and correspon


nd yield.

(g)

Equa

l to the med

ian of th

e average of th

e low and high DCF estim

ates fo

r all compa

nies with tw

o valid observatio

ns.

Six‐mon

th average dividend yield for O

ctob

er 2009 ‐ M

arch 2010.

6 Mo.Div. Yield

Adjusted Div. Yield

Growth Rates

10.5%

10.9%


118

DCF MODEL

NON‐UTILITY PROXY GROUP

(a) (b) (d) (e) (e)

DividendCompany Yield IBES br+sv Low High

1 3M Company 2.53% 11.4% 15.8% 13.9% ‐‐ 18.4%2 Abbott Labs. 3.37% 11.5% 15.1% 14.9% ‐‐ 18.5%3 Alberto‐Culver 1.31% 12.5% 8.1% 9.4% ‐‐ 13.8%4 Allergan, Inc. 0.32% 13.6% 16.1% 13.9% ‐‐ 16.4%5 Automatic Data Proc. 3.10% 10.9% 10.9% 14.0% ‐‐ 14.0%6 Bard (C.R.) 0.81% 11.5% 15.5% 12.3% ‐‐ 16.4%7 Baxter Intʹl Inc. 2.08% 11.8% 15.7% 13.9% ‐‐ 17.7%8 Becton, Dickinson 1.88% 11.2% 13.2% 13.1% ‐‐ 15.1%9 Bemis Co. 3.15% 7.0% 9.9% 10.2% ‐‐ 13.0%10 Bristol‐Myers Squibb 4.89% 2.4% 4.3% 7.3% ‐‐ 9.2%11 Brown‐Forman ʹBʹ 2.05% 8.6% 13.2% 10.7% ‐‐ 15.2%12 Chevron Corp. 3.50% 16.2% 17.7% 19.7% ‐‐ 21.2%13 Chubb Corp. 2.86% 9.2% 9.3% 12.1% ‐‐ 12.1%14 Coca‐Cola 3.27% 8.5% 11.9% 11.8% ‐‐ 15.1%15 Colgate‐Palmolive 2.51% 9.0% 15.7% 11.5% ‐‐ 18.2%16 Commerce Bancshs. 2.28% 6.7% 8.3% 9.0% ‐‐ 10.5%17 ConAgra Foods 3.18% 9.9% 6.5% 9.7% ‐‐ 13.1%

Growth Rates Implied Cost of Equity

17 ConAgra Foods 3.18% 9.9% 6.5% 9.7% ‐‐ 13.1%18 Costco Wholesale 1.18% 13.7% 9.8% 10.9% ‐‐ 14.9%19 CVS Caremark Corp. 0.96% 11.8% 8.2% 9.2% ‐‐ 12.8%20 Ecolab Inc. 1.42% 13.0% 22.7% 14.4% ‐‐ 24.1%21 Everest Re Group Ltd. 2.36% 10.0% 9.2% 11.6% ‐‐ 12.4%22 Exxon Mobil Corp. 2.51% 16.1% 14.8% 17.3% ‐‐ 18.6%23 Genʹl Dynamics 2.19% 7.8% 12.0% 10.0% ‐‐ 14.2%24 Genʹl Mills 2.79% 8.1% 7.8% 10.5% ‐‐ 10.9%25 Genuine Parts 3.82% 7.3% 7.2% 11.0% ‐‐ 11.1%26 Grainger (W.W.) 1.75% 13.0% 8.7% 10.4% ‐‐ 14.8%27 Heinz (H.J.) 3.88% 6.5% 16.7% 10.4% ‐‐ 20.6%28 Home Depot 2.88% 12.2% 8.5% 11.3% ‐‐ 15.1%29 Hormel Foods 2.02% 8.0% 10.2% 10.0% ‐‐ 12.2%30 Illinois Tool Works 2.63% 15.4% 11.4% 14.1% ‐‐ 18.0%31 Intʹl Business Mach. 1.88% 8.9% 17.3% 10.8% ‐‐ 19.1%32 Johnson & Johnson 3.16% 6.9% 9.1% 10.1% ‐‐ 12.2%33 Kellogg 2.91% 10.3% 15.8% 13.2% ‐‐ 18.7%34 Kimberly‐Clark 4.31% 9.0% 17.2% 13.3% ‐‐ 21.5%


119

DCF MODEL


(a) (b) (d) (e) (e)

