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U T IL IT IE S i ISSiOM
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNTAIN POWER FOR
APPROVAL OF CHANGES TO ITS
ELECTRIC SERVICE SCHEDULES
AND A PRICE INCREASE OF $32.7
MILLION, OR APPROXIMATELY
15.0 PERCENT
CASE NO. PAC-E-11-12
Direct Testimony of Samuel C. Hadaway
ROCKY MOUNTAIN POWER
CASE NO. PAC-E-11-12
May 2011
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Introduction and Purpose of Testimony
Q. Please state your name, occupation, and business address.
A. My name is Samuel C. Hadaway. I am a Principal in FINANCO, Inc., Financial
Analysis Consultants, 3520 Executive Center Drive, Austin, Texas 78731.
Q. On whose behalf are you testifying?
A. I am testifying on behalf of Rocky Mountain Power (“RMP” or the “Company”).
Q. Briefly describe your educational and professional background.
A. A summary of my educational background and professional experience is
contained in Appendices A and B.
Q. What is the purpose of your testimony?
A. The purpose of my testimony is to estimate RMP's cost of equity capital.
Q. Please define the term "cost of equity capital" (“COE”).
A. COE is the rate of return that equity investors require or expect to receive from
their investment in common stocks. Conceptually COE is no different than the
interest rate on debt or the cost of preferred stock. Equity investors expect a return
on their capital commensurate with the risks they take and consistent with returns
that might be available from other similar investments.
Summary of Recommendations
Q. Have you determined the COE for utilities comparable to the Company?
A. Yes. I have applied the discounted cash flow (“DCF”) model to estimate COE for
utilities comparable to RMP. The results of that analysis indicate that the
comparable group's COE is in the range of 10.1 percent to 10.5 percent. I also
perform an equity risk premium analysis. That analysis indicates a COE in the
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1 range of 10.25 percent to 10.45 percent. Based on these quantitative results and
2 my further review of recent interest rate increases and projections for even higher
3 rates during the coming year, the appropriate return on equity (“ROE”) for RMP
4 is 10.5 percent. This is a reasonable ROE for establishing the Company’s rates at
5 this time and should be authorized by the Commission.
6 Q. Did this Commission as well as the Washington Utilities and Transportation
7 Commission recently conclude that lower ROEs were appropriate for RMP?
8 A. Yes. On February 28, 2011, in Case No. PAC-E-10-07 (the 2010 General Rate
9 Case”), this Commission found the Company's ROE to be 9.9 percent based on
10 the timing of the evidence in that case. On March 25, 2011, in Docket UE-
11 100749, the Washington Commission found an ROE of 9.8 percent, again based
12 on the timing of the evidence in that case.
13 Q. Have market conditions changed since the records in those cases were
14 developed?
15 A. Yes. The financial data available at the time of rebuttal testimony in the prior
16 cases was from the August to October 2010 time period, which happened to
17 correspond to the lowest level of long-term utility interest rates in over 30 years
18 (see Exhibit No. 14, page 2 and Exhibit No. 17, pages 1 and 2). In those cases, the
19 Commissions, in my opinion, made their decisions based upon evidence that
20 reflected a trough in long-term utility bond interest rates. As shown in Table 1 on
21 page 7 of this testimony, between the availability dates of the data I used in my
22 direct testimony in the 2010 General Rate Case (April 2010) and the data I used to
23 prepare rebuttal testimony (October 2010), single-A utility bond yields fell 71
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basis points (0.71%). Since October 2010, single-A utility bond yields have
increased by 45 basis points (as of April 2011). The record in the Company's prior
case, therefore, reflected a sharp drop in interest rates that has now been
substantially reversed. Hence, irrespective of our differences about the
appropriate ROEs in the prior cases, since those cases were presented, COE has
increased and the allowed ROE in the present case should reflect this fact.
How is your analysis structured?
In my DCF analysis, I apply a comparable company approach. RMP's cost of
equity cannot be estimated directly from its own market data because the
Company is a wholly-owned subsidiary of MidAmerican Energy Holdings
Company. As such, RMP does not have publicly traded common stock or other
independent market data that would be required to estimate its COE directly. I
begin my comparable company review with all the electric utilities that are
included in the Value Line Investment Survey (Value Line). Value Line is a
widely-followed, reputable source of financial data that is often used by
professional regulatory economists. To improve the group's comparability with
RMP, which has a senior secured bond rating of A from Standard & Poor’s (S&P)
and A2 from Moody’s Investors Service (Moody’s), I restricted the group to
companies with senior secured bond ratings of at least A- by S&P or A3 by
Moody's. I also required the comparable companies to derive at least 70 percent
of their revenues from regulated utility sales, to have consistent financial records
not affected by recent mergers or restructuring, and to have a consistent dividend
record with no dividend cuts or resumptions during the past two years. The
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1 fundamental characteristics and bond ratings of the 16 companies in my
2 comparable group are presented in Exhibit No. 13, page 1.
