Direct Testimony and Schedules John J. Reed Before

Transcription

Direct Testimony and Schedules
John J. Reed
Before the Minnesota Public Utilities Commission
State of Minnesota
In the Matter of the Application of Northern States Power Company,
a Minnesota corporation
for Authority to Increase Rates for Electric Service in Minnesota
Docket No. E002/GR-10-971
Exhibit___(JJR-1)
Return on Equity
November 3, 2010
Table of Contents
I.
Introduction and Qualifications
1
II.
Purpose and Overview
2
III.
Regulatory Guidelines and Financial Considerations
5
IV.
Current Capital Market Environment
10
V.
Proxy Group Selection
15
VI.
Cost of Equity Estimation
26
VII.
A. Constant Growth DCF Model
29
B. Dividend Yield for the DCF Model
30
C. Growth Rates for the DCF Model
31
D. Results for Constant Growth DCF Model
32
E. Flotation Adjustment
34
F. CAPM Analysis
38
G. Bond Yield Plus Risk Premium Analysis
42
Risk Factors
46
A. Capital Expenditures
46
VIII.
Capital Structure
52
IX..
Conclusion and Recommendation
53
Schedules
Statement of Qualifications
Attachment A
DCF Results and Summary
Schedule 1
Flotation Cost Calculation
Schedule 2
CAPM Results and Summary
Schedule 3
Summary of Risk Premium Results
Schedule 4
Capital Expenditure Comparison
Comparison of the Company’s Proposed Capital Structure
Relative to the Proxy Groups
Schedule 5
i
Schedule 6
1
I.
INTRODUCTION AND QUALIFICATIONS
2
3
Q. PLEASE STATE YOUR NAME, AFFILIATION AND BUSINESS ADDRESS.
4
A.
My name is John J. Reed. I am Chairman and Chief Executive Officer of
5
Concentric Energy Advisors, Inc. (“Concentric”), located at 293 Boston Post
6
Road West, Suite 500, Marlborough, Massachusetts 01752.
7
8
Q. ON WHOSE BEHALF ARE YOU SUBMITTING THIS TESTIMONY?
9
A.
I am submitting this testimony on behalf of Northern States Power Company,
10
a Minnesota corporation (the “Company”) and wholly owned subsidiary of
11
Xcel Energy Inc. (“XEI”).
12
13
Q. PLEASE
14
15
DESCRIBE YOUR EXPERIENCE IN THE ENERGY AND UTILITY
INDUSTRIES.
A.
I have more than 30 years of experience in the energy industry, having served
16
as an executive in energy consulting firms, including the position of Co-Chief
17
Executive Officer of the largest publicly-traded management consulting firm
18
in the U.S., and as Chief Economist for the largest gas utility in the U.S. I
19
have provided expert testimony on a wide variety of economic and financial
20
issues related to the energy and utility industry on numerous occasions before
21
administrative agencies, utility commissions, courts, arbitration panels, and
22
elected bodies across North America. A summary of my professional and
23
educational background is provided as Exhibit___(JJR-1), Attachment A.
24
1
Reed Direct
1
Q. PLEASE
2
3
DESCRIBE
CONCENTRIC’S
ACTIVITIES IN ENERGY AND UTILITY
ENGAGEMENTS.
A.
Concentric provides financial and economic advisory services to a large
4
number of energy and utility clients across North America. Our regulatory
5
economic and market analysis services include utility ratemaking and
6
regulatory advisory services; energy market assessments; market entry and exit
7
analysis; corporate and business unit strategy development; and energy
8
contract negotiations.
9
acquisition, and divestiture assignments; due diligence and valuation
10
assignments; project and corporate finance services; and transaction support
11
services. In addition, we provide litigation support services on a wide range
12
of financial and economic issues for clients throughout North America.
Our financial advisory activities include merger,
13
14
II.
PURPOSE AND OVERVIEW OF TESTIMONY
15
16
Q. WHAT IS THE PURPOSE OF YOUR TESTIMONY?
17
A.
The purpose of my Direct Testimony in this proceeding is to present
18
evidence and provide a recommendation regarding the Company’s return on
19
equity (“ROE”) for its electric utility operations, and to provide an assessment
20
of the capital structure to be used for ratemaking purposes, as proposed in the
21
Direct Testimony of Company witness Mr. George E. Tyson II. My analysis
22
and recommendations are supported by the data presented in Exhibit___(JJR-
23
1), Schedules 1 through 6.
24
2
Reed Direct
1
Q. WHAT
2
3
ARE YOUR CONCLUSIONS REGARDING THE APPROPRIATE COST OF
EQUITY FOR THE COMPANY?
A.
My analyses indicate that the Company’s cost of equity currently is in the
4
range of 11.21 percent to 11.44 percent, which are the mean DCF results
5
depending on the stock price observation interval chosen (30, 90 and 180
6
days), based on the weighted average DCF results of the Electric Proxy
7
Group and Combination Proxy Group.
8
qualitative analyses discussed throughout my Direct Testimony, I conclude
9
that an ROE of 11.25 percent is reasonable and appropriate. With respect to
10
the Company’s capital structure, I conclude that the Company’s proposed test
11
year 2011 capital structure, consisting of 52.56 percent common equity, 46.30
12
percent long-term debt, and 1.14 percent short-term debt, is reasonable, and
13
my analysis of the appropriate ROE for the Company is based on that capital
14
structure.
Based on the quantitative and
15
16
Q. PLEASE
17
18
PROVIDE A BRIEF OVERVIEW OF THE ANALYSIS THAT LED TO YOUR
ROE RECOMMENDATION.
A.
Since equity analysts and investors tend to use multiple methodologies in
19
developing their return requirements, it is extremely important to consider the
20
results of different analytical approaches in determining the Company’s ROE.
21
Therefore, while my ROE recommendation is primarily based on the results
22
of the Constant Growth Discounted Cash Flow (“DCF”) model, I also
23
considered the results of the Capital Asset Pricing Model (“CAPM”), and the
24
Risk Premium approach. My specifications of the DCF model are based on
25
analysts’ earnings growth projections, current indicated annual dividends, and
26
actual stock price information. My recommended ROE includes the recovery
27
of flotation costs.
3
Reed Direct
1
2
My CAPM analysis is specified using historical and projected market data with
3
respect to Treasury yields, Beta estimates from Bloomberg and Value Line,
4
and market risk premia data from Morningstar (formerly Ibbotson
5
Associates). Finally, my Risk Premium analysis is specified using the historical
6
relationship between the long-term Treasury bond yield and average allowed
7
ROEs for electric utilities.
8
9
In addition to the analyses discussed above, I considered the Company’s
10
capital expenditure program and the potential regulatory and financial risk
11
associated with this program and the absence of a decoupling mechanism or
12
other comparable rate stabilization mechanism in comparison to the proxy
13
companies that I used in my analysis. I did not include an explicit adjustment
14
for the other business and economic risks. I did, however, consider certain
15
unique aspects of the Company’s risk profile when determining where, within
16
a reasonable range, the Company’s ROE rightly falls.
17
18
In order to assess the reasonableness of the Company’s proposed capital
19
structure, I analyzed the capital structures of my electric and combination
20
proxy group companies over the past two years. Based on this review, I
21
found the Company’s recommendation to be well within the ranges observed
22
for my electric and combination company proxy groups.
23
24
Q. HOW IS THE REMAINDER OF YOUR DIRECT TESTIMONY ORGANIZED?
25
A.
The remainder of my Direct Testimony is organized in seven sections:
26
• Section III discusses the regulatory guidelines and financial
27
considerations pertinent to the development of the cost of capital;
4
Reed Direct
1
• Section IV briefly discusses recent market conditions and the effect
2
of those conditions on the Company’s ROE;
3
• Section V explains my selection of proxy groups of comparable
4
companies used to develop my analytical results;
5
• Section VI explains my analysis and the analytical basis for the
6
recommendation of the appropriate ROE for the Company;
7
• Section VII provides a discussion of specific risk factors that have a
8
direct bearing on the ROE to be authorized for the Company in this
9
case;
10
• Section VIII sets out the supporting analyses I performed to assess
11
the reasonableness of the Company’s proposed capital structure; and
12
•
Section IX summarizes my conclusions regarding the ROE.
13
14
III.
15
REGULATORY GUIDELINES AND FINANCIAL
CONSIDERATIONS
16
17
Q. PLEASE
18
19
DESCRIBE THE GUIDING PRINCIPLES TO BE USED IN ESTABLISHING
THE COST OF CAPITAL FOR A REGULATED UTILITY.
A.
The United States Supreme Court’s precedent-setting Hope and Bluefield cases
20
established the standards for determining the fairness or reasonableness of a
21
utility’s allowed ROE. Among the standards established by the Court in those
22
cases are: (1) consistency with other businesses having similar or comparable
23
risks; (2) adequacy of the return to support credit quality and access to capital;
24
and (3) that the means of arriving at a fair return are not important, only that
25
the end result leads to just and reasonable rates.1
1
Bluefield Waterworks & Improvement Co., v. Public Service Commission of West Virginia, 262 U.S. 679
(1923); Federal Power Commission v. Hope Natural Gas Co., 320 U.S. 591 (1944).
5
Reed Direct
1
2
Q. DOES MINNESOTA
3
4
STATUTE PROVIDE SIMILAR GUIDANCE IN ESTABLISHING
THE APPROPRIATE RETURN ON EQUITY?
A.
Yes. Chapter 216B of the Minnesota Statutes states:
5
6
7
8
9
10
11
12
13
14
15
The commission [Minnesota Public Utilities Commission], in
the exercise of its powers under this chapter to provide just
and reasonable rates for public utilities, shall give due
consideration to the public need for adequate, efficient, and
reasonable service and to the need of the public utility for
revenue sufficient to enable it to meet the cost of furnishing
the service, including adequate provision for depreciation of
its utility property used and useful in rendering service to the
public, and to earn a fair and reasonable return upon the
investment in such property.2
16
Based on these legal standards, the consequence of the Minnesota Public
17
Utilities Commission’s (the “Commission”) Order in this case should be to
18
provide the Company with the opportunity to earn an ROE that is: (i)
19
adequate to attract capital at reasonable terms, thereby enabling it to provide
20
safe, reliable service; (ii) sufficient to ensure the financial soundness of the
21
Company’s operations; and (iii) commensurate with returns on equity
22
investments in enterprises having comparable risks. The allowed ROE should
23
enable the Company to finance capital expenditures at reasonable rates and
24
maintain its financial flexibility over the period during which rates are
25
expected to remain in effect.
26
2
Minn. Stat. § 216B.16(6).
6
Reed Direct
1
Q. WHY IS IT IMPORTANT FOR A UTILITY TO BE ALLOWED THE OPPORTUNITY TO
2
EARN A RETURN ADEQUATE TO ATTRACT EQUITY CAPITAL AT REASONABLE
3
TERMS?
4
A.
There is a long history of precedent regarding the allowed ROE, the role of
5
capital structure, and the resulting cost of capital in the establishment of just
6
and reasonable rates for utility services. Among the themes common to many
7
Supreme Court, other Federal court, State court, and agency cases is the
8
principle that a utility’s cost of capital (including its capital structure and
9
allowed ROE) must be reflective of returns achieved by other enterprises
10
having comparable risks acting independently in the financial markets. As
11
noted elsewhere in my Direct Testimony, a return that is adequate to attract
12
capital at reasonable terms enables the Company to provide safe, reliable
13
service while maintaining its financial integrity. To the extent the Company is
14
provided the opportunity to earn its market-based cost of capital, neither
15
customers nor shareholders are disadvantaged.
16
17
While the “capital attraction” and “financial integrity” standards are important
18
principles in normal economic conditions, the practical implications of those
19
standards are even more pronounced in the current financial environment.
20
As discussed in more detail in Section IV, equity market uncertainty and the
21
high risk of interest rate increases has intensified the importance of
22
maintaining a strong financial profile. Consequently, the Commission’s Order
23
in this proceeding will have a greater consequence as it relates to the capital
24
attraction and financial integrity standards.
25
7
Reed Direct
1
Q. HOW DOES THE REGULATORY ENVIRONMENT IN WHICH A UTILITY OPERATES
2
3
AFFECT ITS ACCESS TO AND COST OF CAPITAL?
A.
The regulatory environment in which a utility operates can significantly affect
4
both the access to, and the cost of capital in several ways. First, there is little
5
question that rating agencies consider the regulatory environment, including
6
the extent to which the presiding regulatory commission is supportive of
7
issues affecting credit quality, to be an important determinant of the subject
8
company’s credit profile.
9
example, considers the nature of regulation, including its effect on cost
10
recovery and cash flow generation, to be of such consequence that it
11
represents 50 percent of the factors analyzed in arriving at credit ratings.3 As
12
to the overall regulatory environment, Moody’s notes that “…the
13
predictability and supportiveness of the regulatory framework in which [a
14
regulated utility] operates is a key credit consideration and the one that
15
differentiates the industry from most other corporate sectors.”4 Moody’s
16
further explains:
17
18
19
20
21
22
23
24
25
26
27
28
29
Moody’s Investors Service (“Moody’s”), for
For a regulated utility company, we consider the characteristics
of the regulatory environment in which it operates. These
include how developed the regulatory framework is; its track
record for predictability and stability in terms of decision
making; and the strength of the regulator’s authority over
utility regulatory issues. A utility operating in a stable, reliable,
and highly predictable regulatory environment will be scored
higher on this factor than a utility operating in a regulatory
environment that exhibits a high degree of uncertainty or
unpredictability. Those utilities operating in a less developed
regulatory framework or one that is characterized by a high
degree of political intervention in the regulatory process will
receive the lowest scores on this factor.5
3
4
5
Special Comment: Regulatory Frameworks – Ratings and Credit Quality for Investor-Owned Utilities, Moody’s Investors
Service, June 18, 2010, at 3.
Rating Methodology: Regulated Electric and Gas Utilities, Moody’s Investors Service, August 2009, at 7.
Ibid., at 6.
8
Reed Direct
1
2
Standard & Poor’s (“S&P”) notes that regulatory commissions should
3
eliminate, or at least greatly reduce, the issue of rate-case lag, especially when a
4
utility engages in a sizable capital expenditure program.6 Moody’s agrees that
5
timely cost recovery is an important determinant of credit quality, stating that
6
“[t]he ability to recover prudently incurred costs in a timely manner is perhaps
7
the single most important credit consideration for regulated utilities, as the
8
lack of timely recovery of such costs has caused financial stress for utilities on
9
several occasions”7
10
11
It also is important to note that regulatory decisions regarding the ROE and
12
capital structure have direct consequences for the subject utility’s internal cash
13
flow generation (sometimes referred to as “Funds Flow from Operations”, or
14
“FFO”).
15
financial obligations as they come due, the ability to generate the cash flows
16
required to meet those obligations (and to provide an additional amount for
17
unexpected events) is of critical importance to debt investors. Two of the
18
most important metrics used to assess that ability are the ratios of FFO to
19
debt, and FFO to interest expense, both of which are directly affected by
20
regulatory decisions regarding the appropriate ROE and capital structure.
6
7
Since credit ratings are intended to reflect the ability to meet
Standard and Poor’s, Assessing Vertically Integrated Utilities’ Business Risk Drivers, U.S. Utilities and Power
Commentary, November 2006, at 10.
Moody’s, Global Infrastructure Finance, Regulated Electric and Gas Utilities, August 2009, at 7.
9
Reed Direct
1
2
IV. CURRENT CAPITAL MARKET ENVIRONMENT
Q. HOW
3
4
DO ECONOMIC CONDITIONS INFLUENCE THE COST OF CAPITAL AND
ROE?
A.
The required cost of capital, including the ROE, is a function of prevailing
5
and expected market conditions.
6
decisions, the authorized ROE for a public utility should allow the company
7
to attract investor capital at reasonable cost under a variety of economic and
8
financial market conditions. The ability to attract capital on favorable terms is
9
especially important during a period in which utilities are being asked to
10
Consistent with the Hope and Bluefield
enhance system reliability and expand system capacity.
11
12
Q. DOES
13
14
THE POTENTIAL FOR INCREASING INTEREST RATES REPRESENT A
SOURCE OF RISK TO UTILITIES?
A.
Yes, it does. The financial community has consistently recognized that the
15
stock prices of companies which pay significant dividends (such as electric
16
utilities) have a negative correlation to interest rates. Value Line, for example,
17
establishes “price targets” based on the ratio of dividends per share to interest
18
rates; as interest rates increase, the price target declines, resulting in an
19
increased targeted dividend yield. Consistent with Value Line’s methodology,
20
as shown in Chart 1 (below), there is a strong, positive statistical relationship
21
between the proxy companies’ average dividend yield and the 30-year
22
Treasury yield.
23
10
Reed Direct
1
Chart 1: Proxy Group Average Dividend Yield vs. 30-Year Treasury Yield
10.00%
Proxy Group Average Dividend Yield
9.00%
8.00%
7.00%
6.00%
y = 0.6882x + 0.0165
R² = 0.654
5.00%
4.00%
3.00%
2.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
8.00%
9.00%
10.00%
30-year Treasury Yield
2
3
4
Q. WHAT IS THE SIGNIFICANCE OF THIS RELATIONSHIP TO THE COST OF EQUITY?
5
A.
Given the currently low level of long-term Treasury rates (by historical
6
standards), it is reasonable to assume that on balance, long-term Treasury
7
rates are more likely to increase than decrease in the near to intermediate
8
term. In fact, the Blue Chip Financial Forecasts projects the 30-year Treasury
9
bond to yield 5.70 percent by 2013,8 while the 30-day average yield on 30-year
10
Treasury securities was approximately 3.73 percent as of September 30, 2010.
11
This projected increase of approximately 197 basis points over a period of
12
three years represents a significant element of market risk.
13
8
Blue Chip Financial Forecasts, Vol. 29, No. 6, June 1, 2010, at 14.
11
Reed Direct
1
Q. WHAT
2
3
ANALYSIS HAVE YOU CONDUCTED TO ASSESS CURRENT CAPITAL
MARKET CONDITIONS?
A.
Because Treasury security interest rates remain at historically low levels, I
4
examined the relationship between the interest rate on ten-year Treasury
5
notes and the dividend yield of my proxy group over time.
6
7
Chart 2: Treasury Yield/Dividend Yield Inversion
9.00%
8.00%
7.00%
Yield
6.00%
5.00%
4.00%
3.00%
2.00%
1.00%
0.00%
1/3/1995
8
1/3/1997
1/3/1999
1/3/2001
1/3/2003
Proxy Group Average Yield
12
1/3/2005
1/3/2007
1/3/2009
10-Year Treasury Yield
Reed Direct
1
2
As shown in Chart 2, the 2008 – 2009 financial dislocation created the first
3
inversion (wherein, as opposed to its typical relationship, the dividend yield
4
exceeded the Treasury yield) of the ten-year Treasury yield relative to the
5
proxy group average dividend yield in five years. The most recent period
6
during which these yields were significantly inverted was the period from mid-
7
2002 through mid-2003, which likewise was a period of credit and equity
8
valuation contraction.
9
10
Q. HAS THE SIGNIFICANCE OF THIS INVERSION BEEN NOTED?
11
A.
Yes. In a 2009 article, The Wall Street Journal noted this same inverted
12
relationship between utility dividend yields and the ten-year Treasury yield,
13
noting that:
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
...dividend yields have tended to track the yield on 10-year