DividendCompany Yield IBES br+sv Low High

35 Kraft Foods 3.85% 7.5% 4.7% 8.6% ‐‐ 11.4%36 Lilly (Eli) 5.37% ‐1.1% 8.4% 4.3% ‐‐ 13.8%37 Lockheed Martin 3.16% 8.9% NMF 12.1% ‐‐ 12.1%38 McCormick & Co. 2.73% 8.4% 13.5% 11.1% ‐‐ 16.2%39 McDonaldʹs Corp. 3.27% 10.0% 9.6% 12.9% ‐‐ 13.3%40 McKesson Corp. 0.72% 11.5% 12.2% 12.2% ‐‐ 12.9%41 Medtronic, Inc. 1.87% 10.3% 12.9% 12.2% ‐‐ 14.7%42 Microsoft Corp. 1.74% 11.3% 12.4% 13.0% ‐‐ 14.1%43 NIKE, Inc. ʹBʹ 1.46% 12.3% 13.4% 13.8% ‐‐ 14.9%44 Northrop Grumman 2.73% 11.0% 7.2% 10.0% ‐‐ 13.7%45 Oracle Corp. 0.77% 14.6% 16.5% 15.4% ‐‐ 17.3%46 PepsiCo, Inc. 2.91% 7.6% 14.7% 10.5% ‐‐ 17.6%47 Pfizer, Inc. 4.43% 1.7% 6.1% 6.1% ‐‐ 10.5%48 Procter & Gamble 2.81% 9.3% 12.5% 12.1% ‐‐ 15.3%49 Raytheon Co. 2.64% 8.7% 8.9% 11.3% ‐‐ 11.6%50 Sigma‐Aldrich 1.17% 9.5% 14.3% 10.7% ‐‐ 15.5%51 Stryker Corp. 1.05% 12.1% 12.4% 13.2% ‐‐ 13.4%

Growth Rates Implied Cost of Equity

51 Stryker Corp. 1.05% 12.1% 12.4% 13.2% ‐‐ 13.4%52 Sysco Corp. 3.42% 15.0% 12.8% 16.2% ‐‐ 18.4%53 TJX Companies 1.34% 12.3% 16.3% 13.6% ‐‐ 17.6%54 United Parcel Serv. 2.93% 8.2% 15.0% 11.1% ‐‐ 17.9%55 United Technologies 2.31% 10.7% 14.2% 13.0% ‐‐ 16.5%56 Verizon Communic. 6.30% 4.9% 5.0% 11.2% ‐‐ 11.3%57 Wal‐Mart Stores 2.19% 10.8% 8.2% 10.4% ‐‐ 13.0%58 Walgreen Co. 1.49% 14.3% 10.2% 11.7% ‐‐ 15.8%59 Waste Management 3.64% 7.8% 6.9% 10.5% ‐‐ 11.4%

Range of Reasonableness 4.3% ‐‐ 24.1%

Adjusted Range of Reasonableness (f) 8.6% ‐‐ 16.5% Midpoint Median

(a) www.valueline.com (retrieved Apr. 16, 2010).(b) Thomson Reuters, Company in Context Report (Apr. 15, 2010).(c) www.zacks.com (retrieved Apr. 16, 2010).(d) See Exhibit TEC‐208.(e) Sum of dividend yield and respective growth rate.(f) Excludes highlighted figures.

12.5%12.6%


120

BR + SV GROWTH RATE


(a) (a) (b) (a) (a) (a) (c) (a)