3 In my risk premium analysis, I present estimates from both current and
4 projected single-A utility bond yields for all of 2011. These rates are consistent
5 with the Company's single-A bond ratings. As I will discuss later in this
6 testimony, however, my risk premium estimates continue to be depressed by the
7 U.S. government's ongoing monetary policies, and they do not reflect the much
8 higher interest rates that are expected in 2012. For these reasons, my risk
9 premium results are a conservative estimate of the Company's required COE. The
10 data sources and the details of my cost of equity studies are contained in Exhibit
11 Nos. 13 through 17.
12 Q. How is the remainder of your testimony organized?
13 A. My testimony is divided into three additional sections. Following this
14 introduction, I review general capital market costs and conditions and discuss
15 recent developments in the electric utility industry that may affect the cost of
16 capital. In the following section, I review various methods for estimating the cost
17 of equity. In this section, I discuss comparable earnings methods, equity risk
18 premium methods, and the discounted cash flow model. In the final section, I
19 apply the DCF and risk premium models to estimate RMP's cost of equity, I
20 discuss the details of my cost of equity studies, and I summarize my ROE
21 recommendations.
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1 Fundamental Factors That Affect the Cost of Equity
2 Q. What is the current outlook for the U.S. economy?
3 A. The U.S. economy is expected to continue its slow rate of recovery. While
4 unemployment remains stubbornly high at 9 percent, manufacturing output has
5 increased and in some areas new hiring has begun. Forecasts for 2012 indicate
6 continuing, but slow recovery with new job creation a fundamental concern. Even
7 with the government's continuing expansionary monetary policy, since the low
8 levels reached in September, both Treasury bond and corporate bond interest rates
9 have increased and are expected to increase further in 2012. Although caution
10 remains, and utility stocks remain relatively depressed, the overall stock market
11 has recovered significantly from its March 2009 low levels. All of these factors
12 point to gradually improving conditions this year and into 2012.
13 Q. What has been the experience in the U.S. capital markets for the past several
14 years?
15 A. In Exhibit No. 14, page 1,1 provide a 10-year review of annual interest rates and
16 rates of inflation in the U.S. economy. During the past 10 years, interest rates and
17 inflation were generally lower than in the previous decade. Inflation, as measured
18 by the Consumer Price Index (“CPI”), fluctuated between zero percent in 2008
19 and 4.1 percent in the energy induced period that occurred in 2007. The decade's
20 average inflation rate (2.4 percent) was approximately 100 basis points lower than
21 the longer-term average rate of the past 60 years (see Exhibit No. 15). Interest
22 rates declined steadily over most of the period, with the 2010 single-A utility rate
23 at its lowest level for more than 30 years (see Exhibit No. 17, pages 1 and 2).
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1 Q. What has been the trend in long-term interest rates during the past three
2 years?
3 A. The month-by-month interest rate data for the past three years are presented in
4 Exhibit No. 14, page 2, and summarized below in Table 1.
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Month
Table 1
Long-Term Interest Rate Trends
Single-A 30-Year
Utility Rate Treasury Rate
Single-A
Utility Spread
Jan-08 6.02 4.33 1.69
Feb-08 6.21 4.52 1.69
Mar-08 6.21 4.39 1.82
Apr-08 6.29 4.44 1.85
May-08 6.28 4.60 1.68
Jun-08 6.38 4.69 1.69
Jul-08 6.40 4.57 1.83
Aug-08 6.37 4.50 1.87
Sep-08 6.49 4.27 2.22
Oct-08 7.56 4.17 3.39
Nov-08 7.60 4.00 3.60
Dec-08 6.52 2.87 3.65
Jan-09 6.39 3.13 3.26
Feb-09 6.30 3.59 2.71
Mar-09 6.42 3.64 2.78
Apr-09 6.48 3.76 2.72
May-09 6.49 4.23 2.26
Jun-09 6.20 4.52 1.68
Jul-09 5.97 4.41 1.56
Aug-09 5.71 4.37 1.34
Sep-09 5.53 4.19 1.34
Oct-09 5.55 4.19 1.36
Nov-09 5.64 4.31 1.33
Dec-09 5.79 4.49 1.30
Jan-10 5.77 4.60 1.17
Feb-10 5.87 4.62 1.25
Mar-10 5.84 4.64 1.20
Apr-10 5.81 4.69 1.12
May-10 5.50 4.29 1.21
Jun-10 5.46 4.13 1.33
Jul-10 5.26 3.99 1.27
Aug-10 5.01 3.80 1.21
Sep-10 5.01 3.77 1.24
Oct-10 5.10 3.87 1.23
Nov-10 5.37 4.19 1.18
Dec-10 5.56 4.42 1.14
Jan-11 5.57 4.52 1.05
Feb-11 5.68 4.65 1.03
Mar-11 5.56 4.51 1.05
Apr-11 5.55 4.50 1.05r3-Mo Avg 5.60 4.55 1.04
12-Mo AvgF 5.39 F 4.22 1.17
Sources: Mergent Bond Record (Utility Rates); www.federalreserve.gov
(Treasury rates). Three month average is for February 2011 -April 2011.