Treasurys closely. Since 1970, the spread of regulated utilities’
dividend yields over Treasury yields has averaged 0.24
percentage point. Today, with utilities yielding about 5.65%,
the spread is 10 times that, having peaked in March at 3.75
percentage points. You have to go all the way back to the
early 1980s for the last time it reached such heights.
***
Regulated utilities’ dividend yields decoupled from Treasury
yields in December 2007, as the U.S. recession began. After
the initial flight to quality cut yields on Treasurys, particularly
after Lehman Brothers collapsed in September 2008, the
Federal Reserve’s policy of buying up government debt has
helped keep them low.9
29
Significantly, that inversion of dividend yield relative to the ten-year Treasury
30
has continued unabated since that article was published, demonstrating the
9
A Short Circuit in the Stock Market, The Wall Street Journal, Liam Denning, October 23, 2009, at C10.
13
Reed Direct
1
extraordinarily low level of Treasury yields discussed previously and the
2
continuing high level of capital market uncertainty that began in 2008.
3
4
Q. WHAT CONCLUSIONS DO YOU DRAW FROM THIS ANALYSIS?
5
A.
These analyses demonstrate that the current capital market continues to
6
experience high levels of risk aversion, and uncertainty. The result, of course,
7
is an increased, not a decreased cost of equity. It is well established that utility
8
stock prices decline as interest rates increase. Such lower valuation levels
9
reflect increased costs of attracting the equity capital needed to fund the
10
Company’s capital investment program, and, therefore, reflect the need for a
11
commensurately higher ROE.
12
13
Furthermore, as noted in the June 2010 Federal Reserve Open Market
14
Committee (“FOMC”) Minutes, during the period from April to June 2010,
15
“[t]he spread between the staff’s estimate of the expected real return on
16
equities over the next 10 years and an estimate of the expected real return on
17
a 10-year Treasury note—a measure of the equity risk premium—increased
18
from its already elevated level.”10
19
20
It is also clear that the current market conditions are similar to the 2002-2003
21
market dislocation that affected all market segments, including utilities. As in
22
the current market, one outcome of the 2002-2003 market dislocation was a
23
renewed emphasis on capital market access, and the importance of
24
maintaining a strong financial profile, such strength and capital market access
25
are equally important in the current market environment.
26
10
Federal Open Market Committee, Minutes of the Meeting of June 22-23, 2010, at 6.
14
Reed Direct
1
Q. HOW
SHOULD CURRENT ECONOMIC CONDITIONS AND CAPITAL SPENDING
2
PLANS BE TAKEN INTO CONSIDERATION IN DETERMINING THE APPROPRIATE
3
ROE FOR THE COMPANY?
4
A.
In my view, the authorized rate of return in this proceeding will provide a
5
signal to the financial community concerning the ability of the Company to
6
meet its capital needs during a period in which its capital investments are
7
increasing, and both debt and equity investors are requiring higher rates of
8
return.
9
evidenced by an allowed rate of return that compensates the Company at a
10
level commensurate with its risk, the Company should be able to attract equity
11
capital at a reasonable cost.
If investors perceive a supportive regulatory environment, as
12
13
V. PROXY GROUP SELECTION
14
15
Q. PLEASE
16
17
EXPLAIN WHY YOU HAVE USED PROXY COMPANIES TO DETERMINE
THE COST OF EQUITY FOR THE COMPANY.
A.
In this proceeding, we are focused on estimating the cost of equity for the
18
Company, a wholly owned subsidiary of XEI. Since the ROE is a market-
19
based concept, and given that the Company is not publicly traded, it is
20
necessary to establish one or more groups of companies that are both publicly
21
traded and comparable to the Company in certain fundamental business and
22
financial respects to serve as its “proxy” in the ROE estimation process.
23
24
Even if the Company were a publicly traded entity, it is possible that
25
transitory events could bias its market value in one way or another over a
26
given period of time. A significant benefit of using proxy groups, therefore, is
27
that it serves to dampen the effects of anomalous events that may be
15
Reed Direct
1
associated with any one company. Furthermore, regulatory commissions and
2
analysts alike recognize the importance of developing proxy groups that
3
adequately represent the ongoing risks and prospects of the subject company.
4
5
Q. DOES THE SELECTION OF SIMILAR PROXY GROUPS SUGGEST THAT ANALYTICAL
6
RESULTS WILL BE TIGHTLY CLUSTERED AROUND AVERAGE
7
RESULTS?
8
A.
Not necessarily.
(I.E.,
MEAN)
As discussed in greater detail in Section VI, the DCF
9
approach is based on the theory that a stock’s current price represents the
10
present value of its future expected cash flows. The Constant Growth form
11
of the DCF model is defined as the sum of the expected dividend yield and
12
projected long-term growth. Notwithstanding the care taken to ensure risk
13
comparability, market expectations with respect to future risks and growth
14
opportunities will vary from company to company. Therefore, even within a
15
group of similarly situated companies, it is common for analytical results to
16
reflect a seemingly wide range. At issue, then, is how to select an ROE
17
estimate in the context of that range. As discussed throughout my Direct
18
Testimony, that determination necessarily must be based on the informed
19
judgment and experience of the analyst.
20
21
Q. PLEASE PROVIDE A SUMMARY PROFILE OF THE COMPANY.
22
A.
The Company provides electric utility service to approximately 1.4 million
23
customers and natural gas utility service to approximately 500,000 customers
24
in Minnesota, North Dakota, and South Dakota.11 Approximately 92 percent
25
of the Company’s retail electric net income was derived from operations in
26
Minnesota in 2009. As shown in Table 1, below, the Company has electric
11
Northern States Power Company, SEC Form 10-K for fiscal year 2009, at 16 and 18.
16
Reed Direct
1
net plant of approximately $6.7 billion, and natural gas net plant of
2
approximately $861 million. Investors are aware that, while an investment in
3
the Company includes both gas and electric operations, its electric operations
4
are a far larger proportion of the Company’s overall business.
5
Company’s long-term issuer credit rating issued by Standard and Poor’s and
6
Fitch Ratings is A-, and by Moody’s Investor Services is A3. Table 1 provides
7
relevant financial and operating statistics for the Company for the most recent
8
three years.
9
The
Table 1: Company Operating and Financial Results 2007 to 200912
($ 000s)
Electric Utility Net Income
Net Property, Plant and
Equipment
Electric Utility Customers
Total Energy Sold (millions of
kWh)
Capital Expenditures
Utility Net Income
Total Gas Plant in Service13
Natural Gas Distribution
Customers
Total Throughput (thousands of
MMBtu)
2007
2008
Electric Utility Operations
$246,086
$250,785
2009
$261,556
$6,202,365
$6,539,913
$6,680,083
1,370,930
1,382,047
1,387,010
40,726
39,898
38,654
$894,238
$731,023
$28,887
$835,345
$21,881
$860,774
469,632
475,176
478,000
89,012
97,242
92,675
$43,582
$45,215
$48,042
$911,142
Natural Gas Utility Operations
$21,485
$800,872
10
11
Q. WHAT
12
13
CONCLUSIONS DO YOU DRAW REGARDING THE
COMPANY’S
ELECTRIC
AND NATURAL GAS OPERATIONS FROM THAT DATA?
A.
14
Based on the information presented in Table 1, it is clear that the Company’s
primary focus is on its electric utility operations. For example, as of 2009, the
12
13
Northern States Power Company, SEC Form 10-K for fiscal year 2009, at 16, 19, 84. Northern States
Power Company, 2008 and 2009 FERC Form 1, at 110.
Northern States Power Company, 2008 and 2009 Gas LDC filings.
17
Reed Direct
1
electric utility operations comprised over 88 percent of the Company’s total
2
net plant, over 92 percent of the Company’s total utility operating income and
3
over 74 percent of the Company’s total customers.
4
however, as noted in Table 1 (above), the Company’s capital expenditure
5
program has been concentrated in its electric utility operations over the last
6
three reporting years by an 18:1 margin.
More importantly
7
8
Q. DO YOU EXPECT THAT THE COMPANY WILL CONTINUE TO FOCUS PRIMARILY
9
10
ON ITS ELECTRIC UTILITY OPERATIONS IN THE FUTURE?
A.
Yes. Based on the Company’s internal projections of rate base (see Table 2,
11
below), it is clear that the Company anticipates focusing its investment
12
program on its electric utility operations, increasing the concentration in the
13
Company’s electric utility operations.
14
Company’s natural gas operations’ rate base is projected to grow by
15
approximately 0.4 percent annually in the years 2010 through 2014, while the
16
Company’s electric utility operations is projected to grow by approximately
17
8.5 percent annually in the same time frame. Moreover, in 2014, the electric
18
operations will be approximately 94 percent of the Company’s rate base, while
19
the gas operations will be less than 6 percent.
18
As shown in Table 2 below, the
Reed Direct
1
Table 2: Company Projected Rate Base by Utility Operation14
2010
MN Gas Rate Base
2011
2012
2013
2014
CAGR15
447,698
447,161
451,466
455,145
455,019
0.4%
MN Electric Rate Base
5,325,245
5,724,749
6,313,763
6,785,435
7,369,640
8.5%
Total Average Rate Base
5,772,943
6,171,910
6,765,229
7,240,580
7,824,659
7.9%
92.24%
92.75%
93.33%
93.71%
94.18%
7.76%
7.25%
6.67%
6.29%
5.82%
% of Rate Base in
Electric Operations
% of Rate Base in
Natural Gas Operations
2
3
Q. HOW
4
5
DID YOU TAKE INTO CONSIDERATION THE FACT THAT THE
COMPANY
HAS BOTH GAS AND ELECTRIC OPERATIONS IN THIS CASE?
A.
My analysis recognizes that the purpose of this case is to establish the rates
6
for the Company’s electric utility operations. However, in the Commission’s
7
last Order establishing the authorized ROE for the Company’s electric utility
8
in Docket No. E002/GR-08-1065, the Commission recognized the
9
appropriateness of considering the returns on common equity of other
10
combined electric and gas utilities in setting the Company’s authorized ROE
11
for its electric operations:
12
13
14
15
16
17
18
19
20
21
While the returns on equity of electric – only utilities may be
more probative than the returns of combined companies, the
returns of combined companies provide important
information and remain probative and relevant. The goal in
setting an authorized return on equity is to reflect as accurately
as possible the market situation the company faces. The
situation Xcel faces is the situation of a combined gas and
electric utility with its operations concentrated in the electric
sector. Under these circumstances it was clearly reasonable
and appropriate to include combined utilities as a comparison
14
15
Source: Company projections.
Compound Average Growth Rate (“CAGR”).
19
Reed Direct
1
2
3
group, while weighting the DCF results of the electric-only
comparison group more heavily.16
4
In that case, the Commission approved an ROE for the Company’s electric
5
utility that was based on the weighted DCF results of an electric proxy group
6
and a combination company proxy group. Therefore, consistent with the
7
Commission’s decision in Docket No. E002/GR-08-1065, my analysis
8
considers the weighted ROE results of an integrated electric company proxy
9
group and a combination company proxy group, and I applied the same
10
weightings to maintain consistency with the Commission’s approach in that
11
docket.
12
13
Q. HOW DID YOU SELECT THE COMPANIES INCLUDED IN YOUR ELECTRIC UTILITY
14
15
PROXY GROUP?
A.
16
The vertically integrated electric utility proxy group was selected based on the
following criteria:
17
• I began with companies that Value Line classifies as Electric Utilities,
18
which includes a group of 54 domestic U.S. utilities.
19
• I excluded companies that have not been covered by at least two
20
generally recognized utility industry equity analysts.
21
• I excluded companies that had senior bond and/or corporate ratings
22
below BBB- or above AA.
23
• I excluded companies that do not pay cash dividends, because such
24
companies cannot be analyzed using the DCF model, which is the
25
primary method used in my analysis.
26
• I excluded companies that do not own regulated generation assets.
16
Docket Number E002/GR-08-1065, Findings of Fact, Conclusions of Law, and Order at 11, October 23,
20
Reed Direct
1
• I excluded companies whose regulated revenues and net income
2
comprise less than 60 percent of the respective totals for the company.
3
• I excluded companies whose regulated electric revenues and net
4
income represented less than 90 percent of total regulated revenues and
5
net income to ensure a focus on companies whose revenues and net
6
income are derived primarily from electric operations.
7
Finally, I eliminated any companies that are currently known to be party to a
8
merger.
9
10
Q. BASED
11
12
ON YOUR CRITERIA WHAT WAS THE COMPOSITION OF YOUR PROXY
GROUP?
A.
The criteria discussed above resulted in an initial electric proxy group
13
consisting of the following fourteen companies: American Electric Power,
14
Cleco Corp., DPL, Inc., Edison International, Great Plains Energy, Inc.,
15
Hawaiian Electric, IDACORP, Inc, NextEra Energy, Inc., Northeast Utilities,
16
Pinnacle West Capital, Portland General, Progress Energy, Southern
17
Company, and Westar Energy.
18
19
Q. IS THIS YOUR FINAL PROXY GROUP?
20
A.
No, it is not. I excluded two companies from this preliminary group Edison
21
International (“EIX”) and Northeast Utilities (“NU”). Edison International
22
(“EIX”) experienced significant unregulated operating losses in 2009; those
23
losses were in excess of 55 percent of EIX’s regulated utility operating
24
income. According to EIX’s SEC Form 10-K for the fiscal year ended
25
December 31, 2009, those significant operating losses were the result of a
2009.
21
Reed Direct
1
global tax settlement and payment to the Internal Revenue Service (“IRS”),
2
which caused EIX’s unregulated marketing and trading segment to incur over
3
$1.0 billion in payments to settle a claim by the IRS.17 Given the extent of
4
those losses, it is difficult to assess the extent to which the regulated electric
5
utility operations would be expected to contribute to the company’s
6
consolidated financial performance in the near and longer terms. Further, the
7
scale of these losses (which arose from unregulated operations) could have a
8
significant effect on analysts’ expectations for EIX, which could also have an
9
effect on DCF analyses of EIX to be used in establishing the return for a
10
regulated utility. Consequently, I have excluded EIX from my final electric
11
proxy group (the “Electric Proxy Group”).
12
13
On October 18, 2010, Northeast Utilities and NStar announced a merger
14
agreement wherein NU would acquire NStar for $4.2 billion in stock. While
15
the analyses discussed in the remainder of my testimony are based on market
16
data through September 2010, and may not be affected by the merger
17
announcement, as a practical matter, NU would be excluded from all
18
subsequent analyses in this proceeding as a result of the merger. Therefore, I
19
eliminated NU from my final proxy group.
20
21
Q. WHAT
22
23
COMPANIES HAVE YOU INCLUDED IN YOUR FINAL ELECTRIC PROXY
GROUP?
A.
17
That group includes the following twelve companies:
See, Edison International, SEC Form 10-K for the fiscal year ended December 31, 2009, at 129.
22
Reed Direct
1
Table 3: Final Electric Proxy Group
American Electric Power
NextEra Energy, Inc
Cleco Corp.
Pinnacle West Capital
DPL, Inc.
Portland General
Great Plains Energy, Inc.
Progress Energy
Hawaiian Electric
Southern Company
IDACORP, Inc
Westar Energy
2
3
Q. HOW DID YOU DEVELOP THE COMBINATION COMPANY PROXY GROUP?
4
A.
5
6
7
The combination company proxy group was selected based on the following
criteria:
• I began with the group of 54 companies that currently are classified as
Electric Utilities by Value Line;
8
• To select strictly combination gas and electric utilities, I have only
9
included companies with at least 10 percent of total regulated revenue
10
and net income derived from regulated natural gas distribution;
11
• To select companies that are primarily regulated utilities, I have only
12
included companies with over 60 percent of total revenue and net
13
operating income derived from regulated utility operations;
14
15
16
17
• I eliminated proxy companies that did not have senior bond and/or
corporate credit ratings of BBB- to AA by Standard and Poor’s;
• I eliminated companies that have a recent history of not paying
dividends or do not have positive earnings growth projections;
18
• I eliminated companies that are party to a merger; and
19
• I eliminated the companies that are not covered by at least two utility
20
industry equity analysts.
21
23
Reed Direct
1
Q. BASED
2
3
ON
YOUR
CRITERIA
WHAT
WAS THE COMPOSITION
OF
THE
COMBINATION PROXY GROUP?
A.
The criteria discussed above resulted in a Combination Proxy Group
4
consisting of the following twelve companies: Alliant Energy Corp., Avista
5
Corp., Black Hills Corp., CenterPoint Energy, Consolidated Edison, DTE
6
Energy Co., PG&E Corp., SCANA Corp., TECO Energy, Inc., Vectren
7
Corp., Wisconsin Energy, and Xcel Energy Inc.
8
9
10
Q. DID YOU INCLUDE XEI IN YOUR FINAL PROXY GROUP?
A.
No, I did not. While the fact that the screening criteria indicate that Xcel
11
Energy Inc. is fundamentally comparable to the other combination company
12
proxy companies, in order to avoid the circular logic that otherwise would
13
arise, it has been my consistent practice to exclude the subject company from
14
my final Combination Proxy Group (the “Combination Proxy Group”).
15
16
Q. WHAT
17
18
COMPANIES HAVE YOU INCLUDED IN YOUR FINAL
COMBINATION
PROXY GROUP?
A.
My Combination Proxy Group includes the following eleven companies:
19
Table 4: Final Combination Proxy Group
Alliant Energy Corp.
PG&E Corp.
Avista Corp.
SCANA Corp.
Black Hills Corp.
TECO Energy, Inc.
CenterPoint Energy
Vectren Corp.
Consolidated Edison
Wisconsin Energy
DTE Energy Co.
20
24
Reed Direct
1
Q. HAVE
2
3
YOU TAKEN APPROPRIATE STEPS IN YOUR ANALYSIS TO ADDRESS THE
IMPACT OF NRG ENERGY, INC. (“NRG”) ON NSP-MN’S COST OF EQUITY?
A.
Yes. I have eliminated any effects that NRG may have had on NSP-MN’s
4
ROE for ratemaking purposes by using the Electric Proxy Group and the
5
Combination Proxy Group utilities to calculate the ROE. The screening
6
process ensured that the companies used in my analyses included primarily
7
electric and combination utilities without significant interests in merchant
8
generation. My recommended ROE, therefore, excludes the effects of NRG
9
10
Q. DID
11
12
YOU TAKE THE
COMPANY’S
FUTURE RATE BASE PROJECTION INTO
CONSIDERATION IN DEVELOPING YOUR RECOMMENDED ROE?
A.
Yes, I did.
While my analytical results described below incorporate my
13
Combination Proxy Group, I recognize that the Company is viewed by debt
14
rating agencies and would be viewed by equity investors, were it publicly
15
traded, as primarily an electric utility.18 Because the natural gas business has a
16
marginal role in the performance and risk profile of the Company, it would be
17
reasonable to establish the ROE for the Company based entirely on the
18
results of my Electric Proxy Group. Therefore, while my analytical results
19
reflect the weighted average cost of equity calculations of both my Electric
20
Proxy Group and Combination Proxy Group, I have taken the Company’s
21
operating profile into consideration in the development of my recommended
22
ROE.
18
See, for example, Credit Opinion: Northern States Power Company (Minnesota), Moody’s Investor Service,
December 8, 2009
25
Reed Direct
1
2
VI. COST OF EQUITY ESTIMATION
3
4
Q. PLEASE
5
6
BRIEFLY DISCUSS THE
ROE
IN THE CONTEXT OF THE REGULATED
RATE OF RETURN.
A.
Regulated utilities primarily use common stock and long-term debt to finance
7
their permanent property, plant and equipment. The rate of return (“ROR”)
8
for a regulated utility is based on its weighted average cost of capital, in which