2013‐15 Market Price 2013‐15 ProjectionsCompany High Low Avg. EPS DPS BVPS b r

1 3M Company $120.00 $100.00 $110.00 $6.90 $2.26 $29.35 67.2% 23.5%2 Abbott Labs. $115.00 $95.00 $105.00 $5.70 $2.18 $22.05 61.8% 26.0%3 Alberto‐Culver $50.00 $40.00 $45.00 $2.25 $0.50 $17.95 77.8% 12.5%4 Allergan, Inc. $120.00 $100.00 $110.00 $5.50 $0.25 $36.05 95.5% 15.5%5 Automatic Data Proc. $85.00 $70.00 $77.50 $3.30 $1.60 $20.75 51.5% 16.0%6 Bard (C.R.) $155.00 $125.00 $140.00 $7.80 $0.86 $39.25 89.0% 20.0%7 Baxter Intʹl Inc. $110.00 $90.00 $100.00 $6.75 $1.75 $26.55 74.1% 25.5%8 Becton, Dickinson $135.00 $110.00 $122.50 $7.70 $2.20 $38.90 71.4% 20.5%9 Bemis Co. $65.00 $55.00 $60.00 $3.50 $1.04 $25.60 70.3% 13.5%10 Bristol‐Myers Squibb $40.00 $30.00 $35.00 $2.05 $1.40 $11.65 31.7% 17.5%11 Brown‐Forman ʹBʹ $80.00 $65.00 $72.50 $4.25 $1.40 $20.00 67.1% 21.5%12 Chevron Corp. $145.00 $115.00 $130.00 $13.00 $3.00 $53.15 76.9% 24.0%13 Chubb Corp. $85.00 $75.00 $80.00 $7.00 $1.60 $57.85 77.1% 12.0%14 Coca‐Cola $90.00 $75.00 $82.50 $3.90 $2.00 $17.15 48.7% 23.0%15 Colgate‐Palmolive $165.00 $135.00 $150.00 $7.50 $3.20 $18.25 57.3% 41.0%16 Commerce Bancshs. $50.00 $40.00 $45.00 $3.60 $1.20 $32.80 66.7% 11.0%17 ConAgra Foods $40.00 $35.00 $37.50 $2.30 $0.90 $15.20 60.9% 15.5%18 Costco Wholesale $90.00 $70.00 $80.00 $4.00 $0.80 $29.95 80.0% 13.5%19 CVS Caremark Corp. $75.00 $60.00 $67.50 $4.00 $0.55 $39.20 86.3% 10.5%20 Ecolab Inc. $65.00 $55.00 $60.00 $3.50 $0.85 $13.90 75.7% 25.5%21 Everest Re Group Ltd. $165.00 $135.00 $150.00 $15.00 $2.35 $141.65 84.3% 10.5%22 Exxon Mobil Corp. $125.00 $100.00 $112.50 $9.35 $1.90 $45.25 79.7% 21.0%23 Genʹl Dynamics $155.00 $125.00 $140.00 $10.00 $2.60 $57.00 74.0% 18.0%24 Genʹl Mills $110.00 $90.00 $100.00 $5.75 $2.50 $22.70 56.5% 27.5%25 Genuine Parts $65.00 $50.00 $57.50 $3.80 $1.98 $23.85 47.9% 16.0%26 Grainger (W.W.) $165.00 $135.00 $150.00 $9.35 $2.37 $52.40 74.7% 18.5%27 Heinz (H.J.) $75.00 $60.00 $67.50 $4.00 $2.20 $10.95 45.0% 37.0%28 Home Depot $50.00 $40.00 $45.00 $2.75 $1.10 $17.00 60.0% 16.0%29 Hormel Foods $75.00 $60.00 $67.50 $3.80 $1.20 $23.85 68.4% 16.0%30 Illinois Tool Works $75.00 $65.00 $70.00 $4.65 $1.36 $27.15 70.8% 17.5%31 Intʹl Business Mach. $220.00 $180.00 $200.00 $14.25 $3.15 $52.15 77.9% 28.5%32 Johnson & Johnson $125.00 $100.00 $112.50 $7.10 $2.70 $36.00 62.0% 20.0%33 Kellogg $90.00 $75.00 $82.50 $4.80 $1.85 $13.40 61.5% 36.0%34 Kimberly‐Clark $100.00 $80.00 $90.00 $6.00 $2.75 $15.55 54.2% 38.5%35 Kraft Foods $50.00 $40.00 $45.00 $2.75 $1.40 $26.20 49.1% 10.5%36 Lilly (Eli) $50.00 $45.00 $47.50 $3.40 $2.20 $15.60 35.3% 22.0%37 Lockheed Martin $220.00 $180.00 $200.00 $13.25 $3.50 $35.15 73.6% NMF38 McCormick & Co. $70.00 $55.00 $62.50 $3.15 $1.28 $17.40 59.4% 18.0%39 McDonaldʹs Corp. $105.00 $85.00 $95.00 $5.85 $3.00 $19.00 48.7% 30.5%40 McKesson Corp. $95.00 $80.00 $87.50 $6.55 $0.48 $48.70 92.7% 13.5%41 Medtronic, Inc. $80.00 $65.00 $72.50 $4.90 $1.04 $24.50 78.8% 20.0%42 Microsoft Corp. $45.00 $40.00 $42.50 $2.65 $0.70 $8.70 73.6% 31.5%43 NIKE, Inc. ʹBʹ $105.00 $85.00 $95.00 $5.30 $1.30 $31.45 75.5% 17.0%44 Northrop Grumman $155.00 $125.00 $140.00 $10.00 $2.50 $64.80 75.0% 15.5%45 Oracle Corp. $40.00 $35.00 $37.50 $2.40 $0.30 $11.80 87.5% 21.0%46 PepsiCo, Inc. $115.00 $95.00 $105.00 $5.15 $2.10 $19.40 59.2% 27.5%47 Pfizer, Inc. $30.00 $25.00 $27.50 $2.05 $1.16 $15.50 43.4% 13.5%48 Procter & Gamble $105.00 $85.00 $95.00 $5.25 $1.95 $26.00 62.9% 20.0%49 Raytheon Co. $115.00 $95.00 $105.00 $7.00 $1.80 $41.50 74.3% 17.5%50 Sigma‐Aldrich $85.00 $65.00 $75.00 $3.95 $0.80 $22.30 79.7% 18.0%51 Stryker Corp. $125.00 $100.00 $112.50 $5.15 $0.80 $34.05 84.5% 15.0%52 Sysco Corp. $45.00 $40.00 $42.50 $2.50 $1.20 $7.45 52.0% 33.5%53 TJX Companies $75.00 $60.00 $67.50 $4.15 $0.75 $10.80 81.9% 42.0%54 United Parcel Serv. $110.00 $90.00 $100.00 $4.55 $2.40 $14.30 47.3% 32.0%55 United Technologies $120.00 $95.00 $107.50 $6.75 $2.26 $28.35 66.5% 24.0%56 Verizon Communic. $60.00 $50.00 $55.00 $3.05 $1.96 $18.95 35.7% 14.5%57 Wal‐Mart Stores $95.00 $75.00 $85.00 $5.45 $1.55 $30.90 71.6% 17.5%58 Walgreen Co. $65.00 $55.00 $60.00 $3.40 $0.84 $24.20 75.3% 14.0%59 Waste Management $50.00 $40.00 $45.00 $3.05 $1.60 $17.65 47.5% 17.0%


121

BR + SV GROWTH RATE


(a) (a) (d) (a) (a) (d) (e) (f) (g)2009 2013‐15 Adjusted ʺrʺNo. Common No. Common Chg in Adj. Adj.