Twelve month average is for May 2010-April 2011.
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The data in Table 1 vividly illustrate the uptrend in interest rates that has occurred
since late summer 2010 and the market turmoil that has occurred over the past
three years. Since their lowest levels reached in August and September 2010, both
utility interest rates and yields on long-term Treasury bonds have increased by
about 50 basis points. Over the past three years, interest rates have shown the
widest fluctuations in recent history. The Federal Reserve’s continuing efforts to
hold down borrowing costs for banks (the Fed Funds rate) and lower rates on U.S.
Treasury bonds have now extended to high quality corporate borrowers as well.
While the effects of market turbulence may not be easily captured in financial
models for estimating the rate of return, equity market turbulence and the
resulting elevated level of risk aversion should be considered explicitly in
estimates of the cost of equity capital.
Do the smaller spreads between yields on single-A utility bonds and U.S.
Treasury bonds mean that the markets have fully recovered from the
economic turmoil that resulted from the financial crisis?
No. While markets have stabilized considerably from the conditions that existed
in late 2008, investors remain concerned about high unemployment, large federal
deficits, the Mideast turmoil and skyrocketing commodity (oil, gold, and silver)
and gasoline prices, and the potential for further fallout from foreclosures and
other effects of the financial crisis. These factors combined with sluggish growth
in gross domestic product (“GDP”) during the first quarter of 2011 continue to
cause a high level of market volatility and contribute to heightened investor risk
aversion.
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Q. What do forecasts for the economy and interest rates show for the coming
year?
A. Interest rates are expected to rise substantially. In Exhibit No. 14), page 3, I
provide Standard and Poor’s (S&P) most recent interest rate forecast from its
Trends & Projections publication for April 2011. Table 2 below summarizes the
interest rate forecasts:
Table 2
Standard & Poor’s Interest Rate Forecast
Apr. 2011 Average Average
Average 2011 Est. 2012 Est.
Treasury Bills 0.1% 0.3% 2.1%
10-Yr. T-Bonds 3.5% 3.9% 5.5%
30-Yr. T-Bonds 4.5% 4.9% 6.3%
Aaa Corporate Bonds 5.2%_____ 5.5%________7.2%
Sources: www.federalreserve.gov. (Current Rates). Standard &
Poor’s Trends & Projections, April 2011, page 8 (Projected Rates).
These data show that, dining 2011, average long-term Treasury interest rates are
expected to increase by 40 basis points relative to their April 2011 levels and that
rates will rise substantially more during 2012. Yields on all the other bonds shown
in the table are expected to increase by similar or larger amounts. The interest rate
increases reported by S&P are consistent with the Federal Reserve ending its so-
called Quantitative Easing 2 program (i.e., lower demand for Treasuries, all else
equal, will lead to lower prices and higher yields)1 and a sluggishly improving
U.S. economy. Such expectations for large increases in fixed income yields
indicate that the expected rates of return for utilities, which must compete with
such investments for required capital, are increasing as well.
1 See The Wall Street Journal, "Fed Takes Foot Off the Gas," April 28, 2011, page Al.
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1 Q. How have utility stocks performed during the past several years?
2 A. Utility stock prices have fluctuated widely. The wider fluctuations in more recent
3 years are vividly illustrated in the following Graph 1, which depicts Dow Jones
4 Utility Average (DJUA) prices over the past 25 years.
Graph 1
Dow Jones Utility Average
1987-2011
600
500
400
300
200
100
yN
5 In this environment, investors’ return expectations and requirements for providing
6 capital to the utility industry remain high relative to the longer-term, traditional
7 view of the utility industry. Increased market volatility for utility shares causes
8 investors to require a higher rate of return.
9 Q. How have utility stocks performed relative to the overall market recovery
10 since March 2009?
11 A. Utility stock prices have lagged far behind the overall market. Graph 2 shows the
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monthly levels for the DJUA versus the broader market S&P 500 Index since the
market lows that occurred in February and March of 2009.
Graph 2
Dow Jones Utility Average
vs. S&P 500
Mar. 2009-Apr. 2011
1600.00
1400.00
1200.00
1000.00
itt nr S&P 500
800.00
600.00
400.00
DJUA 200.00
0.00
While the S&P 500 has increased significantly since March 2009, utility prices
have remained relatively flat. This result is a further indication that the cost of
equity for utility companies has not declined to the same extent as interest rates
have fallen or to the same extent that the cost of equity may have come down for
the broader equity market. The relatively lower prices for utility shares indicate
that the cost of capital for utilities is higher.
Graph 3 further illustrates this result by showing the cumulative
percentage change in the two equity indexes since the March 2009 lows.