9
the cost rates of the individual sources of capital, including the ROE, are
10
weighted by their respective book values. While the cost of debt can be
11
directly observed, the cost of equity is market-based and, therefore, must be
12
inferred from market-based information.
13
14
Q. HOW IS THE REQUIRED ROE DETERMINED?
15
A.
The required ROE is estimated by using one or more analytical techniques
16
that rely on market-based data to quantify investor expectations regarding
17
required equity returns, adjusted for certain incremental costs and risks. I
18
then apply my informed judgment, based on the results of those analyses, to
19
determine where within the range of results the cost of equity for the
20
Company should rightly fall. The resulting adjusted cost of equity serves as
21
the recommended ROE for ratemaking purposes. As a general proposition,
22
the key consideration in determining the cost of equity is to ensure that the
23
methodologies employed reasonably reflect an investor’s view of the financial
24
markets in general, and the subject company’s common stock in particular.
25
26
Reed Direct
1
Q. WHAT METHODS DID YOU USE TO DETERMINE THE COMPANY’S ROE?
2
A.
I used the DCF model as the initial approach; I then considered the results of
3
the CAPM and a Bond Yield plus Risk Premium approach in assessing the
4
reasonableness of the DCF results and developing my ROE recommendation.
5
As discussed in more detail below, the use of a historical market risk premium
6
in the CAPM produces results that are entirely inconsistent with current
7
market conditions.
8
9
Q. WHY DO YOU BELIEVE IT IS IMPORTANT TO USE MORE THAN ONE ANALYTICAL
10
11
APPROACH?
A.
As noted above, the cost of equity is not directly observable and, therefore,
12
must be estimated based on both quantitative and qualitative information. As
13
a result, a number of models have been developed to estimate the cost of
14
equity. As a general proposition, when faced with the task of estimating the
15
cost of equity, analysts are inclined to gather and evaluate as many relevant
16
data as reasonably can be analyzed.
17
approaches to estimate the cost of equity used in performing valuations in the
18
context of our financial advisory and transaction practices. In addition, as a
19
practical matter, all of the models available to estimate the cost of equity are
20
subject to limiting assumptions or other methodological constraints.
21
Consequently, many finance texts recommend using multiple approaches
22
when estimating the cost of equity.
23
example, suggest using the CAPM and Arbitrage Pricing Theory model, while
19
For that reason, I use multiple
Copeland, Koller and Murrin,19 for
Tom Copeland, Tim Koller and Jack Murrin, Valuation: Measuring and Managing the Value of Companies,
3rd ed. (New York: McKinsey & Company, Inc., 2000), at 214.
27
Reed Direct
1
Brigham and Gapenski20 recommend the CAPM, DCF and “bond yield plus
2
risk premium” approaches.
3
4
In essence, analysts and academics understand that ROE models simply are
5
tools to be used in the ROE estimation process and that strict adherence to
6
any single approach or the specific results of any single approach can lead to
7
flawed and irrelevant conclusions. That position is consistent with the Hope
8
and Bluefield findings that it is the analytical result, as opposed to the
9
methodology that is controlling in arriving at ROE determinations. Thus, a
10
reasonable ROE estimate appropriately considers alternate methodologies and
11
the reasonableness of their individual and collective results.
12
13
Thus, although we cannot directly observe the cost of equity, we can apply
14
the methods frequently used by analysts to arrive at their return requirements
15
and expectations.
16
approaches in developing their estimate of return requirements, each
17
methodology requires certain judgment with respect to the reasonableness of
18
assumptions and the validity of proxies in its application.
19
therefore, it is both prudent and appropriate to use multiple methodologies in
20
order to mitigate the effects of assumptions and inputs associated with relying
21
exclusively on any single approach. Such use, however, must be tempered
22
with due caution as to the results generated by each individual approach,
23
especially given the current, abnormal market conditions.
24
general reliance on the DCF model in regulatory proceedings, and in light of
25
the capital market conditions discussed above, the Constant Growth form of
20
While investors and analysts tend to use multiple
In my view,
Based on the
Eugene Brigham, Louis Gapenski, Financial Management: Theory and Practice, 7th Ed. (Orlando: Dryden
Press, 1994), at 341. See also How do CFOs make capital budgeting and capital structure decisions?, John
28
Reed Direct
1
the DCF, supported by the results of the CAPM and Bond Yield Plus Risk
2
Premium analysis, is a reasonable methodological approach to establish the
3
Company’s cost of equity.
4
5
6
A.
Q. ARE DCF MODELS WIDELY USED TO DETERMINE THE ROE FOR REGULATED
7
8
Constant Growth DCF Model
UTILITIES?
A.
Yes. DCF models are widely used in regulatory proceedings and have sound
9
theoretical bases, although neither the DCF model nor any other model can
10
be applied without considerable judgment in the selection of data and the
11
interpretation of results. In its simplest form, the DCF model expresses the
12
cost of equity as the sum of the expected dividend yield and long-term growth
13
rate.
14
15
Q. PLEASE DESCRIBE THE DCF APPROACH.
16
A.
The DCF approach is based on the theory that a stock’s current price
17
represents the present value of all expected future cash flows. In its most
18
general form, the DCF model is expressed as follows:
P0 =
19
D1
D2
D∞
+
+ ... +
2
(1 + k ) (1 + k )
(1 + k ) ∞ [1]
20
Where P0 represents the current stock price, D1 … D∞ are all expected future
21
dividends, and k is the discount rate, or required ROE. Equation [1] is a
22
standard present value calculation that can be simplified and rearranged into
23
the familiar form:
Graham and Campbell Harvey, Duke University, Journal of Applied Corporate Finance, Volume 15,
Number 1, Spring 2002.
29
Reed Direct
k=
1
D (1 + g )
+g
P0
[2]
2
Equation [2] is often referred to as the “Constant Growth DCF” model, in
3
which the first term is the expected dividend yield and the second term is the
4
expected long-term growth rate.
5
6
Q. WHAT ASSUMPTIONS ARE REQUIRED FOR THE DCF MODEL?
7
A.
The DCF model requires the following assumptions: (1) a constant average
8
growth rate for earnings and dividends; (2) a stable dividend payout ratio; (3)
9
a constant price-to-earnings multiple; and (4) a discount rate greater than the
10
expected growth rate.
To the extent that any of these assumptions are
11
violated, considered judgment and/or specific adjustments should be applied
12
to the results.
13
14
B.
15
Q. WHAT
16
17
Dividend Yield for the DCF Model
MARKET DATA DID YOU USE TO CALCULATE THE DIVIDEND YIELD IN
YOUR DCF MODEL?
A.
The dividend yield in my DCF model is based on the proxy companies’
18
current annualized dividend and average closing stock prices over the 30, 90
19
and 180-trading days ended September 30, 2010.
20
21
Q. WHY DID YOU USE AVERAGING PERIODS OF 30, 90, AND 180-DAYS?
22
A.
I believe it is important to use an average of recent trading days to calculate
23
the term P0 in the DCF model to ensure that the calculated ROE is not
24
skewed by anomalous events that may affect stock prices on any given trading
25
day. In that regard, the averaging period should be reasonably representative
26
of expected capital market conditions over the long term. At the same time, it
30
Reed Direct
1
is important to reflect the extraordinary conditions that have defined the
2
financial markets over the recent past. In my view, considering 30, 90 and
3
180-day averaging periods reasonably balances those concerns
4
5
Q. PUTTING ASIDE THE ISSUE OF THE AVERAGING PERIOD, DID YOU MAKE ANY
6
ADJUSTMENTS TO THE DIVIDEND YIELD TO ACCOUNT FOR PERIODIC GROWTH
7
IN DIVIDENDS?
8
A.
9
Yes. Since utility companies tend to increase their quarterly dividends at
different times throughout the year, it is reasonable to assume that dividend
10
increases will be evenly distributed over calendar quarters.
Given that
11
assumption, it is reasonable to apply one-half of the expected annual dividend
12
growth for purposes of calculating the expected dividend yield component of
13
the DCF model. This adjustment ensures that the expected dividend yield is,
14
on average, representative of the coming twelve-month period, and does not
15
overstate the aggregated dividends to be paid during that time. Accordingly,
16
the DCF estimates provided in Exhibit___(JJR-1), Schedule 1 reflect one-half
17
of the expected growth in the dividend yield component of the model.
18
19
C.
20
Q. IS
21
22
Growth Rates for the DCF Model
IT IMPORTANT TO SELECT APPROPRIATE MEASURES OF LONG-TERM
GROWTH IN APPLYING THE DCF MODEL?
A.
Yes. In its constant growth form, the DCF model (i.e., Equation [2]) assumes
23
a single growth estimate in perpetuity. Accordingly, in order to reduce the
24
long-term growth rate to a single measure, (as noted earlier) one must assume
25
a constant payout ratio, and that earnings per share, dividends per share and
26
book value per share all grow at the same constant rate. Over the long run,
27
however, dividend growth can only be sustained by earnings growth.
31
Reed Direct
1
Consequently, it is important to incorporate a variety of measures of long-
2
term earnings growth into the constant growth DCF model. This can be
3
accomplished by averaging those measures of long-term growth that tend to
4
be least influenced by capital allocation decisions that companies may make in
5
response to near-term changes in the business environment. Since such
6
decisions may directly affect near-term dividend payout ratios, estimates of
7
earnings growth are more indicative of long-term investor expectations than
8
are dividend growth estimates. Therefore, for the purposes of the Constant
9
Growth form of the DCF model, growth in earnings per share (“EPS”)
10
represents the appropriate measure of long-term growth.
11
12
D. Results for Constant Growth DCF Model
13
Q. PLEASE SUMMARIZE YOUR INPUTS TO THE CONSTANT GROWTH DCF MODEL.
14
A.
15
I applied the DCF model to the Electric Proxy Group and Combination
Proxy Group using the following inputs for the price and dividend terms:
16
• The average daily closing prices for the 30-trading days, 90-trading
17
days, and 180-trading days ended September 30, 2010 for the term P0;
18
and
19
20
• The annualized dividend per share as of September 30, 2010 for the
term D0.
21
I then calculated the DCF results using the average of the following growth
22
terms:
23
• The Zacks consensus long-term earnings growth estimates;
24
• The First Call consensus long-term earnings growth estimates; and
25
• The Value Line long-term earnings per share growth estimates.
26
32
Reed Direct
1
Q. HOW DID YOU CALCULATE THE HIGH AND LOW DCF RESULTS?
2
A.
I calculated the mean high DCF result using the maximum growth rate (i.e.,
3
the maximum of the Value Line, Zack’s, and First Call EPS growth rates) in
4
combination with the dividend yield for each of the Electric Proxy Group and
5
Combination Proxy Group companies. Thus, the mean high result reflects
6
the average maximum DCF result for the proxy group. I used a similar
7
approach to calculate the mean low results, using the minimum growth rate
8
for each company.
9
10
Q. WHAT ARE THE RESULTS OF YOUR DCF ANALYSIS?
11
A.
As noted in Exhibit__(JJR-1), Schedule 1 the mean DCF results for my
12
Electric Proxy Group, including flotation cost recovery, are 11.39 percent,
13
11.56 percent and 11.63 percent for the 30, 90, and 180-trading day periods,
14
respectively.
15
16
Q. DID
17
18
YOU CALCULATE THE
DCF
RESULTS FOR THE COMBINATION COMPANY
PROXY GROUP?
A.
Yes.
As noted in Exhibit__(JJR-1), Schedule 1 the mean DCF results,
19
including flotation cost recovery, for the Combination Proxy Group are 10.93
20
percent, 11.09 percent, and 11.15 percent for the 30, 90, and 180-trading day
21
periods, respectively.
22
23
Q. PLEASE
24
25
EXPLAIN HOW YOU CONSIDERED THE RESULTS FROM THESE TWO
ANALYSES.
A.
Consistent with the methodology that was approved by the Commission to
26
establish the ROE for the Company’s electric utility in Docket No.
27
E002/GR-08-1065, I calculated a weighted average DCF result based on the
33
Reed Direct
1
DCF results of the Electric Proxy Group and the Combination Proxy Group.
2
In that Order, the Commission approved an ROE that was estimated by
3
applying a 60.00 percent weighting to the DCF results for the Electric Proxy
4
Group and a 40.00 percent weighting to the DCF results of the Combination
5
Company Proxy Group. Applying these weightings to the results shown in
6
Exhibit ___(JJR-1), Schedule 1, the weighted mean DCF results for the 30,
7
90, and 180-day averaging periods were 11.21 percent, 11.37 percent, and
8
11.44 percent respectively, including flotation costs.
9
10
E. Flotation Cost Adjustment
11
Q. WHAT ARE FLOTATION COSTS?
12
A.
Flotation costs are the costs associated with the sale of new issues of common
13
stock. These costs include out-of-pocket expenditures for the preparation,
14
filing, underwriting, and other costs of issuance of common stock.
15
16
Q. WHY
17
18
IS IT IMPORTANT TO RECOGNIZE FLOTATION COSTS IN THE ALLOWED
ROE?
A.
In order to attract and retain new investors, a regulated utility must have the
19
opportunity to earn a return that is both competitive and compensatory. To
20
the extent that a company is denied the opportunity to recover prudently
21
incurred flotation costs, actual returns will fall short of required returns,
22
thereby diminishing its ability to attract adequate capital on reasonable terms.
23
24
Q. ARE FLOTATION COSTS PART OF THE UTILITY’S INVESTED COSTS OR PART OF
25
26
27
THE UTILITY’S EXPENSES?
A.
Flotation costs are part of the invested costs of the utility, which are properly
reflected on the balance sheet of the utility under “paid in capital.” They are
34
Reed Direct
1
not current expenses, and therefore are not reflected on the income
2
statement. Flotation costs, like investments in rate base or the issuance costs
3
of long-term debt, are incurred over time. As a result, the great majority of a
4
utility’s flotation costs is incurred prior to the test year, but remain part of the
5
cost structure that exists during the test year and beyond, and as such, should
6
be recognized for ratemaking purposes.
7
appropriate even if no new issuances are planned in the near future because
8
failure to allow such an adjustment may deny the Company the opportunity to
9
earn its required rate of return in the future.
Therefore, this adjustment is
10
11
Q. IS
12
13
THE NEED TO CONSIDER FLOTATION COSTS ELIMINATED BECAUSE THE
COMPANY IS A WHOLLY OWNED SUBSIDIARY OF XEI?
A.
No.
Although the Company is an operating subsidiary of XEI, it is
14
appropriate to consider flotation costs because the source of capital used by
15
the Company was the result of a public issuance by its parent organization,
16
which led to the issuance costs. To deny recovery of issuance costs associated
17
with the capital that is invested in the utility ultimately will penalize the
18
investors that fund the utility operations and will inhibit the utility’s ability to
19
obtain new equity capital at a reasonable cost. This is particularly important
20
in the case of the Company since it is planning significant capital expenditures
21
in the near term, and continued access to capital to fund such required
22
expenditures will be critical.
23
24
Q. DO
25
26
27
THE
DCF
AND
CAPM
MODELS ALREADY INCORPORATE INVESTOR
EXPECTATIONS OF A RETURN THAT COMPENSATES FOR FLOTATION COSTS?
A.
No.
All the models used to estimate the appropriate ROE assume no
“friction” or transaction costs, as these costs are not reflected in the market
35
Reed Direct
1
price (in the case of the DCF model) or risk premium (in the case of the
2
CAPM).
3
determining where within the range of reasonable returns the Company’s
4
return should fall.
Therefore, it is appropriate to consider flotation costs in
5
6
Q. HAS
7
8
THE
COMMISSION
RECOGNIZED THE NEED TO RECOVER FLOTATION
COSTS IN YEARS IN WHICH NO COMMON STOCK IS ISSUED?
A.
Yes. The Commission has recognized that common equity has an indefinite
9
life, and due to the indeterminate life of an equity issuance, flotation costs
10
should be recovered through a return adjustment, regardless of whether or
11
not an issuance occurs during or is planned for the test year.21 Moreover, the
12
Commission has authorized the recovery of flotation costs in several recent
13
cases.22
14
15
Q. HAS XEI INC. ISSUED EQUITY RECENTLY?
16
A.
Yes. XEI Inc. closed on an equity issuance of approximately $483 million
17
(21,850,000 shares of common stock) on August 10, 2010. As Mr. Tyson has
18
explained, the Company will need to access the equity market in the next
19
several years on a more regular basis than in the past.
20
21
Q. HOW DID YOU CALCULATE THE FLOTATION COST ADJUSTMENT?
22
A.
I modified the DCF calculation to provide a dividend yield that would
23
reimburse investors for issuance costs.
24
recognizes the costs of issuing equity that were incurred by the former
21
22
My flotation cost adjustment
Docket No. E017/GR-07-1178, Findings of Fact, Conclusions of Law, and Order at 57-58; Docket No.
G004/GR-04-1487, Findings of Fact, Conclusions of Law and Order at 11.
Docket No. E002/GR-08-1065, Findings of Fact, Conclusions of Law, and Order at 10-11; Docket No.
E017/GR-07-1178, Findings of Fact, Conclusions of Law, and Order at 57-58; Docket No. G004/GR-04-
36
Reed Direct
1
Northern States Power Company because that equity is now invested in the
2
Company.
3
Schedule 2, I calculate a flotation cost adjustment for the Company of 0.22
4
percent (i.e., 22 basis points) using both the Electric Proxy Group and the
5
Combination Proxy Group DCF results.
Based on the issuance costs provided in Exhibit__(JJR-1),
6
7
Q. IS
8
9
YOUR CALCULATION OF THE RECOVERY OF FLOTATION COSTS ALSO
CONSISTENT WITH THE COMMISSION’S PRIOR DETERMINATIONS?
A.
Yes. The Commission described the method that it uses in the Great Plains
10
Natural Gas 2004 rate case, saying that: “The adjustment was made by
11
dividing the expected dividend yield by (1 – percentage flotation costs)”.23 My
12
calculation matches the methodology that was approved by the Commission
13
in that case and that has been applied in subsequent cases.
14
15
Q. PLEASE SUMMARIZE THE RESULTS OF YOUR ANALYSIS INCLUDING FLOTATION
16
17
COSTS.
A.
As shown in Table 5, the mean weighted average DCF results of the Electric
18
Proxy Group and Combination Proxy Group based on 30, 90 and 180-day
19
averaging periods are 11.21 percent, to 11.44 percent, depending on the
20
observation interval chosen. Considering that NSP has greater operating risk
21
than the Electric Proxy Group and Combination Proxy Group, my range
22
which is established as the mean results using the 60 percent Electric Proxy
23
Group and 40 percent Combination Proxy Group, is conservative.
23
1487, Findings of Fact, Conclusions of Law and Order at 1; Docket No. E015/GR-08-415, Findings of
Fact, Conclusions of Law and Order at 37-39.
Docket No. G004/GR-04-1487, Findings of Fact, Conclusions of Law and Order, at 12.
37
Reed Direct
1
Table 5: DCF Results Adjusted for Flotation Costs24
Averaging Period
Electric Proxy Group
Mean Low
Mean
Mean High
30-Day Average
9.76%
11.39%
12.76%
90-Day Average
9.93%
11.56%
12.92%
180-Day Average
9.99%
11.63%
12.99%
30-Day Average
10.01%
10.93%
11.92%
90-Day Average
10.17%
11.09%
12.08%
Combination Proxy Group
180-Day Average
10.23%
11.15%
12.14%
Weighted Average DCF Result (60% Electric Proxy Group/40% Combination Proxy
Group)
30-Day Average
9.86%
11.21%
12.42%
90-Day Average
10.02%
11.37%
12.58%
180-Day Average
10.09%
11.44%
12.65%
2
3
Q. DID
4
5
YOU UNDERTAKE ANY ADDITIONAL ANALYSES TO SUPPORT YOUR
DCF
MODEL RESULTS?
A.
6
Yes, as also noted earlier, I considered the CAPM and the Risk Premium
approach as a means of assessing the reasonableness of my DCF results.