Company BVPS Shares Equity BVPS Shares Equity Equity Factor r

1 3M Company $14.24 693.54 $9,876 $29.35 680.00 $19,958 15.1% 1.0702 25.2%2 Abbott Labs. $14.73 1551.20 $22,849 $22.05 1520.00 $33,516 8.0% 1.0383 27.0%3 Alberto‐Culver $12.18 98.26 $1,197 $17.95 92.00 $1,651 6.7% 1.0322 12.9%4 Allergan, Inc. $15.84 304.43 $4,822 $36.05 305.00 $10,995 17.9% 1.0822 16.8%5 Automatic Data Proc. $10.63 500.90 $5,325 $20.75 520.00 $10,790 15.2% 1.0705 17.1%6 Bard (C.R.) $19.30 96.20 $1,857 $39.25 90.00 $3,533 13.7% 1.0642 21.3%7 Baxter Intʹl Inc. $11.55 593.00 $6,849 $26.55 545.00 $14,470 16.1% 1.0747 27.4%8 Becton, Dickinson $21.69 237.08 $5,142 $38.90 225.00 $8,753 11.2% 1.0531 21.6%9 Bemis Co. $16.55 109.01 $1,804 $25.60 109.00 $2,790 9.1% 1.0436 14.1%10 Bristol‐Myers Squibb $8.65 1709.50 $14,787 $11.65 1650.00 $19,223 5.4% 1.0262 18.0%11 Brown‐Forman ʹBʹ $12.60 145.00 $1,827 $20.00 140.00 $2,800 8.9% 1.0427 22.4%12 Chevron Corp. $45.57 2017.20 $91,924 $53.15 1950.00 $103,643 2.4% 1.0120 24.3%13 Chubb Corp. $47.10 332.00 $15,637 $57.85 325.00 $18,801 3.8% 1.0184 12.2%14 Coca‐Cola $8.85 2312.00 $20,461 $17.15 2310.00 $39,617 14.1% 1.0660 24.5%15 Colgate‐Palmolive $5.96 494.17 $2,945 $18.25 460.00 $8,395 23.3% 1.1044 45.3%16 Commerce Bancshs. $22.72 83.11 $1,888 $32.80 90.00 $2,952 9.3% 1.0447 11.5%17 ConAgra Foods $11.02 484.37 $5,338 $15.20 435.00 $6,612 4.4% 1.0214 15.8%18 Costco Wholesale $21.25 432.51 $9,191 $29.95 415.00 $12,429 6.2% 1.0302 13.9%19 CVS Caremark Corp. $25.71 1391.00 $35,763 $39.20 1285.00 $50,372 7.1% 1.0342 10.9%20 Ecolab Inc. $8.45 236.50 $1,998 $13.90 245.00 $3,406 11.2% 1.0533 26.9%21 Everest Re Group Ltd. $75.62 65.60 $4,961 $141.65 60.00 $8,499 11.4% 1.0538 11.1%22 Exxon Mobil Corp. $24.41 4727.00 $115,386 $45.25 4300.00 $194,575 11.0% 1.0522 22.1%23 Genʹl Dynamics $32.21 385.71 $12,424 $57.00 360.00 $20,520 10.6% 1.0501 18.9%24 Genʹl Mills $18.42 337.50 $6,217 $22.70 300.00 $6,810 1.8% 1.0091 27.8%25 Genuine Parts $16.49 158.92 $2,621 $23.85 155.00 $3,697 7.1% 1.0344 16.6%26 Grainger (W.W.) $30.92 72.28 $2,235 $52.40 62.00 $3,249 7.8% 1.0374 19.2%27 Heinz (H.J.) $3.87 315.04 $1,219 $10.95 310.00 $3,395 22.7% 1.1020 40.8%28 Home Depot $11.40 1700.00 $19,380 $17.00 1625.00 $27,625 7.3% 1.0354 16.6%29 Hormel Foods $14.92 134.52 $2,007 $23.85 130.00 $3,101 9.1% 1.0435 16.7%30 Illinois Tool Works $17.55 502.34 $8,816 $27.15 480.00 $13,032 8.1% 1.0391 18.2%31 Intʹl Business Mach. $17.43 1305.30 $22,751 $52.15 1150.00 $59,973 21.4% 1.0966 31.3%32 Johnson & Johnson $18.50 2750.00 $50,875 $36.00 2500.00 $90,000 12.1% 1.0570 21.1%33 Kellogg $3.79 381.86 $1,447 $13.40 350.00 $4,690 26.5% 1.1170 40.2%34 Kimberly‐Clark $12.96 417.00 $5,404 $15.55 400.00 $6,220 2.9% 1.0141 39.0%35 Kraft Foods $15.11 1469.30 $22,201 $26.20 1400.00 $36,680 10.6% 1.0502 11.0%36 Lilly (Eli) $8.28 1149.90 $9,521 $15.60 1155.00 $18,018 13.6% 1.0637 23.4%37 Lockheed Martin $11.07 372.90 $4,128 $35.15 320.00 $11,248 22.2% 1.0999 NMF38 McCormick & Co. $8.11 130.10 $1,055 $17.40 135.00 $2,349 17.4% 1.0799 19.4%39 McDonaldʹs Corp. $12.35 1075.00 $13,276 $19.00 1000.00 $19,000 7.4% 1.0358 31.6%40 McKesson Corp. $26.40 266.00 $7,022 $48.70 250.00 $12,175 11.6% 1.0550 14.2%41 Medtronic, Inc. $13.20 1100.00 $14,520 $24.50 1000.00 $24,500 11.0% 1.0523 21.0%42 Microsoft Corp. $3.97 9151.00 $36,329 $8.70 7800.00 $67,860 13.3% 1.0624 33.5%43 NIKE, Inc. ʹBʹ $15.93 491.10 $7,823 $31.45 487.50 $15,332 14.4% 1.0672 18.1%44 Northrop Grumman $41.34 306.87 $12,686 $64.80 250.00 $16,200 5.0% 1.0244 15.9%45 Oracle Corp. $4.47 5150.00 $23,021 $11.80 4750.00 $56,050 19.5% 1.0888 22.9%46 PepsiCo, Inc. $7.77 1553.00 $12,067 $19.40 1500.00 $29,100 19.3% 1.0878 29.9%47 Pfizer, Inc. $11.15 8070.00 $89,981 $15.50 8070.00 $125,085 6.8% 1.0329 13.9%48 Procter & Gamble $21.18 2917.00 $61,782 $26.00 2900.00 $75,400 4.1% 1.0199 20.4%49 Raytheon Co. $25.64 383.20 $9,825 $41.50 330.00 $13,695 6.9% 1.0332 18.1%50 Sigma‐Aldrich $13.83 121.88 $1,686 $22.30 120.00 $2,676 9.7% 1.0462 18.8%51 Stryker Corp. $15.90 397.40 $6,319 $34.05 387.00 $13,177 15.8% 1.0734 16.1%52 Sysco Corp. $5.67 601.23 $3,409 $7.45 570.00 $4,247 4.5% 1.0220 34.2%53 TJX Companies $5.17 412.82 $2,134 $10.80 340.00 $3,672 11.5% 1.0542 44.3%54 United Parcel Serv. $7.05 1000.00 $7,050 $14.30 990.00 $14,157 15.0% 1.0696 34.2%55 United Technologies $16.89 942.29 $15,915 $28.35 900.00 $25,515 9.9% 1.0472 25.1%56 Verizon Communic. $18.10 2835.70 $51,326 $18.95 2820.00 $53,439 0.8% 1.0040 14.6%57 Wal‐Mart Stores $16.63 3925.00 $65,273 $30.90 3400.00 $105,060 10.0% 1.0476 18.3%58 Walgreen Co. $14.54 988.56 $14,374 $24.20 960.00 $23,232 10.1% 1.0480 14.7%59 Waste Management $13.56 486.12 $6,592 $17.65 465.00 $8,207 4.5% 1.0219 17.4%