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Graph 3
Dow Jones Utility Average
vs. S&P 500
Cumulative % Change
Mar. 2009 -Apr. 2011 90.00%
80.00%
70.00%
60.00%
S&P 500 50.00%
40.00%
30.00%
20.00%
DJUA 10.00%
L 0.00%
1 The general market, as represented by the S&P 500, has recovered over 85
2 percent (85.50%) from its March 2009 lows. During the same period, utility
3 stocks, as measured by the DJUA, have increased by only about 32 percent
4 (32.44%). While utility stock prices are normally less volatile than the general
5 market, their roughly one-third recovery relative to the general market since
6 March 2009 again points out the market difficulties that utilities face and the
7 continuing relatively higher cost of equity for utility companies.
8 Q. What is the industry’s current fundamental position?
9 A. The industry has seen significant volatility both in terms of fundamental operating
10 characteristics and the effects of the economy. While many companies have
11 refocused their businesses on more traditional utility service, the effects of
12 deregulation of the wholesale power markets and continuing fuel price
13 uncertainties remain prominent. The economic crisis has also reduced sales
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1 volumes and increased the difficulty of planning for future load requirements.
2 Value Line reflects its views in its recent review of electric utility prospects:
3 Value Line Investor Survey
4 Some utilities will probably report lower earnings in 2011 or 2012.
5 Favorable weather patterns in 2010 will make for tough
6 comparisons in 2011. This year and next, unfavorable market
7 conditions will affect many nonregulated subsidiaries of utility
8 holding companies.
9 Electric utility stocks, as a group, are up just slightly in 2011, as
10 are the broader market averages. Despite the lackluster
11 performance, many of these equities are trading within their 2014-
12 2016 Target Price Range. (Value Line Investor Survey, March 25,
13 2011, p. 901).
14 Standard & Poor's also provides perspective on the relatively poor stock
15 price performance for electric utilities.
16 S&P Industry Survey
17 Electric Utility Shares Underperform in 2010
18 The S&P Electric Utilities subindex was down 0.5% in 2010,
19 compared with a 12.8% increase for the benchmark S&P 500
20 Composite stock index and a 14.2% increase for the broader S&P
21 1500 SuperComposite stock index. This followed a similar 0.5%
22 decrease in 2009 for the S&P Electric Utilities subindex, versus
23 gains of 23.5% and 24.3% for the S&P 500 and the S&P 1500,
24 respectively. In addition to the ongoing weakness in both the
25 housing and power markets, we believe the underperformance of
26 electric utility stocks in both 2010 and in 2009 also reflected the
27 belief that other sectors would provide better investor returns once
28 the economy started to recover. (Standard & Poor's Electric Utility
29 Industry Survey, February 24, 2011, p. 6).
30 Credit market gyrations and the volatility of utility shares demonstrate the
31 increased uncertainties that utility investors face. These uncertainties translate into
32 a higher cost of capital.
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1 Q. Do utilities continue to face the operating and financial risks that existed
2 prior to the financial crisis?
3 A. Yes. Prior to the recent financial crisis, the greatest consideration for utility
4 investors was the industry's continuing transition to more open market conditions
5 and competition. With the passage of the Energy Policy Act (EPACT) in 1992
6 and the Federal Energy Regulatory Commission's (FERC) Order 888 in 1996, the
7 stage was set for vastly increased competition in the electric utility industry.
8 EPACT's mandate for open access to the transmission grid and FERC's
9 implementation through Order 888 effectively opened the market for wholesale
10 electricity to competition. Previously protected utility service territory and lack of
11 transmission access in some parts of the country had limited the availability of
12 competitive bulk power prices. EPACT and Order 888 have essentially eliminated
13 such constraints for incremental power needs.
14 As expected, the opening of previously protected utility markets to
15 competition, the uncertainty created by the removal of regulatory protection,
16 continuing fuel price volatility and concerns about the impact of climate change
17 legislation have raised the level of uncertainty about investment returns across the
18 entire industry.
19 Q. Is RMP affected by these same uncertainties and increasing utility capital
20 costs?
21 A. Yes. To some extent all electric utilities are being affected by the industry's
22 transition to competition. Although retail deregulation has not occurred in the
23 state of Idaho, Rocky Mountain Power’s power costs and other operating
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1 activities have been significantly affected by transition and restructuring events
2 around the country. In fact, the uncertainty associated with the changes that are
3 transforming the utility industry as a whole, as viewed from the perspective of the
4 investor, remain a factor in assessing any utility's cost of common equity and
5 required ROE, including the ROE from Rocky Mountain Power’s operations in
6 Idaho.
7 Q. Are there other factors that add to the Company’s risk profile?
8 A. Yes, there are two significant factors. First, when regulators authorize ROEs that
9 are less than 10 percent, the financial markets perceive the regulatory
10 environment as being less credit supportive. Even in the lower interest rate
11 environment that existed in 2010, the average allowed rate of return for other
12 utilities around the country was well above 10 percent. The distinction of being
13 subject to regulation in two jurisdictions that have authorized among the lowest
14 allowed rates of return in the country is clearly a factor that increases the
15 Company’s perceived regulatory risk.
16 Second, the Company is unique in the amount of capital that it is
17 expending to provide generation and transmission service to its customers in
18 relation to its depreciation expense. This requires that it annually subject its
19 operations and rates to review in multiple proceedings in six jurisdictions. As a
20 consequence, the financial markets focus additional attention on the Company's
21 regulatory risk profile. Until recent rate and EC AM orders, the Company has been
22 able to assure the financial markets that it was operating in credit supportive
23 regulatory environments and being permitted to recover its prudent costs on a
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timely basis. Providing this assurance in the face of recent orders will be more
difficult as the regulatory risk may be perceived as higher.