7
8
9
10
F.
CAPM Analysis
Q. PLEASE BRIEFLY DESCRIBE THE CAPITAL ASSET PRICING MODEL.
A.
The CAPM is a risk premium approach that estimates the cost of equity for a
11
given security as a function of a risk-free return plus a risk premium (to
12
compensate investors for the non-diversifiable or “systematic” risk of that
24
If the Administrative Law Judge’s Decision in Docket No. D-G-002/GR-09-1153 is upheld by the
Minnesota Public Service Commission, the application of the 79/21 percent weightings to my Electric
Proxy Group and Combination Proxy Group respectively would result in a range of mean ROEs of 11.30%
to 11.53% based on the 30, 90 and 180 day average results presented in Table 6 above.
38
Reed Direct
1
security).
As shown in Equation [3], the CAPM is defined by four
2
components, each of which theoretically must be a forward-looking estimate:
3
ke = rf + β(rm – rf) [3]
4
where:
5
ke = the required market ROE
6
β = Beta of an individual security
7
rf = the risk free rate of return
8
rm = the required return on the market as a whole.
9
10
In this specification, the term (rm – rf) represents the market risk premium.
11
According to the theory underlying the CAPM, since unsystematic risk can be
12
diversified away, investors should be concerned only with systematic or non-
13
diversifiable risk. Non-diversifiable risk is measured by Beta, which is defined
14
as:
15
β=
Covariance (re , rm )
[4]
Variance (rm )
16
The variance of the market return, noted in Equation [4], is a measure of the
17
uncertainty of the general market, and the covariance between the return on a
18
specific security and the market reflects the extent to which the return on that
19
security will respond to a given change in the market return. Thus Beta
20
represents the risk of the security relative to the market.
21
22
Q. HOW HAS THE CAPM BEEN AFFECTED BY CURRENT ECONOMIC CONDITIONS?
23
A.
Recent market conditions have affected the CAPM model in two important
24
ways.
First, the extraordinary loss in equity values experienced in 2008
25
actually reduced the Market Risk Premium when measured on a historical
26
basis. As often applied in the CAPM, the Market Risk Premium represents
39
Reed Direct
1
the difference in the arithmetic average total return on common stocks, and
2
the income-only return on long-term Government bonds, as reported by
3
Morningstar, Inc. (formerly, Ibbotson Associates). Consequently, the market
4
losses experienced in 2008 actually resulted in a decrease in the Risk Premium
5
from the prior year (as measured on a historical basis) from 7.10 percent to
6
6.50 percent.
7
Committee observations noted previously that the market risk premium has
8
increased in correspondence with a decrease in the Treasury bond yield. In
9
my view, the proposition that the premium required by equity investors would
10
decrease at the same time that equity market volatility was at historically high
11
levels is counter-intuitive. Indeed, the Commission noted in its recent Order
12
in Docket G007,011 /GR-08-835, that “…the CAPM model proved in this
13
case, as it has in the past, to be vulnerable to substantial and largely
14
inexplicable swings in outcome. When the OES attempted to repeat its earlier
15
CAPM analysis with updated data, the results pointed to an unreasonably low
16
return on equity, requiring the OES to substitute a different data source for a
17
critical input to yield a reasonable result.”25
That result is also contrary to the Federal Open Market
18
19
Second, as noted above, the risk free rate, “rf”, in the CAPM formula is
20
represented by the interest rate on long-term U.S. Treasury securities. Since
21
the 2008 financial dislocation, investors have reacted to market uncertainty by
22
investing in low-risk securities such as Treasury bonds. Consequently, the
23
first term in the model (i.e., the risk-free rate) is lower than it would have been
24
absent the elevated degree of risk aversion that has, at least in part, resulted in
25
historically low Treasury yields.
26
25
Docket No. G-007, 011/GR-08-835, Findings of Fact, Conclusions of Law, and Order, at 10-11.
40
Reed Direct
1
Q. WITH THOSE QUALIFICATIONS IN MIND, WHAT ASSUMPTIONS DID YOU USE IN
2
3
YOUR CAPM MODEL?
A.
Since the DCF and CAPM models both assume long-term investment
4
horizons, I used the 30-day, 90-day, and 180-day average yield on 30-year
5
Treasury Bonds as my estimate of the risk-free rate. For the equity risk
6
premium, I relied on the historical risk premium calculated using the long-
7
term average of the total return on large company stocks over the income
8
only portion of long term government bonds as reported by Morningstar for
9
the period from 1926-2009.26 This calculation results in a risk premium of
10
6.70 percent. Finally, for the Beta term, I used Betas from Value Line and
11
Bloomberg, both of which adjust their Beta estimates based on an average of
12
the raw, historical Beta and 1.0. This adjustment addresses the tendency of
13
the CAPM to underestimate the cost of capital for companies with
14
“unadjusted” or “raw” Betas significantly less than 1.0. For relatively low raw
15
Beta companies, such as regulated utilities, failure to take such adjustments
16
into consideration will result in an understatement of required returns. The
17
mean results of this analysis, which are presented in Exhibit__(JJR-1),
18
Schedule 3 range from 8.59 percent to 9.12 percent for the Electric Proxy
19
Group, and 8.75 percent to 9.28 percent for the Combination Proxy Group,
20
before consideration of flotation costs, well below the range of results
21
produced by other calculation methodologies.
22
26
Morningstar Inc., 2009 Ibbotson Stocks, Bonds, Bills and Inflation, Valuation Yearbook, Appendix A: Risk
Premia Over Time, Table A-1 (page 2 of 6), at 127.
41
Reed Direct
1
Q. DOES YOUR RECOMMENDATION SUBSTANTIALLY RELY ON THE CAPM MODEL
2
3
YOU PRESENTED IN EXHIBITS__(JJR-1), SCHEDULE 3?
A.
No, it does not. While I have calculated the CAPM using the approach
4
discussed above, I did not give any particular weight to those results for the
5
reasons that I have explained above.
6
7
8
G. Bond Yield Plus Risk Premium Analysis
Q. PLEASE
9
10
DESCRIBE THE BOND YIELD PLUS RISK PREMIUM APPROACH YOU
EMPLOYED.
A.
In general terms, this approach is based on the fundamental principal that
11
equity investors bear the residual risk associated with ownership and therefore
12
require a premium over the return they would have earned as a bondholder.
13
That is, since returns to equity holders are more risky than the returns to
14
bondholders, equity investors must be compensated to bear that risk. Risk
15
premium approaches therefore estimate the cost of equity as the sum of the
16
equity risk premium and the yield on a particular class of bonds. As noted in
17
my discussion of the CAPM, since the equity risk premium is not directly
18
observable, it typically is estimated using a variety of approaches, some of
19
which incorporate an ex-ante, or forward-looking estimate of the cost of
20
equity, and others that consider historical or ex-post estimates. Since we are
21
concerned with estimating the cost of equity for the Company, an alternative
22
approach is to use actual authorized returns for integrated electric utilities as
23
the historical measure of the cost of equity to determine the Risk Premium.
24
42
Reed Direct
1
Q. ARE
2
3
THERE OTHER CONSIDERATIONS THAT SHOULD BE ADDRESSED IN
CONDUCTING THIS ANALYSIS?
A.
Yes. In addition, it is important to recognize both academic literature and
4
market evidence indicating that the equity risk premium (as used in this
5
approach) is inversely related to the level of interest rates. That is, as interest
6
rates increase (decrease), the equity risk premium decreases (increases).
7
Consequently, it is important to develop an analysis that: (1) reflects the
8
inverse relationship between interest rates and the equity risk premium; and
9
(2) is based on more recent market conditions. Such an analysis can be
10
developed based on a regression of the risk premium as a function of
11
Treasury yields. If we let authorized integrated electric utility ROEs serve as
12
the measure of required equity returns and define the yield on the long-term
13
Treasury bond as the relevant measure of interest rates, the risk premium
14
simply would be the difference between those two points.27
15
16
Q. WHAT DID YOUR BOND YIELD PLUS EQUITY RISK PREMIUM ANALYSIS REVEAL?
17
A.
As shown on Chart 3, from 1992 through September 30, 2010 there was, in
18
fact, a strong negative relationship between risk premia and interest rates. To
19
estimate that relationship, I conducted a regression analysis using the
20
following equation:
21
RP = a + b(T)
22
[5]
where:
23
RP = Risk Premium (difference between allowed ROEs and 30-Year
24
Treasury Bond Yield)
27
See e.g., S. Keith Berry, Interest Rate Risk and Utility Risk Premia during 1982-93, Managerial and Decision
Economics, Vol. 19, No. 2 (March, 1998), in which the author used a methodology similar to the regression
approach described below, including using allowed ROEs as the relevant data source, and came to similar
conclusions regarding the inverse relationship between risk premia and interest rates. See also Robert S.
43
Reed Direct
1
a = Intercept term
2
b = Slope term
3
T = 30-Year Treasury Bond Yield
4
5
Data regarding allowed ROEs was derived from 390 rate cases from 1992
6
through the September 30, 2010 as reported by Regulatory Research
7
Associates. This equation’s coefficients were statistically significant at the 99
8
percent level.28
9
Chart 3: Risk Premium vs. Interest Rates-Linear Regression
8.00%
7.00%
y = -0.6449x + 0.0913
R² = 0.6943
Risk Premium
6.00%
5.00%
4.00%
3.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
8.00%
9.00%
30-Year Treasury Bond Yield
10
11
As shown in Exhibit__(JJR-1), Schedule 4 would range from 10.63 percent to
12
11.19 percent using forecasted Treasury bond yields. It is important to note,
13
however, that this estimate does not include the effect of the Company’s
14
specific risk factors, as discussed in the following section of my direct
15
testimony.
16
28
Harris, Using Analysts’ Growth Forecasts to Estimate Shareholders Required Rates of Return, Financial Management,
Spring 1986, at 66.
In order to ensure that the regression coefficients were not biased as a result of serially correlated error
terms, the equation presented in Exhibit___(JJR-1), Schedule 4 was also estimated using the Prais-Winsten
corrective routine. That equation continues to produce a negative slope coefficient and a ROE estimate of
approximately 10.64% to 11.19%.
44
Reed Direct
1
Q. DID YOU CONSIDER OTHER SPECIFICATIONS OF THE RISK PREMIUM MODEL?
2
A.
Yes, I did. As noted by Dr. Marlon Griffing in a recent case before the
3
Commission, it is possible that the relationship between the ROE and the risk
4
premium may be non-linear. Therefore, I also relied on the equation derived
5
from a logarithmic relationship. As shown in Chart 4 below, the R-squared of
6
the equation assuming the logarithmic relationship is approximately 0.68.
7
This value means that the equation explains approximately 68 percent of the
8
deviation from the regression line.29 As shown in Exhibit__(JJR-1), Schedule
9
4 would range from 10.68 percent to 11.12 percent using forecasted Treasury
10
bond yields.
11
12
Chart 4: Risk Premium vs. Interest Rates-Logarithmic Relationship
8.00%
7.00%
y = -0.036ln(x) - 0.0491
R² = 0.6823
Risk Premium
6.00%
5.00%
4.00%
3.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
8.00%
9.00%
13
29
This alternative was suggested by Dr. Marlon Griffing in Docket No. E008/GR-08-1075. Please note that
using a logarithmic approach to estimating the risk premium does not allow for the correction of serial
correlation.
45
Reed Direct
1
VII. RISK FACTORS
2
3
Q. DO THE MEAN DCF, CAPM, AND RISK PREMIUM RESULTS FOR THE ELECTRIC
4
PROXY GROUP AND COMBINATION PROXY GROUP PROVIDE AN APPROPRIATE
5
ESTIMATE OF THE COST OF EQUITY FOR THE COMPANY?
6
A.
No, the mean results do not necessarily provide an appropriate estimate of
7
the Company’s cost of equity. In my view, the Company’s business and
8
financial risks must be taken into consideration when determining where the
9
Company’s cost of equity falls within the range of results.
10
11
Q. WHAT ARE THE COMPANY’S PRIMARY BUSINESS RISK FACTORS?
12
A.
The principal business risks facing the Company are the effect of the
13
Company’s substantial capital expenditure plan as well as the financial and
14
regulatory risks related to this investment plan.
15
16
A.
17
Q. PLEASE SUMMARIZE THE COMPANY’S CAPITAL EXPENDITURE PLAN.
18
A.
The Company’s current projections include approximately $4.9 billion in
19
capital investment for the four year period from 2011 to 2014, as explained in
20
the Direct Testimony of Mr. Tyson. The Company’s capital expenditure plan
21
includes Minnesota’s renewable portfolio standard30 as well as additional
22
transmission, distribution and generation investment. Minnesota’s renewable
23
portfolio standard requires a minimum of 30.00 percent of the Company’s
24
retail electric sales to be generated by eligible energy technologies by the end
25
of the year 2020. In addition, the Company has substantial investment plans
26
for transmission facilities in connection with the CapX 2020 initiative.
30
Minn. Stat. § 216B.1691.
46
Reed Direct
1
Through this initiative, the Company’s portion of this project is expected to
2
be approximately $900 million of investment that is scheduled to begin in
3
2010 and will continue over a three to five year period.31 The Company’s
4
capital investment plans are discussed further by Company witness Ms. Judy
5
M. Poferl and by Mr. Tyson.
6
7
Q. HOW
8
9
IS THE
COMPANY’S
RISK PROFILE AFFECTED BY THE SUBSTANTIAL
INCREASE IN ITS PLANNED CAPITAL EXPENDITURES?
A.
As with any utility faced with a substantial capital expenditure plan, the
10
Company’s risk profile is adversely affected in two significant and related
11
ways: (1) the heightened level of investment increases the risk of under-
12
recovery, or the delayed recovery of the invested capital; and (2) an
13
inadequate authorized return would put downward pressure on key credit
14
metrics.
15
16
Q.
17
18
DO CREDIT RATING AGENCIES RECOGNIZE THE RISKS ASSOCIATED WITH
INCREASED CAPITAL EXPENDITURES?
A.
Yes, they do. From a credit perspective, the additional pressure on cash flows
19
associated with high levels of capital expenditures exerts corresponding
20
pressure on credit metrics and, therefore, credit ratings. S&P noted several
21
long term challenges for utilities’ financial health including: heavy
22
construction programs to address demand growth, declining capacity margins,
23
and aging infrastructure and regulatory responsiveness to mounting requests
24
for rate increases. S&P further noted that:
25
26
27
To sustain their current credit quality in the face of these longlived challenges, utilities need to have established—and be
able to maintain—a firm credit foundation. This will require a
31
Northern States Power Co., SEC Form 10-K, December 31, 2009, p.73.
47
Reed Direct
1
2
3
4
5
6
7
8
9
strong and effective working relationship among management,
regulators, and increasingly legislators and governors, in the
planning and execution of strategies. A comprehensive
vetting and understanding of the risks associated with the
regulatory mechanisms under which the utility will recover its
investment, which could include a cash return during
construction and timely recognition of volatile costs, will be
paramount in preserving creditworthiness.32
10
S&P specifically noted the risks associated with NSP’s capital expenditure
11
plan in its July 2010 rating of the Company. In that report, S&P noted that its
12
credit rating reflects in part the full cost recovery of larger construction
13
projects. In addition, S&P notes that the current stable outlook could be
14
revised to negative if construction projects are not completed on time and
15
budget or if expected rate recovery is less than expected.33 Therefore, to the
16
extent that the Company’s current regulatory structure cannot meet the
17
Company’s objectives, it will be necessary to change the structure to provide
18
the flexibility necessary to meet those objectives.
19
20
Q. ARE
21
22
YOU AWARE THAT THE
COMPANY
HAS REQUESTED THAT THE
COMMISSION APPROVE A STEP-UP IN ITS 2012 REVENUE REQUIREMENT?
A.
Yes, I am aware of the Company’s proposal and have considered this
23
proposal in my recommended cost of equity. As discussed in greater detail in
24
the testimony of Company witness Mr. Richard A. Ostberg’s testimony, the
25
Company is proposing to increase its 2012 revenue requirement to recover
26
the costs of specific capital and operations and maintenance costs in lieu of
27
filing a general rate case at that time.
28
32
Standard & Poor’s RatingsDirect, Industry Report Card: Utility Sectors In the Americas Remain Stable, While
Challenges Beset European, Australian, and New Zealand Counterparts, June 27, 2008, at 4.
48
Reed Direct
1
Q. ARE
2
3
EQUITY INVESTORS ALSO CONCERNED WITH COMPARATIVELY HIGH
LEVELS OF CAPITAL EXPENDITURES?
A.
Yes, equity investors also recognize the pressure on cash flows associated
4
with relatively high levels of capital expenditures. KeyBanc Capital Markets
5
(“KeyBanc”), for example, conducts a quarterly review of the electric utility
6
industry. In a recent report, KeyBanc noted that:
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
Much of the intermediate to long-term growth in the sector is
tied to large capital growth programs earning regulated
returns. During a period of lofty valuations and easy credit,
investors viewed these programs positively. Recent market
performance has made the equity and debt financing of these
large projects less attractive.
Although capital markets have improved since early 2009,
liquidity and capital costs remain a concern, as costs for credit
have generally become more expensive and available durations
have shrunk. Higher interest costs will likely continue to
pressure earnings until regulatory lag is better addressed. The
compression of stock price valuation multiples in the sector
has also negatively impacted the equity financing of capital
expenditures, as many names are trading below book value.
Credit and liquidity concerns have driven many companies to
revisit capital spending plans and reassess operational
efficiencies. The primary response has generally been to delay
projects, as opposed to outright cancellation. Initially,
reductions in capital programs were a function of lower
growth, which eliminated the need for growth-related capital
spending on items such as line extensions and new
substations. However, as difficult economic conditions
persist, the cuts have grown more extensive, with deferrals in
non-core maintenance spending, reevaluating the costeffectiveness of running older inefficient power plants, and
pursuing company restructurings or mergers.34
33
34
Standard & Poor’s Global Credit Portal RatingsDirect, Northern States Power Co., July 14, 2010, pp. 2-3.
KeyBanc Capital Markets Inc. Equity Research, Electric Utilities Quarterly 1Q10, June 2010, at 7.
49
Reed Direct
1
Q. HOW
2
3
DOES
THE
LEVEL
OF
THE
COMPANY’S
EXPECTED
CAPITAL
EXPENDITURES COMPARE TO THE PROXY GROUP?
A.
In order to reasonably make that comparison, as shown in Exhibit__(JJR-1),
4
Schedule 5, I calculated the ratio of expected capital expenditures to net
5
assets35 for each of the companies in the Electric Proxy Group. For the
6
projected period from 2010-2013, I performed that calculation using the
7
Company’s projected capital expenditures and its total net assets as of
8
December 31, 2009. As shown in Schedule 5, the Company’s relative level of
9
capital expenditures is between 1.4 and 2.7 times the projected investments of
10
the Electric Proxy Group.
11
expenditures of the Company and my Electric Proxy Group.
35
Chart 5 compares the projected capital
Source: Value Line and Xcel and the Company 2008 SEC Forms 10-K.
50
Reed Direct
1
Chart 5: Comparison of Capital Expenditures36
2009-2013 Projected CAPEX/Net Plant