122

BR + SV GROWTH RATE


(a) (a) (e) (h) (i) (j) (k) (l)Common SharesOutstanding M/B ʺsvʺ Factor

Company 2009 2013‐15 Change Ratio s v sv br + sv

1 3M Company 693.54 680.00 ‐0.39% 3.75 (0.0147) 0.7332 ‐1.08% 15.8%2 Abbott Labs. 1551.20 1520.00 ‐0.41% 4.76 (0.0193) 0.7900 ‐1.53% 15.1%3 Alberto‐Culver 98.26 92.00 ‐1.31% 2.51 (0.0328) 0.6011 ‐1.97% 8.1%4 Allergan, Inc. 304.43 305.00 0.04% 3.05 0.0011 0.6723 0.08% 16.1%5 Automatic Data Proc. 500.90 520.00 0.75% 3.73 0.0281 0.7323 2.05% 10.9%6 Bard (C.R.) 96.20 90.00 ‐1.32% 3.57 (0.0472) 0.7196 ‐3.40% 15.5%7 Baxter Intʹl Inc. 593.00 545.00 ‐1.67% 3.77 (0.0631) 0.7345 ‐4.63% 15.7%8 Becton, Dickinson 237.08 225.00 ‐1.04% 3.15 (0.0328) 0.6824 ‐2.24% 13.2%9 Bemis Co. 109.01 109.00 0.00% 2.34 (0.0000) 0.5733 0.00% 9.9%10 Bristol‐Myers Squibb 1709.50 1650.00 ‐0.71% 3.00 (0.0212) 0.6671 ‐1.42% 4.3%11 Brown‐Forman ʹBʹ 145.00 140.00 ‐0.70% 3.63 (0.0254) 0.7241 ‐1.84% 13.2%12 Chevron Corp. 2017.20 1950.00 ‐0.68% 2.45 (0.0165) 0.5912 ‐0.98% 17.7%13 Chubb Corp. 332.00 325.00 ‐0.43% 1.38 (0.0059) 0.2769 ‐0.16% 9.3%14 Coca‐Cola 2312.00 2310.00 ‐0.02% 4.81 (0.0008) 0.7921 ‐0.07% 11.9%15 Colgate‐Palmolive 494.17 460.00 ‐1.42% 8.22 (0.1169) 0.8783 ‐10.27% 15.7%16 Commerce Bancshs. 83.11 90.00 1.61% 1.37 0.0220 0.2711 0.60% 8.3%17 ConAgra Foods 484.37 435.00 ‐2.13% 2.47 (0.0525) 0.5947 ‐3.12% 6.5%18 Costco Wholesale 432.51 415.00 ‐0.82% 2.67 (0.0220) 0.6256 ‐1.38% 9.8%19 CVS Caremark Corp. 1391.00 1285.00 ‐1.57% 1.72 (0.0271) 0.4193 ‐1.14% 8.2%20 Ecolab Inc. 236.50 245.00 0.71% 4.32 0.0306 0.7683 2.35% 22.7%21 Everest Re Group Ltd. 65.60 60.00 ‐1.77% 1.06 (0.0187) 0.0557 ‐0.10% 9.2%22 Exxon Mobil Corp. 4727.00 4300.00 ‐1.88% 2.49 (0.0466) 0.5978 ‐2.79% 14.8%23 Genʹl Dynamics 385.71 360.00 ‐1.37% 2.46 (0.0337) 0.5929 ‐2.00% 12.0%24 Genʹl Mills 337.50 300.00 ‐2.33% 4.41 (0.1026) 0.7730 ‐7.93% 7.8%25 Genuine Parts 158.92 155.00 ‐0.50% 2.41 (0.0120) 0.5852 ‐0.70% 7.2%26 Grainger (W.W.) 72.28 62.00 ‐3.02% 2.86 (0.0865) 0.6507 ‐5.63% 8.7%27 Heinz (H.J.) 315.04 310.00 ‐0.32% 6.16 (0.0199) 0.8378 ‐1.66% 16.7%28 Home Depot 1700.00 1625.00 ‐0.90% 2.65 (0.0238) 0.6222 ‐1.48% 8.5%29 Hormel Foods 134.52 130.00 ‐0.68% 2.83 (0.0193) 