Q. How do capital market concerns and financial risk perceptions affect the cost
of equity capital?
A. As I discussed previously, equity investors respond to changing assessments of
risk and financial prospects by changing the price they are willing to pay for a
given security. When the risk perceptions increase or financial prospects decline,
investors refuse to pay the previously existing market price for a company's
securities and market supply and demand forces then establish a new lower price.
The lower market price typically translates into a higher cost of capital through a
higher dividend yield requirement as well as the potential for increased capital
gains if prospects improve. In addition to market losses for prior shareholders, the
higher cost of capital is transmitted directly to the company by the need to earn a
higher cost of capital on existing and new investments just to maintain the stock’s
new lower price level and the reality that the firm must issue more shares to raise
any given amount of capital for future investment. The additional shares also
impose additional future dividend requirements and may reduce future earnings
per share growth prospects if the proceeds of the share issuance are unable to earn
their expected rate of return.
Q. How have regulatory commissions responded to these changing market and
industry conditions?
A. Over the past five years, quarterly allowed ROEs have averaged about 10.4
percent. For 2010, the average rate for integrated electric utilities was 10.38
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1 percent and for the 1st Quarter of 2011 it was 10.18 percent.2 Table 3 below
2 summarizes the ROE data, including delivery, fully integrated, and special-
3 purpose companies:
4 Table 3
5 Authorized Electric Utility Equity Returns
6 2007_______2008_______2009 2010 2011
7 1st Quarter 10.27% 10.45% 10.29% 10.66% 10.35%
8 2nd Quarter 10.27% 10.57% 10.55% 10.08%
9 3rd Quarter 10.02% 10.47% 10.46% 10.27%
10 4th Quarter_________10.56% 10.33% 10.54% 10.30%_________
11 Full Year Average 10.36% 10.46% 10.48% 10.34% 10.35%
12 Average Utility
13 Debt Cost 6.11% 6.65% 6.28% 5.55% 5.66%
14 Indicated Average
15 Risk Premium 4.25% 3.81% 4.20% 4.79% 4.69%
16 ;_____________________________
17 Source: Regulatory Focus, Regulatory Research Associates, Inc., Major Rate
18 Case Decisions, April 5, 2011. Utility debt costs are the "average" public utility
19 bond yields as reported by Moody’s.
20 Based on these data, over the past five years, the allowed equity risk premium for
21 electric utilities has ranged between 3.81 percent and 4.79 percent. These data
22 show clearly that the recently allowed ROEs below 10 percent set for RMP were
23 well below the average rates of return deemed appropriate by other state
24 regulators.
25 Estimating the Cost of Equity Capital
26 Q. What is the purpose of this section of your testimony?
27 A. The purpose of this section is to compare the strengths and weaknesses of several
28 of the most widely used methods for estimating the cost of equity. Estimating the
29 cost of equity is fundamentally a matter of informed judgment. The various
See Exhibit No. 13, page 2.
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1 models provide a concrete link to actual capital market data and assist with
2 defining the various relationships that underlie the ROE estimation process.
3 (Please see Appendix C for further technical discussion of the DCF and risk
4 premium models.)
5 Q. How is the fair rate of return in the regulatory process related to the
6 estimated cost of equity capital?
7 A. The regulatory process is guided by fair rate of return principles established in the
8 U.S. Supreme Court cases, Bluefield Water Works and Hope Natural Gas:
9 A public utility is entitled to such rates as will permit it to earn a
10 return on the value of the property which it employs for the
11 convenience of the public equal to that generally being made at the
12 same time and in the same general part of the country on
13 investments in other business undertakings which are attended by
14 corresponding risks and uncertainties; but it has no constitutional
15 right to profits such as are realized or anticipated in highly
16 profitable enterprises or speculative ventures. Bluefield Water
17 Works & Improvement Company v. Public Service Commission of
18 West Virginia, 262 U.S. 679, 692-693 (1923).
19 From the investor or company point of view, it is important that
20 there be enough revenue not only for operating expenses, but also
21 for the capital costs of the business. These include service on the
22 debt and dividends on the stock. By that standard the return to the
23 equity owner should be commensurate with returns on investments
24 in other enterprises having corresponding risks. That return,
25 moreover, should be sufficient to assure confidence in the financial
26 integrity of the enterprise, so as to maintain its credit and to attract
27 capital. Federal Power Commission v. Hope Natural Gas Co., 320
28 U.S. 591, 603 (1944).
29 Based on these principles, the fair rate of return should closely parallel investor
30 opportunity costs as discussed above. If a utility earns its market cost of equity,
31 neither its stockholders nor its customers should be disadvantaged.