120.00%
100.00%
80.00%
60.00%
40.00%
20.00%
0.00%
Source: Value Line and Company Data
2
3
4
Q. WHAT ARE YOUR CONCLUSIONS REGARDING THE EFFECT OF THE COMPANY’S
5
6
CAPITAL SPENDING PLANS ON ITS RISK PROFILE?
A.
It is clear that on a relative basis, the Company’s capital expenditure program
7
is significant. This program, which is necessary to maintain system reliability,
8
meet environmental legislation, and support future growth, could materially
9
dilute the Company’s current earnings and cash flows. It also is clear that the
10
financial community recognizes the additional risks associated with substantial
11
capital expenditures and that those risks are reflected in market valuation
12
multiples. In my view, these factors suggest a comparatively high level of risk
13
vis-à-vis the Electric Proxy Group and the Combination Proxy Group.
14
36
Source: Proxy group data based on Value Line, Company data based on 2009 10K and Company provided
information.
51
Reed Direct
1
VIII. CAPITAL STRUCTURE
2
3
Q. WHAT IS THE COMPANY’S PROJECTED CAPITAL STRUCTURE?
4
A.
The Company’s projected 2011 Test Year capital structure consists of 52.56
5
percent common equity, 46.30 percent long-term debt and 1.14 percent short-
6
term debt.37 As discussed in greater detail in the Direct Testimony of Mr.
7
Tyson, the Company’s capital structure finances both its electric and gas
8
utility operations.
9
10
Q. PLEASE DISCUSS YOUR ANALYSIS OF THE CAPITAL STRUCTURES OF THE PROXY
11
12
GROUP COMPANIES.
A.
In order to assess the reasonableness of the Company’s proposed capital
13
structure, I also reviewed the capitalization ratios of the individual utility
14
operating companies owned and operated (and for which separate financial
15
information is available) by the respective Electric Proxy Group and
16
Combination Proxy Group companies.
17
18
I calculated the average capital structure for each of the companies on a
19
quarterly basis for the eight quarters for the period beginning with the third
20
quarter of 2008 through the second quarter of 2010, using the capital
21
structures of the operating utility companies owned and operated by each of
22
my Electric and Combination Proxy Group. I then calculated a range of
23
weighted average equity ratios based on the mean, mean high and mean low
24
equity ratios of the Electric Proxy Group and the Combination Proxy
25
Groups.
26
37
See Exhibit __(GET-1), Schedule 2.
52
Reed Direct
1
As noted previously, I considered my assessment of the Company’s
2
proposed capital structure and equity ratio in my analysis and
3
recommendation of the Company’s ROE.
4
5
Q. PLEASE SUMMARIZE THE RESULTS OF YOUR ANALYSIS.
6
A.
As shown in Exhibit__(JJR-1), Schedule 6, the Company’s proposed equity
7
ratio of 52.56 percent is within the range of the equity ratios established by
8
my Electric and Combination Proxy Groups. Furthermore, the Company’s
9
long-term and short-term debt ratios of 46.30 percent and 1.14 percent
10
respectively are well within the range of the ratios for the Electric Proxy
11
Group and Combination Proxy Group companies.
12
Company’s proposed capital structure is within the range established by my
13
proxy groups.
Thus, overall, the
14
15
IX. CONCLUSION AND RECOMMENDATION
16
17
Q. WHAT IS YOUR CONCLUSION REGARDING A FAIR RETURN ON EQUITY FOR THE
18
19
COMPANY?
A.
My recommended ROE considers the results of the DCF and Risk Premium
20
models, summarized in Table 6 below, as well as the costs associated with the
21
issuance of common stock. As discussed previously, I have considered the
22
fact that investors are aware that the Company is a combination electric and
23
gas utility that derives more than 90 percent of its net income from its electric
24
operations and that the Commission recognized this fact and considered the
25
results of combination companies in the Company’s recent electric rate case.
26
In developing my recommendation of the appropriate ROE for the Company,
27
I considered the results of both my Electric Proxy Group and my
53
Reed Direct
1
Combination Proxy Group. Consistent with the Commission’s determination
2
in Docket No. E002/GR-08-1065, I applied a greater weight to the Electric
3
Proxy Group.
4
5
Investors are also aware of the Company’s very extensive investment plans
6
and that the Company is focused primarily on its electric operations, along
7
with the financial risks associated with these plans.
8
consideration the regulatory environment of utilities, particularly in a time of
9
increased financial risk posed by substantial investments. The Company’s
10
substantial investment plans increase the risk of the Company relative to both
11
the Electric Proxy Group and the Combination Proxy Group.
Investors take into
12
13
The DCF results presented in the remainder of my Direct Testimony indicate
14
that a conservative range of the cost of equity for NSP is from 11.21 percent
15
to 11.44 percent, depending on the observation interval chosen (30, 90 and
16
180 days), based on the weighted average DCF results of the Electric Proxy
17
Group and the Combination Proxy Group. This range, which is established
18
based on my mean DCF results, is conservative when considering the
19
increased operating risk of NSP as compared with the proxy group
20
companies. Based on these factors, an 11.25 percent ROE represents a
21
conservative estimate of the return required to invest in a utility with a risk
22
profile comparable to the Company.
54
Reed Direct
1
Table 6: Summary of Analytical Results
Mean Low
Mean
Mean High
11.39%
11.56%
12.76%
12.92%
11.63%
12.99%
10.93%
11.09%
11.92%
12.08%
Electric Proxy Group (including flotation costs)
Constant Growth DCF – 30-Day Average
9.76%
9.93%
Constant Growth DCF – 180-Day
Average
9.99%
Combination Proxy Group(including flotation costs)
10.01%
10.17%
Average
10.23%
11.15%
12.14%
Weighted Average DCF result (60% Electric Proxy Group 40% Combination Proxy
Group)
9.86%
11.21%
12.42%
10.02%
11.37%
12.58%
Average
10.09%
11.44%
12.65%
2
3
Q. DOES THIS CONCLUDE YOUR TESTIMONY?
4
A.
Yes, it does.
55
Reed Direct
Exhibit___(JJR-1), Attachment A
John J. Reed
Chairman and Chief Executive Officer
John J. Reed is a financial and economic consultant with more than 30 years of experience in the energy
industry. Mr. Reed has also been the CEO of an NASD member securities firm, and Co-CEO of the nation’s
largest publicly traded management consulting firm (NYSE: NCI). He has provided advisory services in the
areas of mergers and acquisitions, asset divestitures and purchases, strategic planning, project finance,
corporate valuation, energy market analysis, rate and regulatory matters and energy contract negotiations to
clients across North and Central America. Mr. Reed’s comprehensive experience includes the development
and implementation of nuclear, fossil, and hydroelectric generation divestiture programs with an aggregate
valuation in excess of $20 billion. Mr. Reed has also provided expert testimony on financial and economic
matters on more than 150 occasions before the FERC, Canadian regulatory agencies, state utility regulatory
agencies, various state and federal courts, and before arbitration panels in the United States and Canada.
After graduation from the Wharton School of the University of Pennsylvania, Mr. Reed joined Southern
California Gas Company, where he worked in the regulatory and financial groups, leaving the firm as Chief
Economist in 1981. He served as executive and consultant with Stone & Webster Management Consulting
and R.J. Rudden Associates prior to forming REED Consulting Group (RCG) in 1988. RCG was acquired
by Navigant Consulting in 1997, where Mr. Reed served as an executive until leaving Navigant to join
Concentric as Chairman and Chief Executive Officer.
REPRESENTATIVE PROJECT EXPERIENCE
Executive Management
As an executive-level consultant, worked with CEOs, CFOs, other senior officers, and Boards of Directors of
many of North America’s top electric and gas utilities, as well as with senior political leaders of the U.S. and
Canada on numerous engagements over the past 25 years. Directed merger, acquisition, divestiture, and
project development engagements for utilities, pipelines and electric generation companies, repositioned
several electric and gas utilities as pure distributors through a series of regulatory, financial, and legislative
initiatives, and helped to develop and execute several “roll-up” or market aggregation strategies for companies
seeking to achieve substantial scale in energy distribution, generation, transmission, and marketing.
Financial and Economic Advisory Services
Retained by many of the nation’s leading energy companies and financial institutions for services relating to
the purchase, sale or development of new enterprises. These projects included major new gas pipeline
projects, gas storage projects, several non-utility generation projects, the purchase and sale of project
development and gas marketing firms, and utility acquisitions. Specific services provided include the
development of corporate expansion plans, review of acquisition candidates, establishment of divestiture
standards, due diligence on acquisitions or financing, market entry or expansion studies, competitive
assessments, project financing studies, and negotiations relating to these transactions.
Litigation Support and Expert Testimony
Provided expert testimony on more than 150 occasions in administrative and civil proceedings on a wide
range of energy and economic issues. Clients in these matters have included gas distribution utilities, gas
pipelines, gas producers, oil producers, electric utilities, large energy consumers, governmental and regulatory
agencies, trade associations, independent energy project developers, engineering firms, and gas and power
marketers. Testimony has focused on issues ranging from broad regulatory and economic policy to virtually
all elements of the utility ratemaking process. Also frequently testified regarding energy contract
interpretation, accepted energy industry practices, horizontal and vertical market power, quantification of
damages, and management prudence. Have been active in regulatory contract and litigation matters on
virtually all interstate pipeline systems serving the U.S. Northeast, Mid-Atlantic, Midwest, and Pacific regions.
Also served on FERC Commissioner Terzic’s Task Force on Competition, which conducted an industry-wide
investigation into the levels of and means of encouraging competition in U.S. natural gas markets.
Represented the interests of the gas distributors (the AGD and UDC) and participated actively in developing
and presenting position papers on behalf of the LDC community.
Resource Procurement, Contracting and Analysis
On behalf of gas distributors, gas pipelines, gas producers, electric utilities, and independent energy project
developers, personally managed or participated in the negotiation, drafting, and regulatory support of
hundreds of energy contracts, including the largest gas contracts in North America, electric contracts
representing billions of dollars, pipeline and storage contracts, and facility leases.
These efforts have resulted in bringing large new energy projects to market across North America, the
creation of hundreds of millions of dollars in savings through contract renegotiation, and the regulatory
approval of a number of highly contested energy contracts.
Strategic Planning and Utility Restructuring
Acted as a leading participant in the restructuring of the natural gas and electric utility industries over the past
fifteen years, as an adviser to local distribution companies (LDCs), pipelines, electric utilities, and independent
energy project developers. In the recent past, provided services to many of the top 50 utilities and energy
marketers across North America. Managed projects that frequently included the redevelopment of strategic
plans, corporate reorganizations, the development of multi-year regulatory and legislative agendas, merger,
acquisition and divestiture strategies, and the development of market entry strategies. Developed and
supported merchant function exit strategies, marketing affiliate strategies, and detailed plans for the functional
business units of many of North America’s leading utilities.
PROFESSIONAL HISTORY
Concentric Energy Advisors, Inc. (2002 – Present)
Chairman and Chief Executive Officer
CE Capital Advisors (2004 – Present)
Chairman, President, and Chief Executive Officer
Navigant Consulting, Inc. (1997 – 2002)
President, Navigant Energy Capital (2000 – 2002)
Executive Director (2000 – 2002)
Co-Chief Executive Officer, Vice Chairman (1999 – 2000)
Executive Managing Director (1998 – 1999)
President, REED Consulting Group, Inc. (1997 – 1998)
REED Consulting Group (1988 – 1997)
Chairman, President and Chief Executive Officer
R.J. Rudden Associates, Inc. (1983 – 1988)
Vice President
Stone & Webster Management Consultants, Inc. (1981 – 1983)
Senior Consultant
Consultant
Southern California Gas Company (1976 – 1981)
Corporate Economist
Financial Analyst
Treasury Analyst
EDUCATION AND CERTIFICATION
B.S., Economics and Finance, Wharton School, University of Pennsylvania, 1976
Licensed Securities Professional: NASD Series 7, 63, and 24 Licenses
BOARDS OF DIRECTORS (PAST AND PRESENT)
Concentric Energy Advisors, Inc.
Navigant Consulting, Inc.
Navigant Energy Capital
Nukem, Inc.
New England Gas Association
R. J. Rudden Associates
REED Consulting Group
AFFILIATIONS
National Association of Business Economists
International Association of Energy Economists
American Gas Association
New England Gas Association
Society of Gas Lighters
Guild of Gas Managers
Expert Testimony of John J. Reed
SPONSOR
Alaska Public Utilities Commission
Chugach Electric
Chugach Electric
Chugach Electric
Chugach Electric
California Energy Commission
Southern California Gas Co.
California Public Utility Commission
Pacific Gas Transmission Co.
Pacific Gas Transmission Co.
Colorado Public Utilities Commission
AMAX Molybdenum
AMAX Molybdenum
Xcel Energy
CT Dept. of Public Utilities Control
Connecticut Natural Gas
United Illuminating
Southern Connecticut Gas
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
12/86
6/87
12/87
2/88
Chugach Electric
Enstar Natural Gas Company
Enstar Natural Gas Company
Chugach Electric
Docket No. U-86-11
Docket No. U-87-2
Docket No. U-87-42
Docket No. U-87-35
Cost Allocation
Tariff Design
Gas Transportation
Cost of Capital
8/80
Docket No. 80-BR-3
Gas Price Forecasting
3/80
10/91
7/92
Pacific Gas & Electric Co.
TY 1981 G.R.C.
App. 89-04-033
A. 92-04-031
Cost of Service, Inflation
Rate Design
Rate Design
2/90
11/90
8/04
Commission Rulemaking
Commission Rulemaking
Xcel Energy
Docket No. 89R-702G
Docket No. 90R-508G
Docket No. 031-134E
Gas Transportation
Gas Transportation
Cost of Debt
12/88
3/99
2/04
4/05
5/06
United Illuminating
Gas Purchasing Practices
Nuclear Plant Valuation
LNG/Trunkline
LNG/Trunkline
8/08
Docket No. 88-08-15
Docket No. 99-03-04
Docket No. 00-12-08
Docket No. 05-03-17
Docket No. 05-0317PH01
Docket No. 06-05-04
CONCENTRIC ENERGY ADVISORS, INC.
PAGE 1
Peaking Service Agreement
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
Divestiture of Gen. Assets
& Purchase Power
Contracts (Direct)
& Purchase Power
Contracts (Supplemental
Direct)
& Purchase Power
Contracts (Rebuttal)
District Of Columbia PSC
Potomac Electric Power Company
3/99
Potomac Electric Power
Company
Docket No. 945
5/99
Company
Docket No. 945
7/99
Company
Docket No. 945
Fed’l Energy Regulatory Commission
Safe Harbor Water Power Corp.
8/82
Safe Harbor Water Power Corp.
Western Gas Interstate Company
5/84
Southern Union Gas
4/87
Western Gas Interstate
Company
El Paso Natural Gas Company
11/87
Penn-York Energy Corporation
AMAX Magnesium
12/88
Questar Pipeline Company
Western Gas Interstate Company
6/89
Company
Associated CD Customers
12/89
CNG Transmission
Utah Industrial Group
9/90
Questar Pipeline Company
Docket No. RP84-77
Docket No. RP87-16000
Docket No. RP88-93000, Phase II
PAGE 2
Wholesale Electric Rate
Increase
Load Fcst. Working Capital
Take-or-Pay Costs
Cost Alloc./Rate Design
Cost Alloc./Rate Design,
Open-Access
Transportation
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
Gas Markets, Rate Design,
Cost of Capital, Capital
Structure
Electric Generation Markets
Iroquois Gas Trans. System
8/90
Iroquois Gas Transmission
System
Docket No. CP89-634000/001; CP89-815-000
Boston Edison Company
1/91
Cincinnati Gas and Electric Co., Union
Light,
Heat and Power Company, Lawrenceburg
Gas Company
Ocean State Power II
7/91
Texas Gas Transmission Corp.
Docket No. ER91-243000
Docket No. RP90-104000, RP88-115-000,
RP90-192-000
7/91
Ocean State Power II
ER89-563-000
Brooklyn Union/PSE&G
7/91
Texas Eastern
RP88-67, et al
Northern Distributor Group
9/92
RP92-1-000, et al
Canadian Association of Petroleum
Producers
and Alberta Pet. Marketing Comm.
Colonial Gas, Providence Gas
10/92
Northern Natural Gas
Company
Lakehead Pipe Line Co. L.P.
IS92-27-000
Rate Case Analysis
Cost of Service
7/93
Algonquin Gas Transmission
RP93-14
Colonial Gas, Providence Gas
8/93
Algonquin Gas Transmission
RP93-14 – Rebuttal
RP94-72-000
Transcontinental Gas Pipeline
Corporation
Pacific Gas Transmission
Cost Allocation, Rate
Design
Cost Allocation, Rate
Design
Cost of Service and Rate
Design
Rate Design, Firm to
Wellhead
Rolled-In vs. Incremental
Rates
94
Transco Customer Group
1/94
2/94
PAGE 3
Comparability of Svc.
Competitive Market
Analysis, Self-dealing
Market Power,
Comparability of Service
Cost of Service
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
Docket Nos. RP93-151000, RP94-39-000,
RP94-197-000, RP94309-000
RP94-149-000
Docket Nos. RP93-151000, RP94-39-000,
RP94-197-000, RP94309-000
RP93-151
GSR Costs
RP92-18-000
RP97-126-000
Stranded Costs
Cost of Service, Rate
Design
Market Power Analysis –
Merger
Tennessee GSR Group
1/95
Tennessee Gas Pipeline
Company
Tennessee GSR Customer Group
2/95
3/95
Company
ProGas and Texas Eastern
1/96
Company
El Paso Natural Gas Company
System, L.P.
Boston Edison Company/
Commonwealth Energy System
PG&E and SoCal Gas
Iroquois Gas Transmission System, L.P.
96
97
BEC Energy - Commonwealth Energy
System
2/99
Central Hudson Gas & Electric,
Consolidated Co. of New York, Niagara
Mohawk Power Corporation, Dynegy
Power Inc.
10/00
Wyckoff Gas Storage
Indicated Shippers/Producers
12/02
10/03
Central Hudson Gas & Electric,
Consolidated Co. of New York,
Niagara Mohawk Power
Corporation, Dynegy Power
Inc.
Wyckoff Gas Storage
Northern Natural Gas
Maritimes & Northeast Pipeline
6/04
ISO New England
8/04
ISO New England
Transwestern Pipeline Company, LLC
9/06
Transwestern Pipeline
Company, LLC
EC99-___-000
Rate Design
GSR Costs
Declaration
Docket No. EC00-___
Market Power 203/205
Filing
CP03-33-000
Docket No. ER03-563030
Need for Storage Project
Ad Valorem Tax Treatment
PAGE 4
Rolled-In Rates
Cost of New Entry
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
Market Assessment, natural
gas transportation; rate
setting
Business risks; extraordinary
and non-recurring events
pertaining to discretionary
revenues
Affidavit re: Impact of
Preferential Rate
Portland Natural Gas Transmission System
6/08
Portland Natural Gas
Transmission System
Portland Natural Gas Transmission System
5/10
Portland Natural Gas
Transmission System
Morris Energy
7/10
Morris Energy
Docket No. RP10-
Florida Public Service Commission
Florida Power and Light Co.
10/07
5/08
3/09
Florida Power & Light Co.
Docket No. 070650-EI
3/09
3/10; 5/10, Florida Power & Light Co.
8/10
Florida Senate Committee on Communication, Energy and Utilities
2/09
Hawaii Public Utility Commission
Hawaiian Electric Light Company, Inc.
6/00
Hawaiian Electric Light
(HELCO)
Company, Inc.
Indiana Utility Regulatory Commission
Northern Indiana Public Service Company
10/01
Northern Indiana Public Service
Company
01/08
Cause No. 43396
08/08
Company
Company
Need for new nuclear plant
New Nuclear cost recovery
Benchmarking in support of
ROE
Securitization
Cause No. 41746
Standby Charge
Docket No. 99-0207
Direct Testimony, Valuation
of Electric Generating
Facilities
Asset Valuation
Cause No. 43526
PAGE 5
Fair Market Value
Assessment
SPONSOR
Iowa Utilities Board
Interstate Power and Light
DATE
7/05