0.6467 ‐1.25% 10.2%30 Illinois Tool Works 502.34 480.00 ‐0.91% 2.58 (0.0234) 0.6121 ‐1.43% 11.4%31 Intʹl Business Mach. 1305.30 1150.00 ‐2.50% 3.84 (0.0959) 0.7393 ‐7.09% 17.3%32 Johnson & Johnson 2750.00 2500.00 ‐1.89% 3.13 (0.0590) 0.6800 ‐4.01% 9.1%33 Kellogg 381.86 350.00 ‐1.73% 6.16 (0.1063) 0.8376 ‐8.91% 15.8%34 Kimberly‐Clark 417.00 400.00 ‐0.83% 5.79 (0.0480) 0.8272 ‐3.97% 17.2%35 Kraft Foods 1469.30 1400.00 ‐0.96% 1.72 (0.0165) 0.4178 ‐0.69% 4.7%36 Lilly (Eli) 1149.90 1155.00 0.09% 3.04 0.0027 0.6716 0.18% 8.4%37 Lockheed Martin 372.90 320.00 ‐3.01% 5.69 (0.1715) 0.8243 ‐14.13% NMF38 McCormick & Co. 130.10 135.00 0.74% 3.59 0.0267 0.7216 1.92% 13.5%39 McDonaldʹs Corp. 1075.00 1000.00 ‐1.44% 5.00 (0.0718) 0.8000 ‐5.74% 9.6%40 McKesson Corp. 266.00 250.00 ‐1.23% 1.80 (0.0222) 0.4434 ‐0.98% 12.2%41 Medtronic, Inc. 1100.00 1000.00 ‐1.89% 2.96 (0.0559) 0.6621 ‐3.70% 12.9%42 Microsoft Corp. 9151.00 7800.00 ‐3.14% 4.89 (0.1536) 0.7953 ‐12.22% 12.4%43 NIKE, Inc. ʹBʹ 491.10 487.50 ‐0.15% 3.02 (0.0044) 0.6689 ‐0.30% 13.4%44 Northrop Grumman 306.87 250.00 ‐4.02% 2.16 (0.0868) 0.5371 ‐4.66% 7.2%45 Oracle Corp. 5150.00 4750.00 ‐1.60% 3.18 (0.0510) 0.6853 ‐3.49% 16.5%46 PepsiCo, Inc. 1553.00 1500.00 ‐0.69% 5.41 (0.0375) 0.8152 ‐3.05% 14.7%47 Pfizer, Inc. 8070.00 8070.00 0.00% 1.77 ‐ 0.4364 0.00% 6.1%48 Procter & Gamble 2917.00 2900.00 ‐0.12% 3.65 (0.0043) 0.7263 ‐0.31% 12.5%49 Raytheon Co. 383.20 330.00 ‐2.95% 2.53 (0.0745) 0.6048 ‐4.51% 8.9%50 Sigma‐Aldrich 121.88 120.00 ‐0.31% 3.36 (0.0104) 0.7027 ‐0.73% 14.3%51 Stryker Corp. 397.40 387.00 ‐0.53% 3.30 (0.0175) 0.6973 ‐1.22% 12.4%52 Sysco Corp. 601.23 570.00 ‐1.06% 5.70 (0.0605) 0.8247 ‐4.99% 12.8%53 TJX Companies 412.82 340.00 ‐3.81% 6.25 (0.2379) 0.8400 ‐19.99% 16.3%54 United Parcel Serv. 1000.00 990.00 ‐0.20% 6.99 (0.0140) 0.8570 ‐1.20% 15.0%55 United Technologies 942.29 900.00 ‐0.91% 3.79 (0.0347) 0.7363 ‐2.55% 14.2%56 Verizon Communic. 2835.70 2820.00 ‐0.11% 2.90 (0.0032) 0.6555 ‐0.21% 5.0%57 Wal‐Mart Stores 3925.00 3400.00 ‐2.83% 2.75 (0.0779) 0.6365 ‐4.96% 8.2%58 Walgreen Co. 988.56 960.00 ‐0.58% 2.48 (0.0145) 0.5967 ‐0.86% 10.2%59 Waste Management 486.12 465.00 ‐0.88% 2.55 (0.0225) 0.6078 ‐1.37% 6.9%