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Q. Please provide an overview of the cost of equity capital estimation process.
A. The cost of equity is the rate of return that common stockholders expect, just as
interest on bonds and dividends on preferred stock are the returns that investors in
those securities expect. Unlike returns from debt and preferred stocks, however,
the equity return is not directly observable in advance and, therefore, it must be
estimated or inferred from capital market data and trading activity.
An example helps to illustrate the cost of equity concept. Assume that an
investor buys a share of common stock for $20 per share. If the stock's expected
dividend is $1.00, the expected dividend yield is 5.0 percent ($1.00 / $20 = 5.0
percent). If the stock price is also expected to increase to $21.20 after one year,
this one dollar and 20 cent expected gain adds an additional 6.0 percent to the
expected total rate of return ($1.20 / $20 = 6.0 percent). Therefore, buying the
stock at $20 per share, the investor expects a total return of 11.0 percent: 5.0
percent dividend yield, plus 6.0 percent price appreciation. In this example, the
total expected rate of return of 11.0 percent is the appropriate measure of the cost
of equity capital, because it is this rate of return that caused the investor to
commit the $20 of equity capital in the first place. If the stock were riskier, or if
expected returns from other investments were higher, investors would have
required a higher rate of return from the stock, which would have resulted in a
lower initial purchase price in market trading.
Each day market rates of return and prices change to reflect new investor
expectations and requirements. For example, when interest rates on bonds and
savings accounts rise, utility stock prices usually fall. This is true, at least in part,
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1 because higher interest rates on these alternative investments make utility stocks
2 relatively less attractive, which causes utility stock prices to decline in market
3 trading. This competitive market adjustment process is quick and continuous, so
4 that market prices generally reflect investor expectations and the relative
5 attractiveness of one investment versus another. The data presented previously in
6 Tables 1 and 2 and the relative market performance of utility stocks versus the
7 general market shown in Graphs 2 and 3 illustrate this fundamental financial
8 principle. Therefore, to estimate the cost of equity one must apply informed
9 judgment about the relative risk of the company in question as well as knowledge
10 about the risk and expected rate of return characteristics of other available
11 investments.
12 Q. How does the market account for risk differences among the various
13 investments?
14 A. Risk-retum tradeoffs among capital market investments have been the subject of
15 extensive financial research. Literally dozens of textbooks and hundreds of
16 academic articles have addressed the issue. Generally, such research confirms the
17 common sense conclusion that investors will take additional risks only if they
18 expect to receive a higher rate of return. Empirical tests consistently show that
19 returns from low risk securities, such as U.S. Treasury bills, are the lowest; that
20 returns from longer-term Treasury bonds and corporate bonds are increasingly
21 higher as risks increase; and generally, returns from common stocks and other
22 more risky investments are even higher. These observations provide a sound
23 theoretical foundation for both the DCF and risk premium methods for estimating
Hadaway, Di - 20
Rocky Mountain Power
1 the cost of equity capital. These methods attempt to capture the well founded risk-
2 return principle and explicitly measure investors' rate of return requirements.
3 Q. Can you illustrate the capital market risk-return principle that you just
4 described?
5 A. Yes. The following graph depicts the risk-return relationship that has become
6 widely known as the Capital Market Line (CML). The CML offers a graphical
7 representation of the capital market risk-return principle. The graph is not meant
8 to illustrate the actual expected rate of return for any particular investment, but
9 merely to illustrate in a general way the risk-return relationship.
Risk-Return Tradeoffs
The Capital Market Line
cL-=s0a:4—o
04-»COa:
~o
0o0Q.
X
LLI
20%
15%
10%
5%
Treasury
Bills
Common
Stocks
Speculative
Investments
Investment
Grade Bonds
Non-investment
Grade Bonds
Higher Risk
Hadaway, Di - 21
Rocky Mountain Power
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As a continuum, the CML can be viewed as an available opportunity set for
investors. Those investors with low risk tolerance or investment objectives that
mandate a low risk profile should invest in assets depicted in the lower left-hand
portion of the graph. Investments in this area, such as Treasury bills and short-
maturity, high quality corporate commercial paper, offer a high degree of investor
certainty. Before considering the potential effects of inflation, such assets are
virtually risk-free.
Investment risks increase as one moves up and to the right along the CML.
A higher degree of uncertainty exists about the level of investment value at any
point in time and about the level of income payments that may be received.
Among these investments, long-term bonds and preferred stocks, which offer
priority claims to assets and income payments, are relatively low risk, but they are
not risk-free. The market value of long-term bonds, even those issued by the U.S.
Treasury, often fluctuates widely when government policies or other factors cause
interest rates to change.
Farther up the CML continuum, common stocks are exposed to even more
risk, depending on the nature of the underlying business and the financial strength
of the issuing corporation. Common stock risks include market-wide factors, such
as general changes in capital costs, as well as industry and company specific
elements that may add further to the volatility of a given company's performance.