CASE/APPLICANT
DOCKET NO.
SUBJECT
Docket No. SPU-05-15
Sale of Nuclear Plant
Docket No. SPU-06-5
Docket No. SPU-06-6
Docket No. SPU-06-10
Docket No. SPU-06-8
Docket No. SPU-06-7
Public Benefits
Public Benefits
Public Benefits
Public Benefits
Public Benefits
Maine Public Utility Commission
Northern Utilities
5/07
5/07
5/07
5/07
5/07
Interstate Power and Light and
FPL Energy Duane Arnold,
LLC
City of Everly, Iowa
City of Kalona, Iowa
City of Wellman, Iowa
City of Terril, Iowa
City of Rolfe, Iowa
5/96
Granite State and PNGTS
Docket No. 95-480, 95481
Transportation Service and
PBR
Maryland Public Service Commission
Eastalco Aluminum
3/82
8/99
Potomac Edison
Company
Docket No. 7604
Docket No. 8796
Cost Allocation
Stranded Cost & Price
Protection (Direct)
Mass. Department of Public Utilities
Haverhill Gas
5/82
Haverhill Gas
Docket No. DPU
#1115
Cost of Capital
New England Energy Group
Energy Consortium of Mass.
1/87
9/87
Commission Investigation
Commonwealth Gas Company
Mass. Institute of Technology
Energy consortium of Mass.
PG&E Bechtel Generating Co./
Constellation Holdings
Coalition of Non-Utility Generators
12/88
3/89
10/91
Middleton Municipal Light
Boston Gas
Docket No. DPU-87122
DPU #88-91
DPU #88-67
DPU #91-131
Cambridge Electric Light Co. &
Commonwealth Electric Co.
DPU 91-234
EFSC 91-4
PAGE 6
Gas Transportation Rates
Rate Design
Valuation of Environmental
Externalities
Review Integrated Resource
Management Filing
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
DPU #92-154
Gas Purchase Contract
Approval
DPU #92-130
DPU #92-146
Least Cost Planning
RFP Evaluation
DPU #92-142
DPU #92-167
DPU #92-153
DPU #92-166
DPU #92-144
DPU #93-187
RFP Evaluation
RFP Evaluation
RFP Evaluation
RFP Evaluation
RFP Evaluation
Gas Purchase Contract
Approval
Docket No. 93-129
Integrated Resource
Planning
Surplus Capacity
Stranded Costs – Direct
Unbundled Rates
Holding Company
Corporate Structure
Regulatory Issues
Marketing for divestiture of
its generation business.
Fossil Generation
Divestiture
Nuclear Generation
Divestiture
The Berkshire Gas Company
Essex County Gas Company
Fitchburg Gas and Elec. Light Co.
5/92
7/92
7/92
Colonial Gas Company
Fitchburg Gas and Electric Company
Bay State Gas Company
7/92
7/92
7/92
7/92
7/92
11/93
10/93
Fitchburg Gas & Elec. Light
Co.
Boston Edison
The Williams/Newcorp
Generating Co.
West Lynn Cogeneration
L’Energia Corp.
DLS Energy, Inc.
CMS Generation Co.
Concord Energy
Colonial Gas Company
Fitchburg Gas and Electric Co.
Bay State Gas Company
Hudson Light & Power Department
94
4/95
5/96
8/97
Boston Edison
Hudson Light & Power Dept.
DPU #94-49
DPU #94-176
Docket No. 96-70
D.P.U. No. 97-63
Berkshire Gas Company
Eastern Edison Company
6/98
8/98
Berkshire Gas Mergeco Gas Co.
Montaup Electric Company
D.T.E. 98-87
D.T.E. 98-83
98
D.T.E. 97-113
98
D.T.E. 98-119
PAGE 7
SPONSOR
CASE/APPLICANT
DOCKET NO.
SUBJECT
12/98
9/07,
12/07
Montaup Electric Company
NStar, Bay State Gas, Fitchburg
G&E, NE Gas, W. MA Electric
D.T.E. 99-9
DPU 07-50
Decoupling
Mass. Energy Facilities Siting Council
Mass. Institute of Technology
Silver City Energy Ltd. Partnership
1/89
9/90
11/91
M.M.W.E.C.
Boston Edison
Silver City Energy
EFSC-88-1
EFSC-90-12
D.P.U. 91-100
Least-Cost Planning
Electric Generation Mkts
State Policies; Need for
Facility
Michigan Public Service Commission
Detroit Edison Company
9/98
Case No. U-11726
Consumers Energy Company
Minnesota Public Utilities Commission
Xcel Energy/No. States Power
8/06
Consumers Energy Company
Case No. U-14992
Market Value of Generation
Assets
9/04
Xcel Energy/No. States Power
8/05
Northern States Power Company
d/b/a Xcel Energy
d/b/a Xcel Energy
d/b/a Xcel Energy
Northern States Power
11/05
Interstate Power and Light and
FPL Energy Duane Arnold,
LLC
Company
NSP v. Excelsior
Docket No. G002/GR04-1511
Docket No. E001/PA05-1272
11/09
Eastern Edison Company
NStar
DATE
09/06
11/06
11/08
Company
Company
Company
Docket No. E002/GR05-1428
Docket No. E6472/M05-1993
Docket No. E002/GR08-1065
PAGE 8
NRG Impacts
NRG Impacts on Debt
Costs
Industry Norms and
Financial Impacts
Return on Equity
Return on Equity
Return on Equity
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
Gas Purchasing Practices;
Prudence
Structure
Missouri Public Service Commission
Missouri Gas Energy
1/03
Missouri Gas Energy
Case No. GR-2001-382
Aquila Networks
2/04
Aquila-MPS, Aquila_L&P
Aquila Networks
2/04
Aquila-MPS, Aquila_L&P
Missouri Gas Energy
11/05
Missouri Gas Energy
Case Nos. ER-20040034
HR-2004-0024
Case No. GR-20040072
Case Nos. GR-2002348
GR-2003-0330
10/82
Great Falls Gas Company
Docket No. 82-4-25
Gas Rate Adjust. Clause
2/87
Docket No. GH-1-87
Gas Export Markets
Docket No. GH-2-87
Docket No. GH-5-89
RH-2-91
RH3-93
Gas Export Markets
Gas Export Markets
Pipeline Valuation, Toll
Cost of Capital
Market Study
Market Study
Natural Gas Demand
Analysis
Segmented Service
Market Study
Montana Public Service Commission
Great Falls Gas Company
Nat. Energy Board of Canada
Alberta-Northeast
Alberta-Northeast
Alberta-Northeast
Indep. Petroleum Association of Canada
The Canadian Association of Petroleum
Producers
Alliance Pipeline L.P.
11/87
1/90
1/92
11/93
Alberta Northeast Gas Export
Project
TransCanada Pipeline
TransCanada Pipeline
Interprovincial Pipe Line, Inc.
Transmountain Pipe Line
6/97
97
2/02
Alliance Pipeline L.P.
Sable Offshore Energy Project
GH-3-97
GH-6-96
GH-3-2002
TransCanada Pipelines
Brunswick Pipeline
TransCanada Pipelines Ltd.
8/04
9/06
3/07
TransCanada Pipelines
Brunswick Pipeline
TransCanada Pipelines Ltd.:
Gros Cacouna Receipt Point
Application
RH-3-2004
GH-1-2006
RH-1-2007
PAGE 9
Structure
Capacity Planning
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
3/08
Repsol Energy Canada Ltd
GH-1-2008
Market Study
1/08
Atlantic Wallboard/JD Irving
Co.
Atlantic Wallboard/Flakeboard
MCTN #298600
Rate Setting for EGNB
File OF-Tolls-Group1M124-2010-01 01
Ratemaking treatment of
Escrow Account
6/89
5/90
6/90
12/90
7/90
P.S. Co. of New Hampshire
Northeast Utilities
Eastern Utilities Associates
EnergyNorth Natural Gas
Docket No. DR89-091
Docket No. DR89-244
Docket No. DF89-085
Docket No. DE90-166
Docket No. DR90-187
Northern Utilities, Inc.
New Jersey Board of Public Utilities
12/91
Docket No. DR91-172
Fuel Costs
Merger & Acq. Issues
Merger & Acq. Issues
Special Contracts,
Discounted Rates
Generic Discounted Rates
Hilton/Golden Nugget
Golden Nugget
New Jersey Natural Gas
12/83
3/87
2/89
1/91
8/91
Atlantic Electric
Atlantic Electric
B.P.U. 832-154
B.P.U. No. 837-658
B.P.U. GR89030335J
B.P.U. GR90080786J
B.P.U. GR91081393J
South Jersey Gas
4/93
4/94
South Jersey Gas
New Jersey Utilities Association
Morris Energy Group
New Jersey American Water Co.
9/96
11/09
4/10
Morris Energy Group
New Jersey American Water Co.
B.P.U. GR93040114J
BRC Dock No.
GR080334
BPU AX96070530
BPU GR 09050422
BPU WR 1040260
Repsol Energy Canada Ltd
New Brunswick Energy and Utilities Board
Atlantic Wallboard/JD Irving Co
Atlantic Wallboard/Flakeboard
Maritimes and Northeast Pipeline
NH Public Utilities Commission
Bus & Industry Association
Bus & Industry Association
09/09,
6/10, 7/10
7/10
Rate Setting for EGNB
PAGE 10
Line Extension Policies
Line Extension Policies
Rate Design; Weather
Norm. Clause
Revised levelized gas
adjustment
PBOP Cost Recovery
Discriminatory Rates
Tariff Rates and Revisions
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
New Mexico Public Service Commission
Gas Company of New Mexico
11/83
Public Service Co. of New
Mexico
Docket No. 1835
New York Public Service Commission
Iroquois Gas. Transmission
12/86
Case No. 70363
Gas Markets
Brooklyn Union Gas Company
8/95
System
Brooklyn Union Gas Company
Case No. 95-6-0761
Central Hudson, ConEdison and Niagara
Mohawk
9/00
Central Hudson, ConEdison
and Niagara Mohawk
Panel on Industry
Directions
Section 70
Central Hudson, New York State Electric
& Gas, Rochester Gas & Electric
5/01
Rochester Gas & Electric
12/03
01/04
Joint Petition of NiMo,
NYSEG, RG&E, Central
Hudson, Constellation and Nine
Mile Point
Rochester Gas and Electric and NY State
Electric & Gas Corp
2/10
NY State Electric & Gas Corp
Oklahoma Corporation Commission
Oklahoma Natural Gas Company
6/98
Oklahoma Gas & Electric Company
9/05
Oklahoma Gas & Electric Company
03/08
Oklahoma Natural Gas
Company
Oklahoma Gas & Electric
Company
Oklahoma Gas & Electric
Company
Case No. 96-E-0909
Case No. 96-E-0897
Case No. 94-E-0098
Case No. 94-E-0099
Case No. 01-E-0011
Section 70, Rebuttal
Testimony
Case No. 03-E-1231
Case No. 03-E-0765
Case No. 02-E-0198
Case No. 03-E-0766
Case No. 09-E-0715
Case No. 09-E-0716
Case No. 09-E-0717
Case No. 09-E-0718
Sale of Nuclear Plant;
Ratemaking Treatment of
Sale
Depreciation policy
Case PUD No.
980000177
Cause No. PUD
200500151
Cause No. PUD
200800086
Evaluate their use of storage
PAGE 11
Prudence of McLain
Acquisition
Acquisition of Redbud
generating facility
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
Ontario Energy Board
Market Hub Partners Canada, L.P.
5/06
Natural Gas Electric Interface
Roundtable
File No. EB-2005-0551
Market-based Rates For
Storage
Pennsylvania Public Utility Commission
ATOC
4/95
Equitrans
Tariff Changes
ATOC
3/96
Equitrans
Docket No. R00943272
Docket No. P00940886
Rhode Island Public Utilities Commission
Newport Electric
South County Gas
New England Energy Group
Providence Gas
7/81
9/82
7/86
8/88
Newport Electric
South County Gas
Providence Gas Company
Providence Gas Company
Docket No. 1599
Docket No. 1671
Docket No. 1844
Docket No. 1914
1/01
Providence Gas Company and
The Valley Gas Company
New England Gas Company
Docket No. 1673 and
1736
Docket No. 3459
Rate Attrition
Cost of Capital
Load Forecast., Least-Cost
Planning
Gas Cost Mitigation
Strategy
Cost of Capital
Docket No. 9300
Cost of Capital, CWIP
Providence Gas Company and The Valley
Gas Company
The New England Gas Company
Texas Public Utility Commission
Southwestern Electric
P.U.C. General Counsel
5/83
11/90
Oncor Electric Delivery Company
8/07
6/08
3/03
Southwestern Electric
Texas Utilities Electric
Company
Oncor Electric Delivery
Company
Oncor Electric Delivery
Company
Docket No. 34040
Docket No.35717
PAGE 12
Rate Service - Direct
Rate Filing Package;
Regulatory Policy, Rate of
Return, Return of Capital
and Consolidated Tax
Adjustment
Rate Filing
SPONSOR
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
Docket No. 35665
Competitive Renewable
Energy Zone
Docket No. 38339
Cost of Service Rate
Adjustment
10/08
CenterPoint Energy
6/10
10/10
Oncor, TCC, TNC, ETT,
LCRA TSC, Sharyland, STEC,
TNMP
CenterPoint Energy/Houston
Electric
5/85
8/10
Southern Union Gas Company
Atmos Pipeline Texas
G.U.D. 1891
GUD 10000
Cost of Service
Ratemaking Policy
1/88
4/88
7/90
9/90
8/90
12/07
Mountain Fuel Supply Company
Utah P&L/Pacific P&L
Mountain Fuel Supply
Utah Power & Light
Utah Power & Light
Questar Gas Company
Case No. 86-057-07
Case No. 87-035-27
Case No. 89-057-15
Case No. 89-035-06
Case No. 90-035-06
Docket No. 07-057-13
Merger & Acquisition
Gas Transportation Rates
Energy Balancing Account
Electric Service Priorities
Benchmarking in support of
ROE
Texas Railroad Commission
Southern Union Gas
AtmosPipeline Texas
Utah Public Service Commission
AMAX Magnesium
AMAX Magnesium
Utah Industrial Group
AMAX Magnesium
AMAX Magnesium
Questar Gas Company
Vermont Public Service Board
Green Mountain Power
Wisconsin Public Service Commission
WEC & WICOR
8/82
12/97
7/98
9/00
Docket No. 4570
Docket No. 5983
Docket No. 6107
Docket No. 6107
Rate Attrition
Tariff Filing
Direct Testimony
Rebuttal Testimony
11/99
WEC
Approval to Acquire the
Stock of WICOR
Wisconsin Electric Power Company
1/07
Wisconsin Electric Power Co.
10/09
Wisconsin Electric Power Co.
Docket No. 9401-YO100
Docket No. 9402-YO101
Docket No. 6630-EI113
Docket No. 6630-CE302
PAGE 13
CPCN Application
ATTACHMENT A
EXPERT TESTIMONY OF JOHN J. REED
SPONSOR
DATE
CASE/APPLICANT
American Arbitration Association
Michael Polsky
3/91
M. Polsky vs. Indeck Energy
ProGas Limited
7/92
Attala Generating Company
12/03
ProGas Limited v. Texas
Eastern
Attala Generating Co v. Attala
Energy Co.
Nevada Power Company
4/08
DOCKET NO.
SUBJECT
Arbitration Panel
Corporate Valuation,
Damages
Gas Contract Arbitration
Case No. 16-Y-19800228-03
Power Project Valuation;
Breach of Contract;
Damages
Power Purchase
Agreement
C.A. No. 4452
Damages Quantification
Case No. 00CV129-A
Partnership Fiduciary
Duties
C.A. No. 1669-N
Bond Indenture
Covenants
Docket No. 97 CH
07291
Breach of Contract; Power
Plant Valuation
2001/2002 Arbitration
Gas Price Arbitration
Nevada Power v. Nevada
Cogeneration Assoc. #2
Commonwealth of Massachusetts, Suffolk Superior Court
John Hancock
1/84
Trinity Church v. John
Hancock
State of Colorado District Court, County of Garfield
Questar Corporation, et al
11/00
Questar Corporation, et al.
State of Delaware, Court of Chancery, New Castle County
Wilmington Trust Company
11/05
Calpine Corporation vs. Bank
Of New York and Wilmington
Trust Company
Illinois Appellate Court, Fifth Division
Norweb, plc
8/02
Indeck No. America v.
Norweb
Independent Arbitration Panel
Alberta Northeast Gas Limited
2/98
ProGas Ltd., Canadian Forest
Oil Ltd., AEC Oil & Gas
Ocean State Power
9/02
Ocean State Power vs. ProGas
Ltd.
Ocean State Power
2/03
Ltd.
Ocean State Power
6/04
Ltd.
Shell Canada Limited
7/05
Shell Canada Limited and
Nova Scotia Power Inc.
Gas Contract Price
Arbitration
PAGE 14
ATTACHMENT A
SPONSOR
DATE
International Court of Arbitration
Wisconsin Gas Company, Inc.
CASE/APPLICANT
DOCKET NO.
SUBJECT
Wisconsin Gas Co. vs. PanAlberta
Minnegasco vs. Pan-Alberta
Case No. 9322/CK
Contract Arbitration
Case No. 9357/CK
Utilicorp vs. Pan-Alberta
IES vs. Pan-Alberta
Case No. 9373/CK
Case No. 9374/CK
IMO Industries Inc. vs.
Transamerica Corp., et. al.
Docket No. L-2140-03
Breach-Related Damages,
Enterprise Value
Steel Los II, LP & Associated
Brook, Corp v. Power
Authority of State of NY
Index No. 5662/05
Property seizure
5/07
Cargill Gas Marketing Ltd. vs.
Alberta Northeast Gas
Limited
Action No. 050103291
Gas Contracting Practices
5/87
Laroche vs. Newport
Least-Cost Planning
5/85
State of Texas vs. Western Gas Case No. 14,843
Interstate Co.
Cost of Service
1/07
USA Power & Spring Canyon
Energy vs. PacifiCorp. et. al.
Civil No. 050903412
Breach-Related Damages
EUA Power Corporation
Case No. BK-9110525-JEY
Pre-Petition Solvency
Ponderosa Pine Energy
Partners, Ltd.
Case No. 05-21444
Forward Contract
Bankruptcy Treatment
2/97
Minnegasco, A Division of NorAm Energy
3/97
Corp.
Utilicorp United Inc.
4/97
IES Utilities
97
State of New Jersey, Mercer County Superior Court
Transamerica Corp., et. al.
7/07
State of New York, Nassau County Supreme Court
Steel Los III, LP
6/08
Province of Alberta, Court of Queen’s Bench
Alberta Northeast Gas Limited
State of Rhode Island, Providence City Court
Aquidneck Energy
State of Texas Hutchinson County Court
State of Utah Third District Court
PacifiCorp & Holme, Roberts & Owen, LLP
U.S. Bankruptcy Court, District of New Hampshire
7/92
U.S. Bankruptcy Court, District Of New Jersey
Ponderosa Pine Energy Partners, Ltd.
7/05
U.S. Bankruptcy Court, No. District of New York
PAGE 15
ATTACHMENT A
SPONSOR
DATE
Cayuga Energy, NYSEG Solutions, The
Energy Network
CASE/APPLICANT
DOCKET NO.
SUBJECT
Cayuga Energy, NYSEG
Solutions, The Energy
Network
Case No. 06-60073-6sdg
Going concern
Enron Energy Mktg. v. Johns
Manville;
Enron No. America v. Johns
Manville
Case No. 01-16034
(AJG)
Breach of Contract;
Damages
Mirant Corporation, et al. v.
SMECO
Case No. 03-4659;
Adversary No. 044073
PPA Interpretation;
Leasing
Boston Edison v. Department
of Energy
Consolidated Edison of New
York, Inc. and subsidiaries v.
United States
Consolidated Edison
Company v. United States
Vermont Yankee Nuclear
Power Corporation
No. 99-447C
No. 03-2626C
No. 06-305T
Spent Nuclear Fuel
Litigation
Leasing Litigation
No. 04-0033C
SNF Expert Report
No. 03-2663C
SNF Expert Report
KN Energy vs. Colorado
GasMark, Inc.
Case No. 92 CV 1474
Gas Contract
Interpretation
Norcen Energy Resources
Limited
Case No. C94-0911
VRW
Fraud Claim
12/04
Constellation Power Source,
Inc. v. Select Energy, Inc.
Civil Action 304 CV
983 (RNC)
ISO Structure, Breach of
Contract
3/94
NECO Enterprises Inc. vs.
Civil Action No. 9210355-RCL
Seabrook Power Sales
09/09
U.S. Bankruptcy Court, So. District Of New York
Johns Manville
5/04
U.S. Bankruptcy Court, Northern District Of Texas
Southern Maryland Electric Cooperative, Inc.
11/04
and Potomac Electric Power Company
U. S. Court of Federal Claims
7/06
Consolidated Edison of New York
08/07
Consolidated Edison Company
2/08
Vermont Yankee Nuclear Power Corporation
6/08
U. S. District Court, Boulder County, Colorado
KN Energy, Inc.
3/93
U. S. District Court, Northern California
Pacific Gas & Electric Co./PGT
PG&E/PGT Pipeline Exp. Project
U. S. District Court, District of Connecticut
Constellation Power Source, Inc.
U. S. District Court, Massachusetts
Eastern Utilities Associates & Donald F.
Pardus
4/97
PAGE 16
ATTACHMENT A
SPONSOR
U. S. District Court, Montana
KN Energy, Inc.
U.S. District Court, New Hampshire
Portland Natural Gas Transmission and
DATE
CASE/APPLICANT
DOCKET NO.
SUBJECT
9/92
KN Energy v. Freeport
MacMoRan
Docket No. CV 91-40BLG-RWA
Gas Contract Settlement
9/03
Public Service Company of
New Hampshire vs. PNGTS
and M&NE Pipeline
Docket No. C-02-105B
Impairment of Electric
Transmission Right-ofWay
Central Hudson v.
Riverkeeper, Inc., Robert H.
Boyle, John J. Cronin
Central Hudson v.
Riverkeeper, Inc., Robert H.
Boyle, John J. Cronin
Consolidated Edison v.
Northeast Utilities
Merrill Lynch v. Allegheny
Energy, Inc.
Civil Action 99 Civ
2536 (BDP)
Expert Report, Shortnose
Sturgeon Case
Civil Action 99 Civ
2536 (BDP)
Revised Expert Report,
Shortnose Sturgeon Case
Case No. 01 Civ. 1893
(JGK) (HP)
Civil Action 02 CV
7689 (HB)
Industry Standards for
Due Diligence
Due Diligence, Breach of
Contract, Damages
VPEM v. Aquila, Inc.
Civil Action 304 CV
411
Breach of Contract,
Damages
CIT Financial vs. ACEC
Maine
Combustion Eng. vs. Miller
Hydro
Docket No. 90-0304-B
Project Valuation
Docket No. 89-0168P
Output Modeling;
Project Valuation
File No. 70-8034
Value of EUA Power
Bill 13-284
Utility restructuring
U. S. District Court, Southern District of New York
Central Hudson Gas & Electric
11/99
Central Hudson Gas & Electric
8/00
Consolidated Edison
3/02
Merrill Lynch & Company
1/05
U. S. District Court, Eastern District of Virginia
Aquila, Inc.
1/05
U. S. District Court, Portland Maine
ACEC Maine, Inc. et al.
10/91
Combustion Engineering
1/92
U.S. Securities and Exchange Commission
Eastern Utilities Association
10/92
Council of the District of Columbia Committee on Consumer and Regulatory Affairs
Potomac Electric Power Co.
7/99
Potomac Electric Power Co.
PAGE 17
Exhibit__(JJR-1), Schedule 1
Page 1 of 7
30 DAY CONSTANT GROWTH DCF - ELECTRIC PROXY GROUP
Company
Cleco Corp.
DPL, Inc.
NextEra Energy, Inc.
Great Plains Energy Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
[1]
[2]
[3]
Annualized
Stock
Dividend
Dividend
Price
Yield
$1.68
$35.96
4.67%
$1.00
$28.87
3.46%
$1.21
$25.65
4.72%
$2.00
$54.14
3.69%
$0.83
$18.78
4.42%
$1.24
$23.39
5.30%
$1.20
$35.32
3.40%
$2.10
$40.57
5.18%
$1.04
$20.13
5.17%
$2.48
$43.61
5.69%
$1.82
$36.90
4.93%
$1.24
$23.97
5.17%
PROXY GROUP MEAN 4.65%
[4]
Expected
Dividend Yield
4.76%
3.58%
4.87%
3.81%
4.64%
5.56%
3.47%
5.34%
5.32%
5.79%
5.05%
5.39%
4.80%
[5]
Zacks EPS
Growth
4.30%
7.00%
NA
6.40%
13.00%
9.80%
4.00%
6.80%
9.60%
4.00%
5.10%
8.00%
7.09%
[6]
Value Line
EPS Growth
3.00%
9.50%
7.00%
5.00%
4.50%
11.50%
5.50%
6.00%
3.00%
3.50%
4.50%
7.50%
5.88%
[7]
First Call
4.38%
3.00%
5.90%
6.83%
13.00%
7.43%
4.00%
6.50%
5.40%
3.63%
5.07%
9.28%
6.20%
[8]
Average
Growth Rate
3.89%
6.50%
6.45%
6.08%
10.17%
9.58%
4.50%
6.43%
6.00%
3.71%
4.89%
8.26%
6.37%
Flotation Adjustment
Adjusted Mean DCF
Notes
[1] Source: Bloomberg
[2] Source: Bloomberg. Based on indicated number of days historical average.
[3] Equals Col. [1]/Col. [2]
[4] Equals (Col. [1] x (1+(0.5 x Col. [8])))/Col. [2]
[5] Source: Zacks
[6] Source: Value Line
[7] Source: First Call
[8] Equals Avg (Col. [5], [6], [7])
[9] Equals (Col. [3] x (1 + (0.5 x Minimum (Col. [5], [6], [7])))) + Minimum (Col. [5], [6], [7])
[10] Equals Col. [4] + Col. [8]
[11] Equals (Col. [3] x (1 + (0.5 x Maximum (Col. [5], [6], [7])))) + Maximum (Col. [5], [6], [7])