(a) www.valueline.com (retrieved Apr. 16, 2010).(b) Average of High and Low expected market prices.(c) Computed at (EPS ‐ DPS) / EPS.(d) Product of BVPS and No. Shares Outstanding.(e) Five‐year rate of change.(f) Computed using the formula 2*(1+5‐Yr. Change in Equity)/(2+5 Yr. Change in Equity).(g) Product of year‐end ʺrʺ for 2013‐15 and Adjustment Factor.(h) Average of High and Low expected market prices divided by 2013‐15 BVPS.(i) Product of change in common shares outstanding and M/B Ratio.(j) Computed as 1 ‐ B/M Ratio.(k) Product of ʺsʺ and ʺvʺ.(l) Product of average ʺbʺ and adjusted ʺrʺ, plus ʺsvʺ.


123


EXPECTED EARNINGS APPROACH

(a)

(b)

(c)

Adjustment

Adjusted Return

Company

2010

2011

2013‐15

Average

Factor

on Common Equity

1 A

meren Corp.

7.5%

7.5%

8.0%

7.7%

1.0213

7.8%

2 D

ominion Resou

rces

16.5%

15.5%

14.5%

15.5%

1.0432

16.2%

3 D

uke En

ergy Corp.

7.5%

8.0%

8.0%

7.8%

1.0133

7.9%

4 E

ntergy Corp.

14.5%

14.0%

12.5%

13.7%

1.0322

14.1%

5 F

PL Group

12.5%

12.0%

11.5%

12.0%

1.0373

12.4%

6 P

rogress En

ergy

8.5%

9.0%

9.0%

8.8%

1.0176

9.0%

7 S

CANA Corp.

10.0%

10.0%

10.0%

10.0%

1.0417

10.4%

8 S

outhern Co.

12.5%

12.5%

13.0%

12.7%

1.0318

13.1%

9 T

ECO Energy

12.0%

13.0%

12.5%

12.5%

1.0286

12.9%


7.8%

‐‐16.2%

Adjusted Range of Reasonableness

9.0%

‐‐16.2%

Midpoint

12.6%

Median

12.9%

(a)Th

e Value Line Investment S

urvey (Feb. 26 & M

ar. 26, 2010).

(b)Adjustm

ent to conv

ert y

ear‐end ʺrʺ to an average ra

te of return from Exh

ibit TE

C‐205.

(c)(a) x (b

).(d)Ex

clud




124

RATING SCREEN PROXY GROUP

EXPECTED EARNINGS APPROACH

(a)

(b)

(c)

Adjustment

Adjusted Return

Company

2010

2011

2013‐15

Average

Factor

on Common Equity

1 A

meren Corp.

7.5%

7.5%

8.0%

7.7%

1.0213

7.8%

4 E

ntergy Corp.

14.5%

14.0%

12.5%

13.7%

1.0322

14.1%

6 P

rogress En

ergy

8.5%

9.0%

9.0%

8.8%

1.0176

9.0%

7 S

CANA Corp.

10.0%

10.0%

10.0%

10.0%

1.0417

10.4%

9 T

ECO Energy

12.0%

13.0%

12.5%

12.5%

1.0286

12.9%


7.8%

‐‐14.1%

Adjusted Range of Reasonableness (d)

9.0%

‐‐14.1%

Midpoint

11.5%

Median

11.6%

(a)Th

e Value Line Investment S

urvey (Feb. 26 & M

ar. 26, 2010).

(b)Adjustm

ent to conv

ert y

ear‐end ʺrʺ to an average ra

te of return from Exh

ibit TE

C‐205.

(c)(a) x (b

).(d)Ex

clud




125


CAPITAL STRUCTURE

Long‐term

Common

Long‐term

Common

Company

Debt

Preferred

Equity

Debt

Other

Equity

1 A

meren Corp.