As I will illustrate in my risk premium analysis, common stocks typically are
more volatile (have higher risk) than high quality bond investments and,
therefore, they reside above and to the right of bonds on the CML graph. Other
Hadaway, Di - 22
Rocky Mountain Power
1 more speculative investments, such as stock options and commodity futures
2 contracts, offer even higher risks (and higher potential returns). The CML's
3 depiction of the risk-return tradeoffs available in the capital markets provides a
4 useful perspective for estimating investors' required rates of return.
5 Q. What specific methods and capital market data are used to evaluate the cost
6 of equity?
7 A. Techniques for estimating the cost of equity normally fall into three groups:
8 comparable earnings methods, risk premium methods, and DCF methods. The
9 first set of estimation techniques, the comparable earnings methods, has evolved
10 over time. The original comparable earnings methods were based on book
11 accounting returns. This approach developed ROE estimates by reviewing
12 accounting returns for unregulated companies thought to have risks similar to
13 those of the regulated company in question. These methods have generally been
14 rejected because they assume that the unregulated group is earning its actual cost
15 of capital, and that its equity book value is the same as its market value. In most
16 situations these assumptions are not valid, and, therefore, accounting-based
17 methods do not generally provide reliable cost of equity estimates.
18 More recent comparable earnings methods are based on historical stock
19 market returns rather than book accounting returns. While this approach has some
20 merit, it too has been criticized because there can be no assurance that historical
21 returns actually reflect current or future market requirements. Also, in practical
22 application, earned market returns tend to fluctuate widely from year-to-year. For
Hadaway, Di - 23
Rocky Mountain Power
1 these reasons, a current cost of equity estimate (based on the DCF model or a risk
2 premium analysis) is usually required.
3 The second set of estimation techniques is grouped under the heading of
4 risk premium methods. These methods begin with currently observable market
5 returns, such as yields on government or corporate bonds, and add an increment to
6 account for the additional equity risk. The capital asset pricing model (CAPM)
7 and arbitrage pricing theory (“APT”) model are more sophisticated risk premium
8 approaches. The CAPM and APT methods estimate the cost of equity directly by
9 combining the "risk-free" government bond rate with explicit risk measures to
10 determine the risk premium required by the market. Although these methods are
11 widely used in academic cost of capital research, their additional data
12 requirements and their potentially questionable underlying assumptions have
13 detracted from their use in most regulatory jurisdictions. The basic risk premium
14 methods generally provide a useful parallel approach with the DCF model and
15 assure consistency with other capital market data in the equity cost estimation
16 process.
17 The third set of estimation techniques, based on the DCF model, is the
18 most widely used regulatory cost of equity estimation method. Like the risk
19 premium approach, the DCF model has a sound basis in theory, and many argue
20 that it has the additional advantage of simplicity. I will describe the DCF model in
21 detail below, but in essence its estimate of ROE is simply the sum of the expected
22 dividend yield and the expected long-term dividend, earnings, or price growth rate
23 (all of which are assumed to grow at the same rate). While dividend yields are
Hadaway, Di - 24
Rocky Mountain Power
1 easy to obtain, estimating long-term growth is more difficult. Because the
2 constant growth DCF model also requires very long-term growth estimates
3 (technically to infinity), some argue that its application is too speculative to
4 provide reliable results, resulting in the preference for the multistage growth DCF
5 analysis.
6 Q. Of the three estimation methods, which do you believe provides the most
7 reliable results?
8 A. From my experience, a combination of DCF and risk premium methods usually
9 provides the most reliable approach. While the caveat about estimating long-term
10 growth must be observed, the DCF model's other inputs are readily obtainable,
11 and the model's results typically are consistent with capital market behavior. The
12 risk premium methods provide a good parallel approach to the DCF model and
13 further ensure that current market conditions are accurately reflected in the cost of
14 equity estimate. However, due to ongoing market turmoil and current government
15 monetary policy, which I will discuss later in this testimony, ROE estimates
16 obtained from the risk premium methodology should be discounted.
17 Cost of Equity Capital for Rocky Mountain Power
18 Q. What is the purpose of this section of your testimony?
19 A. The purpose of this section is to present my quantitative studies of the cost of
20 equity capital for RMP and to discuss the details and results of my analysis.
21 Q. How are your studies organized?
22 A. In the first part of my analysis, I apply three versions of the DCF model to a lb-
23 company group of electric utilities based on the selection criteria discussed
Hadaway, Di - 25
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previously. In the second part of my analysis, I apply equity risk premium models
and review projected economic conditions and projected capital costs for the
coming year.
My DCF analysis is based on three versions of the DCF model. In the first
version of the DCF model, I use the constant growth format with long-term
expected growth based on analysts' estimates of five-year utility earnings growth.
While I continue to endorse a longer-term growth estimation approach based on
growth in overall gross domestic product, I show the analyst growth rate DCF
results because this is the approach that has traditionally been used by many
regulators. In the second version of the DCF model, for the estimated growth rate,
I use only the long-term estimated GDP growth rate. Finally, in the third version
of the DCF model, I use a two-stage growth approach, with stage one growth
based on Value Line’s three-to-five-year dividend projections and stage two
growth based on long-term projected GDP growth. The dividend yields in all
three of the models are from Value Line’s projections of dividends for the coming
year and stock prices are from the three-month average for the months that
correspond to the Value Line editions from which the underlying financial data
are taken.