[9]
Low DCF
7.74%
6.52%
10.76%
8.79%
9.02%
12.93%
7.47%
11.33%
8.24%
9.29%
9.54%
12.87%
9.54%
[10]
Mean
DCF
8.66%
10.08%
11.32%
9.88%
14.81%
15.13%
7.97%
11.78%
11.32%
9.50%
9.94%
13.65%
11.17%
[11]
High DCF
9.15%
13.13%
11.88%
10.65%
17.71%
17.11%
8.99%
12.15%
15.02%
9.80%
10.16%
14.69%
12.54%
0.22%
9.76%
0.22%
11.39%
0.22%
12.76%
Page 2 of 7
Company
Cleco Corp.
DPL, Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
[1]
[2]
[3]
Annualized
Stock
Dividend
Dividend
Price
Yield
$1.68
$34.72
4.84%
$1.00
$27.90
3.58%
$1.21
$25.31
4.78%
$2.00
$52.24
3.83%
$0.83
$18.04
4.60%
$1.24
$23.28
5.33%
$1.20
$34.71
3.46%
$2.10
$38.52
5.45%
$1.04
$19.39
5.36%
$2.48
$41.55
5.97%
$1.82
$35.25
5.16%
$1.24
$23.21
5.34%
[4]
Expected
Dividend Yield
4.93%
3.70%
4.94%
3.94%
4.84%
5.58%
3.54%
5.63%
5.53%
6.08%
5.29%
5.56%
4.96%
[5]
Zacks EPS
Growth
4.30%
7.00%
NA
6.40%
13.00%
9.80%
4.00%
6.80%
9.60%
4.00%
5.10%
8.00%
7.09%
[6]
Value Line
EPS Growth
3.00%
9.50%
7.00%
5.00%
4.50%
11.50%
5.50%
6.00%
3.00%
3.50%
4.50%
7.50%
5.88%
[7]
First Call
4.38%
3.00%
5.90%
6.83%
13.00%
7.43%
4.00%
6.50%
5.40%
3.63%
5.07%
9.28%
6.20%
[8]
Average
Growth Rate
3.89%
6.50%
6.45%
6.08%
10.17%
9.58%
4.50%
6.43%
6.00%
3.71%
4.89%
8.26%
6.37%
Adjusted Mean DCF
Notes
[5] Source: Zacks
[8] Equals Avg (Col. [5], [6], [7])
[10] Equals Col. [4] + Col. [8]
[9]
Low DCF
7.91%
6.64%
10.82%
8.92%
9.21%
12.96%
7.53%
11.61%
8.44%
9.57%
9.78%
13.04%
9.70%
[10]
Mean
DCF
8.83%
10.20%
11.39%
10.02%
15.00%
15.16%
8.04%
12.06%
11.53%
9.79%
10.18%
13.82%
11.33%
[11]
High DCF
9.32%
13.25%
11.95%
10.79%
17.90%
17.13%
9.05%
12.44%
15.22%
10.09%
10.39%
14.87%
12.70%
0.22%
9.93%
0.22%
11.56%
0.22%
12.92%
Page 3 of 7
Company
Cleco Corp.
DPL, Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
[1]
[2]
[3]
Annualized
Stock
Dividend
Dividend
Price
Yield
$1.68
$34.35
4.89%
$1.00
$27.17
3.68%
$1.21
$26.25
4.61%
$2.00
$50.60
3.95%
$0.83
$18.23
4.55%
$1.24
$22.54
5.50%
$1.20
$34.33
3.50%
$2.10
$37.79
5.56%
$1.04
$19.40
5.36%
$2.48
$40.34
6.15%
$1.82
$34.21
5.32%
$1.24
$22.75
5.45%
[4]
Expected
Dividend Yield
4.99%
3.80%
4.76%
4.07%
4.78%
5.77%
3.57%
5.74%
5.52%
6.26%
5.45%
5.67%
5.03%
[5]
Zacks EPS
Growth
4.30%
7.00%
NA
6.40%
13.00%
9.80%
4.00%
6.80%
9.60%
4.00%
5.10%
8.00%
7.09%
[6]
Value Line
EPS Growth
3.00%
9.50%
7.00%
5.00%
4.50%
11.50%
5.50%
6.00%
3.00%
3.50%
4.50%
7.50%
5.88%
[7]
First Call
4.38%
3.00%
5.90%
6.83%
13.00%
7.43%
4.00%
6.50%
5.40%
3.63%
5.07%
9.28%
6.20%
[8]
Average
Growth Rate
3.89%
6.50%
6.45%
6.08%
10.17%
9.58%
4.50%
6.43%
6.00%
3.71%
4.89%
8.26%
6.37%
Adjusted Mean DCF
Notes
[5] Source: Zacks
[8] Equals Avg (Col. [5], [6], [7])
[10] Equals Col. [4] + Col. [8]
[9]
Low DCF
7.96%
6.74%
10.64%
9.05%
9.15%
13.14%
7.57%
11.72%
8.44%
9.75%
9.94%
13.15%
9.77%
[10]
Mean
DCF
8.88%
10.30%
11.21%
10.15%
14.95%
15.34%
8.07%
12.17%
11.52%
9.97%
10.34%
13.93%
11.40%
[11]
High DCF
9.38%
13.35%
11.77%
10.92%
17.85%
17.32%
9.09%
12.55%
15.22%
10.27%
10.56%
14.98%
12.77%
0.22%
9.99%
0.22%
11.63%
0.22%
12.99%
Page 4 of 7
30 DAY CONSTANT GROWTH DCF - COMBINATION PROXY GROUP
Company
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
[1]
[2]
[3]
Annualized
Stock
Dividend
Dividend
Price
Yield
$1.58
$35.78
4.42%
$1.00
$20.85
4.80%
$1.44
$30.54
4.72%
$0.78
$15.13
5.15%
$2.38
$47.90
4.97%
$2.24
$46.66
4.80%
$1.82
$46.14
3.94%
$1.90
$39.72
4.78%
$0.82
$17.07
4.80%
$1.36
$24.98
5.44%
$1.60
$56.96
2.81%
[4]
Expected
Dividend Yield
4.58%
4.93%
4.86%
5.29%
5.06%
4.93%
4.08%
4.88%
4.96%
5.57%
2.94%
4.74%
[5]
Zacks EPS
Growth
5.00%
4.70%
6.00%
6.00%
4.50%
5.00%
6.80%
4.30%
5.30%
5.00%
8.70%
5.57%
[6]
Value Line
EPS Growth
7.00%
8.50%
6.50%
4.50%
2.50%
6.50%
7.00%
3.50%
8.00%
4.50%
9.50%
6.18%
[7]
First Call
9.90%
4.00%
6.00%
5.70%
4.47%
5.00%
6.88%
4.90%
6.68%
4.85%
9.53%
6.17%
[8]
Average
Growth Rate
7.30%
5.73%
6.17%
5.40%
3.82%
5.50%
6.89%
4.23%
6.66%
4.78%
9.24%
5.98%
Adjusted Mean DCF
Notes
[5] Source: Zacks
[8] Equals Avg (Col. [5], [6], [7])
[10] Equals Col. [4] + Col. [8]
[9]
Low DCF
9.53%
8.89%
10.86%
9.77%
7.53%
9.92%
10.88%
8.37%
10.23%
10.07%
11.63%
9.79%
[10]
Mean
DCF
11.88%
10.67%
11.03%
10.69%
8.89%
10.43%
10.97%
9.12%
11.62%
10.36%
12.18%
10.71%
[11]
High DCF
14.54%
13.50%
11.37%
11.31%
9.58%
11.46%
11.08%
9.80%
13.00%
10.58%
12.47%
11.70%
0.22%
10.01%
0.22%
10.93%
0.22%
11.92%
Page 5 of 7
Company
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
[1]
[2]
[3]
Annualized
Stock
Dividend
Dividend
Price
Yield
$1.58
$34.26
4.61%
$1.00
$20.47
4.89%
$1.44
$30.24
4.76%
$0.78
$14.33
5.44%
$2.38
$45.91
5.18%
$2.24
$46.68
4.80%
$1.82
$44.06
4.13%
$1.90
$38.25
4.97%
$0.82
$16.40
5.00%
$1.36
$24.39
5.58%
$1.60
$53.89
2.97%
[4]
Expected
Dividend Yield
4.78%
5.03%
4.91%
5.59%
5.28%
4.93%
4.27%
5.07%
5.17%
5.71%
3.11%
4.90%
[5]
Zacks EPS
Growth
5.00%
4.70%
6.00%
6.00%
4.50%
5.00%
6.80%
4.30%
5.30%
5.00%
8.70%
5.57%
[6]
Value Line
EPS Growth
7.00%
8.50%
6.50%
4.50%
2.50%
6.50%
7.00%
3.50%
8.00%
4.50%
9.50%
6.18%
[7]
First Call
9.90%
4.00%
6.00%
5.70%
4.47%
5.00%
6.88%
4.90%
6.68%
4.85%
9.53%
6.17%
[8]
Average
Growth Rate
7.30%
5.73%
6.17%
5.40%
3.82%
5.50%
6.89%
4.23%
6.66%
4.78%
9.24%
5.98%
Adjusted Mean DCF
Notes
[5] Source: Zacks
[8] Equals Avg (Col. [5], [6], [7])
[10] Equals Col. [4] + Col. [8]
[9]
Low DCF
9.73%
8.98%
10.91%
10.07%
7.75%
9.92%
11.07%
8.55%
10.43%
10.20%
11.80%
9.95%
[10]
Mean
DCF
12.08%
10.76%
11.08%
10.99%
9.11%
10.43%
11.17%
9.31%
11.83%
10.49%
12.35%
10.87%
[11]
High DCF
14.74%
13.59%
11.42%
11.61%
9.80%
11.45%
11.28%
9.99%
13.20%
10.72%
12.64%
11.86%
0.22%
10.17%
0.22%
11.09%
0.22%
12.08%
Page 6 of 7
Company
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
[1]
[2]
[3]
Annualized
Stock
Dividend
Dividend
Price
Yield
$1.58
$33.61
4.70%
$1.00
$20.70
4.83%
$1.44
$29.80
4.83%
$0.78
$14.27
5.47%
$2.38
$45.05
5.28%
$2.24
$45.87
4.88%
$1.82
$43.49
4.18%
$1.90
$37.74
5.03%
$0.82
$16.16
5.08%
$1.36
$24.21
5.62%
$1.60
$52.01
3.08%
[4]
Expected
Dividend Yield
4.87%
4.97%
4.98%
5.61%
5.38%
5.02%
4.33%
5.14%
5.24%
5.75%
3.22%
4.96%
[5]
Zacks EPS
Growth
5.00%
4.70%
6.00%
6.00%
4.50%
5.00%
6.80%
4.30%
5.30%
5.00%
8.70%
5.57%
[6]
Value Line
EPS Growth
7.00%
8.50%
6.50%
4.50%
2.50%
6.50%
7.00%
3.50%
8.00%
4.50%
9.50%
6.18%
[7]
First Call
9.90%
4.00%
6.00%
5.70%
4.47%
5.00%
6.88%
4.90%
6.68%
4.85%
9.53%
6.17%
[8]
Average
Growth Rate
7.30%
5.73%
6.17%
5.40%
3.82%
5.50%
6.89%
4.23%
6.66%
4.78%
9.24%
5.98%
Adjusted Mean DCF
Notes
[5] Source: Zacks
[8] Equals Avg (Col. [5], [6], [7])
[10] Equals Col. [4] + Col. [8]
[9]
Low DCF
9.82%
8.93%
10.98%
10.09%
7.85%
10.01%
11.13%
8.62%
10.51%
10.24%
11.91%
10.01%
[10]
Mean
DCF
12.17%
10.70%
11.15%
11.01%
9.21%
10.52%
11.22%
9.37%
11.90%
10.53%
12.46%
10.93%
[11]
High DCF
14.83%
13.54%
11.49%
11.63%
9.90%
11.54%
11.33%
10.06%
13.28%
10.76%
12.75%
11.92%
0.22%
10.23%
0.22%
11.15%
0.22%
12.14%
Page 7 of 7
SUMMARY OF DCF RESULTS
Mean Results (not including flotation cost)
30 Day Average
60% Electric 40% Combination Company
Mean Low
9.54%
9.79%
9.64%
Mean
11.17%
10.71%
10.99%
Mean High
12.54%
11.70%
12.20%
90 Day Average
9.70%
9.95%
9.80%
11.33%
10.87%
11.15%
12.70%
11.86%
12.36%
180 Day Average
9.77%
10.01%
9.87%
11.40%
10.93%
11.21%
12.77%
11.92%
12.43%
Flotation Cost (not reflected in above results)
0.22%
0.22%
Mean Results (including flotation cost)
30 Day Average
Mean Low
9.76%
10.01%
9.86%
Mean
11.39%
10.93%
11.21%
Mean High
12.76%
11.92%
12.42%
90 Day Average
9.93%
10.17%
10.02%
11.56%
11.09%
11.37%
12.92%
12.08%
12.58%
180 Day Average
9.99%
10.23%
10.09%
11.63%
11.15%
11.44%
12.99%
12.14%
12.65%
Page 1 of 3
FLOTATION COST ADJUSTMENT
Flotation Costs from Inception to Date
Date
11/16/1949
6/4/1952
4/14/1954
2/29/1956
7/22/1959
7/28/1965
1/22/1969
10/21/1970
7/26/1972
10/10/1973
11/20/1974
8/14/1975
6/3/1976
5/31/1993
9/23/1997
9/29/1997
2/25/2002
9/9/2008
8/10/2010
Shares
Issued
1,584,238
1,108,966
1,219,856
670,920
952,033
772,008
1,080,811
1,729,298
1,902,228
2,092,451
2,300,000
1,750,000
2,000,000
3,041,955
4,500,000
400,000
20,000,000
15,000,000
21,850,000
Market Price Offering Price
$10.750
$10.500
$15.250
$17.825
$23.375
$35.250
$29.000
$23.125
$25.000
$25.825
$17.625
$23.000
$24.000
$44.125
$49.938
$50.500
$22.950
$20.860
$22.100
Weighted Average Flotation Costs
$10.250
$10.500
$14.000
$16.750
$22.000
$33.000
$27.000
$21.500
$23.500
$24.500
$17.500
$23.000
$24.000
$43.625
$49.563
$49.563
$22.500
$20.200
$21.500
Underwriting
Discount
$0.124
$0.098
$0.060
$0.050
$0.069
$0.092
$0.119
$0.175
$0.129
$0.128
$0.910
$0.740
$0.720
$1.200
$1.230
$1.230
$0.730
$0.100
$0.065
Offering
Expense
$0.137
$0.162
$0.124
$0.221
$0.191
$0.225
$0.187
$0.149
$0.166
$0.153
$0.069
$0.077
$0.064
$0.048
$0.133
$0.133
$0.015
$0.005
$0.027
Net
Proceeds
$9.989
$10.240
$13.816
$16.479
$21.740
$32.683
$26.694
$21.176
$23.205
$24.219
$16.521
$22.183
$23.216
$42.377
$48.200
$48.200
$21.755
$20.095
$21.408
Total Flotation
Costs
$1,205,605
$288,331
$1,749,274
$903,058
$1,556,574
$1,981,745
$2,492,350
$3,370,402
$3,414,499
$3,360,476
$2,539,200
$1,429,750
$1,568,000
$5,317,337
$7,821,000
$920,000
$23,900,000
$11,475,000
$15,119,325
$90,411,926
Gross Equity
Issue before
Costs
Net Proceeds
$17,030,559
$11,644,143
$18,602,804
$11,959,149
$22,253,771
$27,213,282
$31,343,519
$39,990,016
$47,555,700
$54,037,547
$40,537,500
$40,250,000
$48,000,000
$134,226,264
$224,721,000
$20,200,000
$459,000,000
$312,900,000
$482,885,000
$2,044,350,255
$15,824,953
$11,355,812
$16,853,530
$11,056,091
$20,697,197
$25,231,537
$28,851,169
$36,619,614
$44,141,201
$50,677,071
$37,998,300
$38,820,250
$46,432,000
$128,908,927
$216,900,000
$19,280,000
$435,100,000
$301,425,000
$467,765,675
$1,953,938,328
Flotation Cost
Percentage
7.079%
2.476%
9.403%
7.551%
6.995%
7.282%
7.952%
8.428%
7.180%
6.219%
6.264%
3.552%
3.267%
3.961%
3.480%
4.554%
5.207%
3.667%
3.131%
4.423%
The flotation adjustment is derived by dividing the dividend yield by 1-F (where F = flotation costs expressed in percentage terms), or by 0.9518, and adding that result
to the constant growth rate to determine the cost of equity. Using the formulas shown previously in my testimony, the Constant Growth DCF calculation is modified as
follows to accommodate an adjustment for flotation costs:
k=
D × (1 + .5 g )
+g
P × (1 − F )
Page 2 of 3
Flotation Cost Adjustment - Electric Proxy Group
[1]
Cleco Corp.
DPL, Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
MEAN
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
Stock Price
$35.96
$28.87
$25.65
$54.14
$18.78
$23.39
$35.32
$40.57
$20.13
$43.61
$36.90
$23.97
[2]
[3]
[4]
Annualized
Expected
Dividend Dividend Yield Dividend Yield
$1.68
4.67%
4.76%
$1.00
3.46%
3.58%
$1.21
4.72%
4.87%
$2.00
3.69%
3.81%
$0.83
4.42%
4.64%
$1.24
5.30%
5.56%
$1.20
3.40%
3.47%
$2.10
5.18%
5.34%
$1.04
5.17%
5.32%
$2.48
5.69%
5.79%
$1.82
4.93%
5.05%
$1.24
5.17%
5.39%
4.65%
4.80%
MEAN
UNADJUSTED CONSTANT GROWTH DCF MEAN
DIFFERENCE (FLOTATION COST ADJUSTMENT)
[1] Source: Bloomberg, 30 day average price
[2] Bloomberg
[3] = [1] / [2] or [Annualized Dividend] / [Price]
[4] = [3] x [1+ .5g] or [Dividend Yield] x [1 + (.5 x average growth rate)]
[5] = [Expected Dividend Yield] / [1- Flotation Cost Percentage]
[6] Source: Zacks
[7] Source Value Line
[9] Average of columns [6], [7], [8]
[10] = (Column [4] + Column [9]
[11] = (Column [5] + Column [9]
[12] Equals Mean Adjusted DCF, Column [11] - Mean Unadjusted DCF, Column [10]
[5]
[6]
[7]
[8]
[9]
Expected
Dividend Yield Proj EPS
Adjusted for
Growth
Proj EPS Growth Proj EPS Growth Average Growth
Flotation Costs
(Zacks)
(V.L.)
(First Call)
Estimate
4.98%
4.30%
3.00%
4.38%
3.89%
3.74%
7.00%
9.50%
3.00%
6.50%
5.10%
NA
7.00%
5.90%
6.45%
3.98%
6.40%
5.00%
6.83%
6.08%
4.86%
13.00%
4.50%
13.00%
10.17%
5.81%
9.80%
11.50%
7.43%
9.58%
3.63%
4.00%
5.50%
4.00%
4.50%
5.59%
6.80%
6.00%
6.50%
6.43%
5.57%
9.60%
3.00%
5.40%
6.00%
6.06%
4.00%
3.50%
3.63%
3.71%
5.29%
5.10%
4.50%
5.07%
4.89%
5.64%
8.00%
7.50%
9.28%
8.26%
7.09%
5.88%
6.20%
[10]
DCF k(e)
8.66%
10.08%
11.32%
9.88%
14.81%
15.13%
7.97%
11.78%
11.32%
9.50%
9.94%
13.65%
11.17%
[12]
[11]
Flotation Adjusted
DCF k(e)
8.88%
10.24%
11.55%
10.06%
15.03%
15.39%
8.13%
12.02%
11.57%
9.77%
10.18%
13.90%
11.39%
11.39%
11.17%
0.22%
Page 3 of 3
Flotation Cost Adjustment - Combination Proxy Group
[1]
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
MEAN
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
Stock Price
$35.78
$20.85
$30.54
$15.13
$47.90
$46.66
$46.14
$39.72
$17.07
$24.98
$56.96
[2]
[3]
[4]
Annualized
Expected
Dividend Dividend Yield Dividend Yield
$1.58
4.42%
4.58%
$1.00
4.80%
4.93%
$1.44
4.72%
4.86%
$0.78
5.15%
5.29%
$2.38
4.97%
5.06%
$2.24
4.80%
4.93%
$1.82
3.94%
4.08%
$1.90
4.78%
4.88%
$0.82
4.80%
4.96%
$1.36
5.44%
5.57%
$1.60
2.81%
2.94%
4.60%
4.74%
MEAN
UNADJUSTED CONSTANT GROWTH DCF MEAN
DIFFERENCE (FLOTATION COST ADJUSTMENT)
[1] Source: Bloomberg, 30 day average price
[2] Bloomberg
[3] = [1] / [2] or [Annualized Dividend] / [Price]
[4] = [3] x [1+ .5g] or [Dividend Yield] x [1 + (.5 x average growth rate)]
[5] = [Expected Dividend Yield] / [1- Flotation Cost Percentage]
[6] Source: Zacks
[7] Source Value Line
[9] Average of columns [6], [7], [8]
[10] = (Column [4] + Column [9]
[11] = (Column [5] + Column [9]
[12] Equals Mean Adjusted DCF, Column [11] - Mean Unadjusted DCF, Column [10]
[5]
[6]
[7]
[8]
[9]
Expected
Dividend Yield Proj EPS
Adjusted for
Growth
Proj EPS Growth Proj EPS Growth Average Growth
Flotation Costs
(Zacks)
(V.L.)
(First Call)
Estimate
4.79%
5.00%
7.00%
9.90%
7.30%
5.16%
4.70%
8.50%
4.00%
5.73%
5.09%
6.00%
6.50%
6.00%
6.17%
5.54%
6.00%
4.50%
5.70%
5.40%
5.30%
4.50%
2.50%
4.47%
3.82%
5.16%
5.00%
6.50%
5.00%
5.50%
4.27%
6.80%
7.00%
6.88%
6.89%
5.11%
4.30%
3.50%
4.90%
4.23%
5.19%
5.30%
8.00%
6.68%
6.66%
5.83%
5.00%
4.50%
4.85%
4.78%
3.08%
8.70%
9.50%
9.53%
9.24%
5.57%
6.18%
6.17%
[10]
DCF k(e)
11.88%
10.67%
11.03%
10.69%
8.89%
10.43%
10.97%
9.12%
11.62%
10.36%
12.18%
10.71%
[12]
[11]
Flotation Adjusted
DCF k(e)
12.09%
10.90%
11.25%
10.94%
9.12%
10.66%
11.16%
9.34%
11.85%
10.62%
12.32%
10.93%
10.93%
10.71%
0.22%
Page 1 of 6
ELECTRIC PROXY GROUP - CAPM 30-DAY AVERAGE 30 YEAR TREASURY YIELD
[1]
[2]
Adjusted Betas
Company
Cleco Corp.
DPL, Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
MEAN
Value Line Bloomberg
0.70
0.83
0.65
0.72
0.60
0.70
0.75
0.79
0.75
0.92
0.70
0.80
0.70
0.75
0.75
0.85
0.75
0.75
0.60
0.69
0.55
0.56
0.75
0.81
0.69
0.76
[3]
[4]
[5]
Market
30-Yr
Risk
Treasury
Mean
Premium
Yield
Beta
3.72%
6.70%
0.76
3.72%
6.70%
0.69
3.72%
6.70%
0.65
3.72%
6.70%
0.77
3.72%
6.70%
0.83
3.72%
6.70%
0.75
3.72%
6.70%
0.72
3.72%
6.70%
0.80
3.72%
6.70%
0.75
3.72%
6.70%
0.64
3.72%
6.70%
0.56
3.72%
6.70%
0.78
0.73
Notes
[3] Equals mean of Cols. [1], [2]
[5] Source: Ibboston Associates
[6] Equals Col [4] + (Min (Cols [1], [2]) x Col [5])
[7] Equals Col. [4] +(Col. [3] x Col [5])
[8] Equals Col [4] + (Max (Cols [1], [2]) x Col [5])
[6]
Low
CAPM
8.41%
8.08%
7.74%
8.75%
8.75%
8.41%
8.41%
8.75%
8.75%
7.74%
7.41%
8.75%
8.33%
[7]
CAPM
k(e)
8.85%
8.32%
8.09%
8.87%
9.32%
8.77%
8.56%
9.09%
8.75%
8.03%
7.46%
8.96%
8.59%
[8]
High
CAPM
9.28%
8.57%
8.44%
9.00%
9.88%
9.12%
8.72%
9.42%
8.75%
8.32%
7.50%
9.17%
8.85%
Page 2 of 6
[1]
[2]
Adjusted Betas
Company
Cleco Corp.
DPL, Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
MEAN
0.70
0.83
0.65
0.72
0.60
0.70
0.75
0.79
0.75
0.92
0.70
0.80
0.70
0.75
0.75
0.85
0.75
0.75
0.60
0.69
0.55
0.56
0.75
0.81
0.69
0.76
[3]
[4]
[5]
Market
30-Yr
Risk
Treasury
Mean
Premium
Yield
Beta
3.94%
6.70%
0.76
3.94%
6.70%
0.69
3.94%
6.70%
0.65
3.94%
6.70%
0.77
3.94%
6.70%
0.83
3.94%
6.70%
0.75
3.94%
6.70%
0.72
3.94%
6.70%
0.80
3.94%
6.70%
0.75
3.94%
6.70%
0.64
3.94%
6.70%
0.56
3.94%
6.70%
0.78
0.73
Notes
[6]
Low
CAPM
8.63%
8.29%
7.96%
8.96%
8.96%
8.63%
8.63%
8.96%
8.96%
7.96%
7.62%
8.96%
8.54%
[7]
CAPM
k(e)
9.06%
8.54%
8.30%
9.09%
9.53%
8.98%
8.78%
9.30%
8.96%
8.24%
7.67%
9.17%
8.80%
[8]
High
CAPM
9.49%
8.78%
8.65%
9.21%
10.09%
9.33%
8.93%
9.63%
8.96%
8.53%
7.71%
9.38%
9.06%
Page 3 of 6
[1]
[2]
Adjusted Betas
Company
Cleco Corp.
DPL, Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
MEAN
0.70
0.83
0.65
0.72
0.60
0.70
0.75
0.79
0.75
0.92
0.70
0.80
0.70
0.75
0.75
0.85
0.75
0.75
0.60
0.69
0.55
0.56
0.75
0.81
0.69
0.76
[3]
[4]
[5]
Market
30-Yr
Risk
Treasury
Mean
Premium
Yield
Beta
4.26%
6.70%
0.76
4.26%
6.70%
0.69
4.26%
6.70%
0.65
4.26%
6.70%
0.77
4.26%
6.70%
0.83
4.26%
6.70%
0.75
4.26%
6.70%
0.72
4.26%
6.70%
0.80
4.26%
6.70%
0.75
4.26%
6.70%
0.64
4.26%
6.70%
0.56
4.26%
6.70%
0.78
0.73
Notes
[6]
Low
CAPM
8.95%
8.61%
8.28%
9.28%
9.28%
8.95%
8.95%
9.28%
9.28%
8.28%
7.94%
9.28%
8.86%
[7]
CAPM
k(e)
9.38%
8.86%
8.62%
9.41%
9.85%
9.30%
9.10%
9.62%
9.29%
8.56%
7.99%
9.50%
9.12%
[8]
High
CAPM
9.82%
9.10%
8.97%
9.53%
10.42%
9.65%
9.25%
9.96%
9.29%
8.85%
8.04%
9.71%
9.38%
Page 4 of 6
COMBINATION PROXY GROUP - CAPM 30-DAY AVERAGE 30 YEAR TREASURY YIELD
[1]
[2]
Adjusted Betas
Company
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
MEAN
0.70
0.83
0.70
0.75
0.80
0.89
0.80
1.00
0.65
0.66
0.75
0.87
0.55
0.62
0.70
0.72
0.85
0.86
0.70
0.76
0.65
0.68
0.71
0.79
[3]
[4]
[5]
Market
30-Yr
Risk
Treasury
Mean
Premium
Yield
Beta
3.72%
6.70%
0.77
3.72%
6.70%
0.73
3.72%
6.70%
0.84
3.72%
6.70%
0.90
3.72%
6.70%
0.66
3.72%
6.70%
0.81
3.72%
6.70%
0.58
3.72%
6.70%
0.71
3.72%
6.70%
0.85
3.72%
6.70%
0.73
3.72%
6.70%
0.67
0.75
Notes
[3] Equals median of Cols. [1], [2]
[4] Source: Bloomberg Based on indicated number of days historical average.
[6]
Low
CAPM
8.41%
8.41%
9.08%
9.08%
8.08%
8.75%
7.41%
8.41%
9.42%
8.41%
8.08%
8.51%
[7]
CAPM
k(e)
8.86%
8.59%
9.38%
9.74%
8.12%
9.17%
7.63%
8.50%
9.44%
8.63%
8.19%
8.75%
[8]
High
CAPM
9.30%
8.77%
9.67%
10.41%
8.16%
9.59%
7.85%
8.58%
9.47%
8.84%
8.30%
8.99%
Page 5 of 6
[1]
[2]
Adjusted Betas
Company
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
MEAN
0.70
0.83
0.70
0.75
0.80
0.89
0.80
1.00
0.65
0.66
0.75
0.87
0.55
0.62
0.70
0.72
0.85
0.86
0.70
0.76
0.65
0.68
0.71
0.79
[3]
[4]
[5]
Market
30-Yr
Risk
Treasury
Mean
Premium
Yield
Beta
3.94%
6.70%
0.77
3.94%
6.70%
0.73
3.94%
6.70%
0.84
3.94%
6.70%
0.90
3.94%
6.70%
0.66
3.94%
6.70%
0.81
3.94%
6.70%
0.58
3.94%
6.70%
0.71
3.94%
6.70%
0.85
3.94%
6.70%
0.73
3.94%
6.70%
0.67
0.75
Notes
[6]
Low
CAPM
8.63%
8.63%
9.30%
9.30%
8.29%
8.96%
7.62%
8.63%
9.63%
8.63%
8.29%
8.72%
[7]
CAPM
k(e)
9.07%
8.80%
9.59%
9.96%
8.33%
9.38%
7.84%
8.71%
9.66%
8.84%
8.40%
8.96%
[8]
High
CAPM
9.52%
8.98%
9.88%
10.62%
8.37%
9.80%
8.06%
8.79%
9.68%
9.05%
8.51%
9.20%
Page 6 of 6
[1]
[2]
Adjusted Betas
Company
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
MEAN
0.70
0.83
0.70
0.75
0.80
0.89
0.80
1.00
0.65
0.66
0.75
0.87
0.55
0.62
0.70
0.72
0.85
0.86
0.70
0.76
0.65
0.68
0.71
0.79
[3]
[4]
[5]
Market
30-Yr
Risk
Treasury
Mean
Premium
Yield
Beta
4.26%
6.70%
0.77
4.26%
6.70%
0.73
4.26%
6.70%
0.84
4.26%
6.70%
0.90
4.26%
6.70%
0.66
4.26%
6.70%
0.81
4.26%
6.70%
0.58
4.26%
6.70%
0.71
4.26%
6.70%
0.85
4.26%
6.70%
0.73
4.26%
6.70%
0.67
0.75
Notes
[6]
Low
CAPM
8.95%
8.95%
9.62%
9.62%
8.61%
9.28%
7.94%
8.95%
9.95%
8.95%
8.61%
9.04%
[7]
CAPM
k(e)
9.39%
9.12%
9.91%
10.28%
8.65%
9.70%
8.16%
9.03%
9.98%
9.16%
8.72%
9.28%
[8]
High
CAPM
9.84%
9.30%
10.20%
10.94%
8.69%
10.12%
8.38%
9.11%
10.00%
9.37%
8.83%
9.53%
Page 1 of 3
BOND YIELD RISK PREMIUM
Average Authorized
Average 30-Yr.
Quarter [1b] Electric Utility ROE [1] Treasury Yield [2]
1992.1
12.36%
7.84%
1992.2
11.81%
7.88%
1992.3
12.17%
7.42%
1992.4
12.08%
7.54%
1993.1
11.80%
7.01%
1993.2
11.60%
6.86%
1993.3
11.11%
6.23%
1993.4
11.18%
6.21%
1994.1
11.16%
6.66%
1994.2
11.16%
7.45%
1994.3
12.75%
7.55%
1994.4
11.15%
7.95%
1995.1
11.81%
7.52%
1995.2
11.35%
6.87%
1995.3
11.37%
6.66%
1995.4
11.67%
6.14%
1996.1
11.31%
6.39%
1996.2
11.52%
6.92%
1996.3
11.22%
7.00%
1996.4
11.39%
6.54%
1997.1
11.32%
6.90%
1997.2
11.60%
6.88%
1997.3
12.00%
6.44%
1997.4
10.94%
6.04%
1998.1
11.49%
5.89%
1998.2
11.40%
5.79%
1998.3
11.90%
5.32%
1998.4
12.30%
5.11%
1999.1
10.72%
5.43%
1999.2
10.75%
5.82%
1999.3
10.93%
6.07%
1999.4
10.30%
6.31%
2000.1
10.98%
6.15%
2000.2
12.20%
5.95%
2000.3
12.03%
5.78%
2000.4
11.80%
5.62%
2001.1
11.13%
5.42%
2001.2
11.01%
5.77%
2001.3
10.69%
5.44%
2001.4
11.81%
5.21%
2002.1
10.95%
5.55%
2002.2
11.27%
5.57%
2002.3
12.30%
4.96%
2002.4
11.18%
4.93%
2003.1
11.58%
4.78%
2003.2
10.79%
4.57%
2003.3
10.70%
5.15%
2003.4
11.42%
5.11%
2004.1
10.75%
4.86%
2004.2
10.69%
5.31%
2004.3
10.33%
5.01%
2004.4