47.6%

0.0%

52.4%

46.5%

1.0%

52.5%

2 D

ominion Re

sources

59.2%

0.9%

39.9%

54.0%

0.5%

45.5%

3 D

uke En

ergy Corp.

43.7%

0.0%

56.3%

49.0%

0.0%

51.0%

4 E

ntergy Corp.

56.1%

1.5%

42.3%

54.5%

1.0%

44.5%

5 F

PL Group

56.5%

0.0%

43.5%

57.0%

0.0%

43.0%

6 P

rogress En

ergy

56.1%

0.4%

43.5%

52.5%

0.0%

47.5%

7 S

CANA Corp.

57.0%

0.0%

43.0%

53.5%

0.0%

46.5%

8 S

outhern Co.

54.7%

1.1%

44.3%

53.0%

2.5%

44.5%

9 T

ECO Energy

61.3%

0.0%

38.7%

56.5%

0.0%

43.5%

Value Line Projected 2012‐14 (b)

At December 31, 2009 (a)

gy

Average

54.7%

0.4%

44.9%

52.9%

0.6%

46.5%

(a)

Com

pany 2009 Fo

rm 10‐K Rep

orts availa

ble at http

://www.sec.gov

/edg

ar/searchedg

ar/com

pany

search.htm

l.(b)


urvey (Feb. 26 & M

ar. 26, 2010).


126


CAPITAL STRUCTURE

Long‐term

Common

Long‐term

Common

Company

Debt

Preferred

Equity

Debt

Other

Equity

1 A

meren Corp.

47.6%

0.0%

52.4%

46.5%

1.0%

52.5%

2 E

ntergy Corp.

56.1%

1.5%

42.3%

54.5%

1.0%

44.5%

3 P

rogress En

ergy

56.1%

0.4%

43.5%

52.5%

0.0%

47.5%

4 S

CANA Corp.

57.0%

0.0%

43.0%

53.5%

0.0%

46.5%

5 T

ECO Energy

61.3%

0.0%

38.7%

56.5%

0.0%

43.5%

Average

55.6%

0.4%

44.0%

52.7%

0.4%

46.9%

Value Line Projected 2012‐14 (b)

At December 31, 2009 (a)

(a)

Com

pany 2009 Fo

rm 10‐K Rep

orts availa

ble at http

://www.sec.gov

/edg

ar/searchedg

ar/com

pany

search.htm

l.(b)


urvey (Feb. 26 & M

ar. 26, 2010).


127


OPERATING CO. CAPITAL STRUCTURE

Operating CompanyCentral Illinois Light 24.6% 1.7% 73.7%Central Illinois Public Service 42.3% 5.0% 52.7%Illinois Power Co. 44.1% 1.8% 54.1%Union Electric Co. 49.8% 1.4% 48.8%Virginia Electric Power 47.4% 0.0% 52.6%Duke Energy Carolinas 48.1% 0.0% 51.9%Duke Energy Indiana 51.3% 0.0% 48.7%Duke Energy Kentucky 42.9% 0.0% 57.1%Duke Energy Ohio 30.5% 0.0% 69.5%Entergy Arkansas Inc. 51.4% 3.7% 44.9%Entergy Gulf States Louisiana LLC 53.0% 0.3% 46.7%Entergy Louisiana LLC 48.2% 2.7% 49.1%Entergy Mississippi Inc. 53.3% 3.2% 43.5%Entergy New Orleans Inc. 46.4% 4.6% 48.9%Entergy Texas Inc. 66.3% 0.0% 33.7%Florida Power & Light 40.9% 0.0% 59.1%Carolina Power & Light Co. 44.0% 0.7% 55.3%Florida Power Corp. 48.0% 0.4% 51.6%South Carolina Electric & Gas 49.4% 0.0% 50.6%Alabama Power Co. 51.1% 5.7% 43.3%Georgia Power Co. 49.6% 1.6% 48.8%Gulf Power Co. 50.4% 4.4% 45.2%Mississippi Power Co. 41.7% 2.8% 55.5%

Average 46.7% 1.7% 51.5%

Source: 2009 Form 10‐K Reports or 2009 FERC Form 1 Reports.

Long‐term Debt

Preferred Stock

Common Equity

Year‐End 2009


128

UNITED STATES OF AMERICABEFORE THE

FEDERAL ENERGY REGULATORY COMMISSION

In the Matter of ))

Tampa Electric Company ) Docket No. ER1O- -000

County of Travis )) SS

State of Texas )

VERIFICATION

William E. Avera, being first duly sworn, deposes and states that he is the witness

identified in the foregoing prepared testimony, and that the statements of fact in the

testimony and supporting exhibits are true and correct to the best of his knowledge,

information, and belief.

i-Zi- &CLWilliam E. Avera

SUBSRIBED AND SWORN before methë71 day of July, 2010

ublii

My commission expires on: \ / 0 2O I

DRIEN MCKENZIE

STATE OF TEXASMy Comm Exp. Jan. 10, 2011

BEFORE THE FEDERAL ENERGY REGULATORY ... - Tampa Electric

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Transcript of BEFORE THE FEDERAL ENERGY REGULATORY ... - Tampa Electric