11.37%
4.87%
2005.1
10.46%
4.69%
2005.2
10.69%
4.34%
2005.3
10.38%
4.43%
2005.4
10.63%
4.66%
2006.1
10.30%
4.69%
2006.2
10.81%
5.19%
2006.3
10.26%
4.90%
2006.4
10.70%
4.70%
2007.1
10.59%
4.81%
2007.2
10.36%
4.98%
2007.3
10.20%
4.85%
2007.4
10.50%
4.53%
2008.1
10.49%
4.34%
2008.2
10.58%
4.57%
2008.3
10.39%
4.44%
2008.4
10.46%
3.49%
2009.1
10.87%
3.62%
2009.2
10.66%
4.23%
2009.3
10.60%
4.18%
2009.4
10.58%
4.35%
2010.1
10.53%
4.59%
2010.2
10.28%
4.20%
2010.3
10.29%
3.73%
Mean
11.12%
5.62%
Risk Premium
(ROE-Treasury
Yield)
4.52%
3.93%
4.75%
4.54%
4.79%
4.74%
4.88%
4.97%
4.50%
3.71%
5.20%
3.20%
4.29%
4.48%
4.71%
5.54%
4.92%
4.59%
4.21%
4.84%
4.42%
4.72%
5.56%
4.90%
5.60%
5.61%
6.58%
7.20%
5.29%
4.93%
4.85%
3.99%
4.83%
6.25%
6.25%
6.18%
5.71%
5.24%
5.25%
6.60%
5.40%
5.70%
7.34%
6.24%
6.80%
6.22%
5.55%
6.31%
5.89%
5.38%
5.32%
6.50%
5.77%
6.35%
5.94%
5.96%
5.60%
5.62%
5.36%
6.00%
5.78%
5.38%
5.35%
5.97%
6.15%
6.01%
5.95%
6.97%
7.26%
6.43%
6.42%
6.23%
5.95%
6.07%
6.56%
5.51%
Page 2 of 3
8.00%
Risk Premium
7.00%
y = -0.6449x + 0.0913
R2 = 0.6943
6.00%
5.00%
4.00%
3.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
8.00%
9.00%
SUMMARY OUTPUT
Regression Statistics
Multiple R
0.833223974
R Square
0.694262191
Adjusted R Square
0.690074002
Standard Error
0.004808684
Observations
75
ANOVA
df
Regression
Residual
Total
Intercept
X Variable 1
SS
1 0.003833095
73 0.001688011
74 0.005521106
MS
0.003833095
2.31234E-05
F
165.7666746
Coefficients
Standard Error
0.091276179 0.002866692
-0.64486535 0.050086471
t Stat
31.84024398
-12.87504076
P-value
1.4972E-44
1.82288E-20
30 Year Treasury
4.22%
5.80%
Risk Prem [3]
6.41%
5.39%
5.90%
30 Year Treasury Yield
Blue Chip Consensus Forecast (2010-2011) [4]
Blue Chip Consensus Forecast (2012 - 2021) [5]
MEAN
Significance F
1.82288E-20
Lower 95%
Upper 95% Lower 95.0% Upper 95.0%
0.08556287 0.0969895
0.08556287 0.096989488
-0.744687541 -0.5450432 -0.744687541 -0.54504316
ROE
10.63%
11.19%
10.91%
Notes
[1] Source: Regulatory Research Associates, Rate Case Statistics , accessed September 30, 2010.
[2] Source: Bloomberg Professional Service. Quarterly T-bond yields are the average of the last trading day of each month in the quarter.
[3] Independent variable = Treasury Yield; Dependent Variable = Risk Premium.
[4] Source: Aspen Publishers, Blue Chip Financial Forecasts , Vol. 29, No. 10 October 1, 2010, p. 2
[5] Source: Aspen Publishers, Blue Chip Financial Forecasts , Vol. 29 No. 6 June 1, 2010 p.14
Page 3 of 3
8.00%
Risk Premium
7.00%
y = -0.0359Ln(x) - 0.0491
R2 = 0.6823
6.00%
5.00%
4.00%
3.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
8.00%
9.00%
SUMMARY OUTPUT
Regression Statistics
Multiple R
0.826026748
R Square
0.682320189
Adjusted R Square
0.677968411
Standard Error
0.004901697
Observations
75
ANOVA
df
Regression
Residual
Total
Intercept
X Variable 1
SS
1 0.003767162
73 0.001753944
74 0.005521106
MS
0.003767162
2.40266E-05
F
156.7911214
Coefficients
Standard Error
-0.049051982 0.008334324
-0.035913651 0.00286813
t Stat
-5.885538331
-12.52162615
P-value
1.11644E-07
7.44323E-20
30 Year Treasury
4.22%
5.80%
Risk Prem [3]
6.47%
5.32%
5.89%
30 Year Treasury Yield
Blue Chip Consensus Forecast (2010-2011) [4]
Blue Chip Consensus Forecast (2012 - 2021) [5]
MEAN
Significance F
7.44323E-20
Lower 95%
Upper 95% Lower 95.0% Upper 95.0%
-0.065662266 -0.0324417 -0.065662266
-0.0324417
-0.041629826 -0.0301975 -0.041629826 -0.03019748
ROE
10.68%
11.12%
10.90%
Notes
[1] Source: Regulatory Research Associates, Rate Case Statistics , accessed September 30, 2010.
[2] Source: Bloomberg Professional Service. Quarterly T-bond yields are the average of the last trading day of each month in the quarter.
[3] Independent variable = Treasury Yield; Dependent Variable = Risk Premium.
[4] Source: Aspen Publishers, Blue Chip Financial Forecasts , Vol. 29, No. 10 October 1, 2010, p. 2
[5] Source: Aspen Publishers, Blue Chip Financial Forecasts , Vol. 29 No. 6 June 1, 2010 p.14
Page 1 of 1
2010-2013 Projected CAPEX/Net Plant
120.00%
100.00%
80.00%
60.00%
40.00%
20.00%
Am
er
ica
DP
L,
nE
Inc
lec
.
tric
Po
we
r
Cl
e
co
Gr
ea
Co
tP
rp
.
lai
ns
E
ne
Ha
rg
wa
y
iia
nE
lec
tric
Pi
nn
ac
le
W
Pr
es
og
t
re
ss
En
er
ID
gy
AC
OR
P,
Inc
.
W
es
tar
Po
Ga
rtla
s
nd
Ge
So
ne
uth
ra
er
l
nC
om
pa
Ne
ny
xtE
ra
En
NS
er
gy
P
-M
inn
es
ota
0.00%
Source: Value Line and Company Data
Projected CAPEX / 2009 Net Plant
[1]
2009-2013
Company
DPL, Inc.
36.83%
41.26%
Cleco Corp.
48.90%
Great Plains Energy
50.36%
Hawaiian Electric
51.99%
Pinnacle West
52.30%
Progress Energy
52.62%
IDACORP, Inc.
54.28%
Westar Gas
54.90%
Portland General
57.80%
Southern Company
66.93%
NextEra Energy
68.45%
NSP - Minnesota
98.11%
Notes
[1]
NSP-MN Capital expenditures are projected through 2010-2013, however Value Line projects capital expenditures through
2010, 2011, and 2013-2014.
Page 1 of 6
CAPITAL STRUCTURE - ELECTRIC PROXY GROUP
Equity Ratio
Company Name
Cleco Corp.
DPL, Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
Ticker
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
52.65% 52.60% 48.57% 49.15% 49.04% 47.93% 48.75% 48.49%
50.52% 50.69% 45.45% 47.08% 46.43% 45.54% 45.07% 47.49%
61.42% 61.53% 61.73% 58.46% 57.38% 57.09% 62.56% 63.33%
55.70% 53.38% 57.62% 56.91% 56.65% 56.59% 57.41% 53.94%
49.39% 49.46% 49.96% 51.46% 50.76% 44.33% 46.95% 49.30%
55.10% 54.99% 55.26% 53.15% 54.29% 56.00% 55.69% 52.92%
48.20% 47.56% 47.45% 48.15% 46.32% 44.90% 46.36% 45.30%
51.49% 48.39% 50.37% 50.74% 46.75% 47.17% 49.64% 52.58%
46.26% 46.47% 46.94% 49.37% 49.17% 51.68% 47.42% 50.17%
54.16% 53.05% 54.07% 53.01% 51.58% 49.99% 48.96% 50.04%
52.21% 52.11% 51.42% 52.05% 50.58% 50.95% 52.02% 53.28%
56.96% 56.93% 57.00% 57.68% 56.69% 59.74% 60.23% 61.52%
Proxy Group Average
Company Name
AEP Texas Central Company
AEP Texas North Company
Appalachian Power Company
Columbus Southern Power Company
Indiana Michigan Power Company
Kentucky Power Company
Kingsport Power Company
Ohio Power Company
Public Service Company of Oklahoma
Southwestern Electric Power Company
Wheeling Power Co
Cleco Power LLC
Dayton Power and Light Company
Hawaii Electric Light Company, Inc.
Kansas City Power & Light Company
KCP&L Greater Missouri Operations Company
Idaho Power Co.
Florida Power & Light Company
Arizona Public Service Company
Portland General Electric Company
Carolina Power & Light Company
Florida Power Corporation
Alabama Power Company
Georgia Power Company
Gulf Power Company
Mississippi Power Company
Kansas Gas and Electric Company
Westar Energy (KPL)
Overall Average
49.65%
47.28%
60.44%
56.03%
48.95%
54.67%
46.78%
49.64%
48.44%
51.86%
51.83%
58.34%
51.99%
Ticker
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
CNL
DPL
HE
GXP
GXP
IDA
NEE
PNW
POR
PGN
PGN
SO
SO
SO
SO
WR
WR
Equity Ratio
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
44.03% 44.13% 44.03% 43.91% 46.38% 44.26% 43.96% 42.70%
45.28% 45.92% 45.76% 46.81% 46.69% 46.90% 46.90% 47.47%
43.68% 45.21% 44.51% 44.98% 44.74% 41.04% 43.00% 43.52%
47.05% 46.48% 46.95% 46.18% 46.81% 46.39% 46.40% 47.26%
46.41% 46.56% 45.97% 45.86% 45.42% 43.20% 51.18% 51.09%
43.59% 44.27% 44.04% 44.00% 43.94% 48.92% 48.74% 47.70%
100.00% 100.00% 51.61% 55.30% 54.84% 55.05% 55.59% 55.66%
52.46% 49.54% 50.07% 50.27% 53.45% 48.16% 47.41% 48.97%
45.56% 45.49% 45.77% 48.71% 47.61% 45.02% 45.99% 45.69%
47.89% 47.48% 51.79% 51.60% 48.26% 47.39% 46.83% 42.67%
63.16% 63.54% 63.72% 62.98% 61.25% 60.92% 60.29% 60.62%
50.52% 50.69% 45.45% 47.08% 46.43% 45.54% 45.07% 47.49%
61.42% 61.53% 61.73% 58.46% 57.38% 57.09% 62.56% 63.33%
55.10% 54.99% 55.26% 53.15% 54.29% 56.00% 55.69% 52.92%
48.43% 49.26% 49.48% 51.40% 50.23% 45.35% 47.92% 50.55%
50.35% 49.66% 50.45% 51.52% 51.29% 43.32% 45.98% 48.04%
48.20% 47.56% 47.45% 48.15% 46.32% 44.90% 46.36% 45.30%
55.70% 53.38% 57.62% 56.91% 56.65% 56.59% 57.41% 53.94%
51.49% 48.39% 50.37% 50.74% 46.75% 47.17% 49.64% 52.58%
46.26% 46.47% 46.94% 49.37% 49.17% 51.68% 47.42% 50.17%
57.20% 56.93% 56.19% 55.69% 54.55% 53.96% 54.93% 55.37%
51.11% 49.16% 51.96% 50.33% 48.61% 46.03% 42.99% 44.72%
49.26% 49.25% 48.92% 48.89% 46.71% 46.69% 48.51% 49.01%
51.45% 51.78% 50.61% 52.40% 50.44% 49.01% 49.40% 48.81%
49.72% 48.96% 47.69% 48.32% 47.26% 50.31% 47.98% 49.30%
58.41% 58.44% 58.45% 58.58% 57.91% 57.78% 62.18% 65.98%
56.49% 56.24% 57.15% 57.23% 56.43% 65.33% 65.35% 65.25%
57.42% 57.61% 56.85% 58.13% 56.96% 54.15% 55.10% 57.78%
Page 2 of 6
Long Term Debt Ratio
Company Name
Cleco Corp.
DPL, Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
Ticker
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
47.35% 47.40% 51.43% 50.85% 50.96% 52.07% 51.25% 51.51%
49.48% 49.31% 54.55% 52.92% 53.57% 52.05% 54.93% 52.51%
38.58% 38.47% 38.27% 36.76% 36.79% 36.69% 37.44% 32.89%
38.81% 38.92% 39.70% 40.09% 40.75% 42.74% 39.56% 37.87%
41.81% 42.54% 43.15% 45.75% 46.16% 47.25% 43.67% 46.47%
44.31% 44.43% 44.74% 46.38% 41.15% 42.62% 42.37% 40.73%
51.80% 52.44% 52.55% 51.85% 52.27% 51.24% 49.24% 49.40%
48.51% 48.81% 49.63% 49.26% 50.27% 49.37% 42.61% 43.35%
53.74% 53.53% 53.06% 50.63% 50.83% 48.32% 45.74% 48.41%
45.84% 46.95% 45.93% 46.70% 48.42% 49.19% 48.03% 49.96%
47.66% 47.02% 47.61% 47.49% 48.65% 48.19% 45.82% 43.65%
40.06% 40.45% 39.96% 40.19% 42.51% 37.12% 37.59% 34.70%
Proxy Group Average
Company Name
Ohio Power Company
Wheeling Power Co
Cleco Power LLC
KCP&L Greater Missouri Operations Company
Idaho Power Co.
Gulf Power Company
Westar Energy (KPL)
Overall Average
50.35%
52.42%
36.99%
39.80%
44.60%
43.34%
51.35%
47.73%
50.53%
47.63%
47.01%
39.07%
45.90%
Ticker
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
AEP
CNL
DPL
HE
GXP
GXP
IDA
NEE
PNW
POR
PGN
PGN
SO
SO
SO
SO
WR
WR
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
55.97% 55.87% 55.97% 56.09% 53.62% 55.74% 56.04% 57.30%
54.72% 54.08% 54.24% 53.19% 53.31% 53.10% 53.10% 52.53%
56.32% 54.79% 55.49% 55.02% 55.26% 58.96% 57.00% 56.48%
52.95% 53.52% 53.05% 53.82% 53.19% 53.61% 53.60% 52.74%
53.59% 53.44% 54.03% 54.14% 54.58% 56.80% 48.82% 48.91%
56.41% 55.73% 55.96% 56.00% 56.06% 51.08% 51.26% 52.30%
0.00%
0.00%
48.39% 44.70% 45.16% 44.95% 44.41% 44.34%
47.54% 50.46% 49.93% 49.73% 46.55% 51.84% 52.59% 51.03%
54.44% 54.51% 54.23% 51.29% 52.39% 54.98% 54.01% 54.31%
52.11% 52.52% 48.21% 48.40% 51.74% 52.61% 53.17% 57.33%
36.84% 36.46% 36.28% 37.02% 38.75% 39.08% 39.71% 39.38%
49.48% 49.31% 54.55% 52.92% 53.57% 52.05% 54.93% 52.51%
38.58% 38.47% 38.27% 36.76% 36.79% 36.69% 37.44% 32.89%
44.31% 44.43% 44.74% 46.38% 41.15% 42.62% 42.37% 40.73%
44.19% 45.52% 45.73% 47.58% 47.63% 48.90% 40.81% 41.73%
39.42% 39.55% 40.57% 43.91% 44.68% 45.59% 46.52% 51.21%
51.80% 52.44% 52.55% 51.85% 52.27% 51.24% 49.24% 49.40%
38.81% 38.92% 39.70% 40.09% 40.75% 42.74% 39.56% 37.87%
48.51% 48.81% 49.63% 49.26% 50.27% 49.37% 42.61% 43.35%
53.74% 53.53% 53.06% 50.63% 50.83% 48.32% 45.74% 48.41%
42.80% 43.07% 43.81% 44.31% 45.45% 46.04% 43.69% 44.63%
48.89% 50.84% 48.04% 49.09% 51.39% 52.34% 52.37% 55.28%
50.26% 50.75% 51.08% 51.11% 53.29% 53.31% 51.27% 50.14%
48.53% 48.22% 49.39% 47.60% 49.55% 50.32% 49.91% 45.21%
50.28% 47.55% 48.41% 49.96% 49.80% 46.90% 44.29% 45.24%
41.59% 41.56% 41.55% 41.30% 41.97% 42.22% 37.82% 34.02%
43.51% 43.76% 42.85% 42.77% 43.57% 34.67% 34.65% 34.75%
36.62% 37.14% 37.07% 37.62% 41.44% 39.56% 40.54% 34.65%
Page 3 of 6
Short Term Debt Ratio
Company Name
Cleco Corp.
DPL, Inc.
Hawaiian Electric
IDACORP, Inc.
Portland General
Progress Energy
Southern Co.
Westar Energy
Ticker
AEP
CNL
DPL
NEE
GXP
HE
IDA
PNW
POR
PGN
SO
WR
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
2.41%
0.00%
0.00%
0.00%
0.00%
0.00%
4.78%
5.83%
6.23%
0.00%
3.78%
5.48%
7.70%
2.68%
3.00%
2.60%
0.67%
3.03%
8.19%
8.80%
8.00%
6.89%
2.79%
3.08%
8.42%
9.38%
4.23%
0.59%
0.58%
0.00%
0.47%
4.56%
1.38%
1.95%
6.35%
0.00%
0.00%
0.00%
0.00%
1.41%
3.86%
4.40%
5.30%
0.00%
2.80%
0.00%
0.00%
2.98%
3.46%
7.75%
4.08%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
6.84%
1.42%
0.00%
0.00%
0.00%
0.29%
0.00%
0.81%
3.01%
0.00%
0.13%
0.87%
0.98%
0.46%
0.77%
0.87%
2.16%
3.07%
2.98%
2.62%
3.04%
2.12%
0.80%
3.14%
2.18%
3.78%
Proxy Group Average
2.11%
Company Name
Ticker
AEP
AEP
AEP
AEP
AEP
AEP
AEP
Ohio Power Company
AEP
AEP
AEP
Wheeling Power Co
AEP
Cleco Power LLC
CNL
DPL
HE
GXP
KCP&L Greater Missouri Operations Company GXP
Idaho Power Co.
IDA
NEE
PNW
POR
PGN
PGN
SO
SO
Gulf Power Company
SO
SO
WR
Westar Energy (KPL)
WR
Overall Average
0.00%
0.30%
2.58%
4.17%
6.45%
1.98%
1.87%
2.63%
1.03%
0.51%
1.16%
2.58%
2009 Q1 2008 Q4 2008 Q3
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.59%
0.58%
0.00%
7.37%
5.22%
4.79%
10.23% 10.79%
8.99%
0.00%
0.00%
0.00%
5.48%
7.70%
2.68%
0.00%
2.80%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.49%
0.00%
0.00%
0.02%
0.00%
0.00%
0.00%
3.50%
3.91%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
5.96%
5.25%
6.08%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
4.78%
0.47%
1.02%
4.57%
0.00%
3.00%
0.00%
0.00%
0.00%
0.59%
0.00%
0.00%
1.71%
0.12%
0.00%
4.25%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
5.83%
4.56%
2.14%
4.02%
1.41%
2.60%
2.98%
0.00%
0.00%
0.00%
0.00%
0.01%
2.94%
0.12%
0.00%
1.60%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
2.41%
6.23%
1.38%
5.74%
11.09%
3.86%
0.67%
3.46%
0.00%
0.00%
1.63%
0.00%
0.67%
2.79%
0.00%
0.00%
6.29%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
1.95%
11.27%
7.49%
4.40%
3.03%
7.75%
6.84%
1.38%
4.64%
0.22%
0.70%
7.73%
0.00%
0.00%
4.36%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
3.78%
6.35%
7.71%
0.75%
5.30%
8.19%
4.08%
1.42%
0.00%
0.00%
0.84%
5.98%
5.46%
0.00%
0.00%
7.57%
Page 4 of 6
CAPITAL STRUCTURE - COMBINATION PROXY GROUP
Equity Ratio
Company Name
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
Ticker
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
52.96% 52.14% 52.51% 54.19% 54.88% 55.16% 55.09% 62.11%
47.39% 47.19% 46.56% 47.15% 47.63% 46.72% 45.63% 47.44%
69.31% 68.43% 67.16% 73.15% 65.68% 66.64% 73.21% 59.23%
28.95% 28.30% 27.40% 30.05% 28.13% 27.33% 27.97% 28.04%
63.18% 63.81% 63.53% 64.00% 64.30% 63.98% 65.57% 64.91%
49.09% 49.03% 48.85% 39.17% 38.63% 38.31% 36.51% 40.31%
47.88% 47.23% 47.85% 49.08% 47.80% 47.54% 46.83% 47.30%
51.49% 50.88% 50.64% 51.83% 50.45% 49.60% 49.66% 53.27%
50.53% 51.20% 50.12% 50.45% 50.10% 50.55% 51.84% 51.13%
51.68% 51.04% 50.37% 49.84% 49.91% 52.27% 53.91% 53.88%
57.54% 58.70% 57.91% 55.90% 55.97% 56.28% 58.10% 61.34%
Proxy Group Average
Company Name
Interstate Power and Light Company
Wisconsin Power and Light Company
Avista Corporation
Black Hills Colorado Electric Utility Company, L
Black Hills Power, Inc.
Cheyenne Light, Fuel and Power Company
CenterPoint Energy Houston Electric, LLC
Consolidated Edison Company of New York, In
Orange and Rockland Utilities, Inc.
Pike County Light & Power Company
Rockland Electric Company
Pacific Gas and Electric Company
South Carolina Electric & Gas Co.
Tampa Electric Company
Southern Indiana Gas and Electric Company, In
Overall Average
54.88%
46.96%
67.85%
28.27%
64.16%
42.49%
47.69%
50.98%
50.74%
51.61%
57.72%
51.21%
Ticker
LNT
LNT
AVA
BKH
BKH
BKH
CNP
ED
ED
ED
ED
DTE
PCG
SCG
TE
VVC
WEC
Equity Ratio
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
52.90% 52.04% 52.03% 55.62% 53.34% 54.84% 54.71% 62.94%
53.03% 52.24% 52.99% 52.77% 56.42% 55.47% 55.46% 61.29%
47.39% 47.19% 46.56% 47.15% 47.63% 46.72% 45.63% 47.44%
100.00% 100.00% 100.00% 100.00% 78.70% 78.95% 100.00%
NA
51.06% 48.95% 45.81% 64.59% 63.98% 63.40% 62.77% 62.27%
56.88% 56.34% 55.66% 54.87% 54.35% 57.57% 56.87% 56.19%
28.95% 28.30% 27.40% 30.05% 28.13% 27.33% 27.97% 28.04%
48.80% 48.76% 49.73% 48.59% 49.38% 48.73% 49.95% 51.26%
48.15% 49.79% 47.36% 51.52% 51.49% 50.50% 54.60% 50.36%
55.77% 56.69% 57.01% 55.90% 56.34% 56.70% 57.71% 58.04%
100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00% 100.00%
49.09% 49.03% 48.85% 39.17% 38.63% 38.31% 36.51% 40.31%
47.88% 47.23% 47.85% 49.08% 47.80% 47.54% 46.83% 47.30%
51.49% 50.88% 50.64% 51.83% 50.45% 49.60% 49.66% 53.27%
50.53% 51.20% 50.12% 50.45% 50.10% 50.55% 51.84% 51.13%
51.68% 51.04% 50.37% 49.84% 49.91% 52.27% 53.91% 53.88%
57.54% 58.70% 57.91% 55.90% 55.97% 56.28% 58.10% 61.34%
Page 5 of 6
Company Name
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
Ticker
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
47.04% 41.56% 44.23% 45.81% 40.37% 42.68% 43.06% 36.26%
48.90% 49.70% 49.59% 51.72% 40.39% 42.97% 42.93% 48.44%
30.69% 31.57% 32.84% 26.85% 34.32% 26.34% 26.79% 40.77%
71.05% 71.70% 72.60% 69.95% 71.87% 72.67% 72.03% 71.96%
34.69% 35.59% 36.47% 33.36% 33.87% 33.58% 34.09% 32.44%
50.91% 50.97% 51.15% 60.83% 61.37% 60.94% 62.72% 55.50%
47.84% 47.49% 48.59% 48.69% 48.90% 50.70% 51.80% 46.16%
44.90% 45.69% 45.29% 44.16% 47.62% 48.83% 49.75% 46.23%
47.41% 48.31% 48.38% 48.08% 45.55% 46.75% 47.35% 48.49%
48.32% 48.96% 49.63% 50.16% 49.91% 47.73% 46.06% 38.93%
39.13% 40.22% 40.21% 36.11% 39.37% 39.74% 41.90% 31.66%
Proxy Group Average
Avista Corporation
Overall Average
42.63%
46.83%
31.27%
71.73%
34.26%
56.80%
48.77%
46.56%
47.54%
47.46%
38.54%
46.58%
LNT
LNT
AVA
BKH
BKH
BKH
CNP
ED
ED
ED
ED
DTE
PCG
SCG
TE
VVC
WEC
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
47.10% 40.90% 41.44% 44.38% 40.76% 43.18% 43.55% 36.66%
46.97% 42.23% 47.01% 47.23% 39.99% 42.18% 42.56% 35.86%
48.90% 49.70% 49.59% 51.72% 40.39% 42.97% 42.93% 48.44%
0.00%
0.00%
0.00%
0.00%
21.30%
0.00%
0.00%
NA
48.94% 51.05% 54.19% 35.41% 36.02% 36.60% 37.23% 37.73%
43.12% 43.66% 44.34% 45.13% 45.65% 42.43% 43.13% 43.81%
71.05% 71.70% 72.60% 69.95% 71.87% 72.67% 72.03% 71.96%
50.87% 48.84% 50.27% 49.18% 50.62% 51.27% 48.67% 46.62%
43.65% 50.21% 52.64% 40.16% 41.19% 39.75% 45.40% 41.20%
44.23% 43.31% 42.99% 44.10% 43.66% 43.30% 42.29% 41.96%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
50.91% 50.97% 51.15% 60.83% 61.37% 60.94% 62.72% 55.50%
47.84% 47.49% 48.59% 48.69% 48.90% 50.70% 51.80% 46.16%
44.90% 45.69% 45.29% 44.16% 47.62% 48.83% 49.75% 46.23%
47.41% 48.31% 48.38% 48.08% 45.55% 46.75% 47.35% 48.49%
48.32% 48.96% 49.63% 50.16% 49.91% 47.73% 46.06% 38.93%
39.13% 40.22% 40.21% 36.11% 39.37% 39.74% 41.90% 31.66%
Page 6 of 6
Company Name
Avista Corp.
Black Hills Corp.
Center Point Energy
Consolidated Edison
DTE Energy Co.
PG&E Corp
SCANA Corp.
TECO Energy, Inc.
Vectren Corp.
Wisconsin Energy
Ticker
LNT
AVA
BKH
CNP
ED
DTE
PCG
SCG
TE
VVC
WEC
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
0.00%
6.30%
3.27%
0.00%
4.75%
2.16%
1.86%
1.62%
3.71%
3.11%
3.85%
1.14%
11.99% 10.31% 11.44%
4.12%
0.00%
0.00%
0.00%
0.00%
0.00%
7.02%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
2.13%
0.60%
0.00%
2.64%
1.83%
2.44%
0.34%
2.64%
0.00%
0.00%
0.00%
0.00%
0.00%
0.75%
0.77%
4.20%
4.28%
5.27%
3.56%
2.23%
3.30%
1.76%
1.37%
6.54%
3.61%
3.43%
4.07%
4.01%
1.92%
1.56%
0.59%
0.51%
2.06%
0.49%
1.50%
1.47%
4.35%
2.70%
0.81%
0.38%
0.00%
0.00%
0.00%
0.00%
0.18%
0.00%
0.04%
7.19%
3.33%
1.07%
1.88%
7.99%
4.67%
3.98%
0.00%
7.00%
Proxy Group Average
Company Name
Avista Corporation
Overall Average
2.49%
6.21%
0.88%
0.00%
1.58%
0.72%
3.54%
2.46%
1.72%
0.93%
3.74%
2.21%
Ticker
LNT
LNT
AVA
BKH
BKH
BKH
CNP
ED
ED
ED
ED
DTE
PCG
SCG
TE
VVC
WEC
2010 Q2 2010 Q1 2009 Q4 2009 Q3 2009 Q2 2009 Q1 2008 Q4 2008 Q3
0.00%
7.06%
6.53%
0.00%
5.90%
1.98%
1.74%
0.40%
0.00%
5.54%
0.00%
0.00%
3.60%
2.35%
1.97%
2.85%
3.71%
3.11%
3.85%
1.14%
11.99% 10.31% 11.44%
4.12%
0.00%
0.00%
0.00%
0.00%
0.00%
21.05%
0.00%
NA
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.33%
2.40%
0.00%
2.22%
0.00%
0.00%
1.37%
2.12%
8.20%
0.00%
0.00%
8.33%
7.32%
9.75%
0.00%
8.44%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.00%
0.75%
0.77%
4.20%
4.28%
5.27%
3.56%
2.23%
3.30%
1.76%
1.37%
6.54%
3.61%
3.43%
4.07%
4.01%
1.92%
1.56%
0.59%
0.51%
2.06%
0.49%
1.50%
1.47%
4.35%
2.70%
0.81%
0.38%
0.00%
0.00%
0.00%
0.00%
0.18%
0.00%
0.04%
7.19%
3.33%
1.07%
1.88%
7.99%
4.67%
3.98%
0.00%
7.00%

Direct Testimony and Schedules John J. Reed Before

Transcription

Similar documents

Program for Grey Rock 2015-06 - Maryland Society Sons of the

Indonesian Diaspora Network Southern California

DOMAIN REGISTRATION AND HOSTING OF A WEBSITE: THE

Agenda Summary - Manhattan Beach Unified School District

Fall 2014 - Towson University

electronic access to court records

Exhibit C - Hunter Wise Commodities

Advertising Specs / Policies

nfusion step by step for newbies

Brian Jeppesen Counselor - StudentTheses@CBS