Q. Why do you believe the long-term GDP growth rate should be used to
estimate long-term growth expectations in the DCF model?
A. Growth in nominal GDP (real GDP plus inflation) is the most general measure of
economic growth in the U.S. economy. For long time periods, such as those used
in the Momingstar/Ibbotson Associates rate of return data, nominal GDP growth
Hadaway, Di - 26
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has averaged between five percent and eight percent per year. From this
observation, Professors Brigham and Houston offer the following observation
concerning the appropriate long-term growth rate in the DCF Model:
Expected growth rates vary somewhat among companies, but
dividends for mature firms are often expected to grow in the future
at about the same rate as nominal gross domestic product (real
GDP plus inflation). On this basis, one might expect the dividend
of an average, or "normal," company to grow at a rate of 5 to 8
percent a year. (Eugene F. Brigham and Joel F. Houston,
Fundamentals of Financial Management, 11th Ed. 2007, page
298).
Other academic research on corporate growth rates offers similar conclusions
about GDP growth as well as concerns about the long-term adequacy of analysts’
forecasts:
Our estimated median growth rate is reasonable when compared to
the overall economy’s growth rate. On average over the sample
period, the median growth rate over 10 years for income before
extraordinary items is about 10 percent for all firms. ... After
deducting the dividend yield (the median yield is 2.5 percent per
year), as well as inflation (which averages 4 percent per year over
the sample period), the growth in real income before extraordinary
items is roughly 3.5 percent per year. This is consistent with the
historical growth rate in real gross domestic product, which has
averaged about 3.4 percent per year over the period 1950-1998.
(Louis K. C. Chan, Jason Karceski, and Josef Lakonishok, "The
Level and Persistence of Growth Rates," The Journal of Finance,
April 2003, p. 649).
IBES long-term growth estimates are associated with realized
growth in the immediate short-term future. Over long horizons,
however, there is little forecastability in earnings, and analysts’
estimates tend to be overly optimistic. ... On the whole, the
absence of predictability in growth fits in with the economic
intuition that competitive pressures ultimately work to correct
excessively high or excessively low profitability growth. (Ibid,
page 683).
These findings support the notion that long-term growth expectations are more
Hadaway, Di - 27
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1 closely predicted by broader measures of economic growth than by near-term
2 analysts’ estimates. Especially for the very long-term growth rate requirements of
3 the DCF model, the growth in nominal GDP should be considered an important
4 input.
5 Q. How did you estimate the expected long-run GDP growth rate?
6 A. I developed my long-term GDP growth forecast from nominal GDP data
7 contained in the St. Louis Federal Reserve Bank data base. That data for the
8 period 1950 through 2010 are summarized in my Exhibit No. 15. As shown at the
9 bottom of that exhibit, the overall average for the period was 6.7 percent. The data
10 also show, however, that in the more recent years since 1980, lower inflation has
11 resulted in lower overall GDP growth. For this reason I gave more weight to the
12 more recent years in my GDP forecast. Based on this approach, my overall
13 forecast for long-term GDP growth at 5.8 percent is almost 100 basis points lower
14 than the long-term average GDP growth rate.
15 Q. Why do you believe your forecast of GDP growth based on long-term
16 historical data is appropriate in the DCF model?
17 A. There are at least three reasons. First, most econometric forecasts are derived
18 from the trending of historical data or the use of weighted averages. This is the
19 approach I have taken in Exhibit No. 15. The long-run historical average GDP
20 growth rate is 6.7 percent, but my estimate of long-term expected growth is only
21 5.8 percent. My forecast is lower because my forecasting method gives much
22 more weight to the more recent 10- and 20-year periods.
23 Second, some currently lower GDP growth forecasts likely understate very
Hadaway, Di - 28
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1 long growth rate expectations that are required in the DCF model. Many of those
2 forecasts are currently low because they are based on the assumption of
3 permanently low inflation rates, in the range of two percent. As shown in my
4 Exhibit No. 15, the average long-term inflation rate has been over three percent in
5 all but the most recent 10- and 20- year periods. Also, as shown in Exhibit No. 14,
6 page 1, from December 2008 to December 2009, even with the continuing effects
7 of the economic recession, the CPI increased by 2.8 percent. Use of long-term
8 inflation rates of two percent or less to estimate long-term nominal growth in the
9 DCF model is not consistent with reasonable long-term expectations for the U.S.
10 economy or investors'long-term experience.
11 Finally, the current economic turmoil makes it even more important to
12 consider longer-term economic data in the growth rate estimate. As discussed in
13 the previous section, current near-term forecasts for both real GDP and inflation
14 are severely depressed. To the extent that even the longer-term outlooks of
15 professional economists are also depressed, their forecasts will be low. Under
16 these circumstances, a longer-term balance is even more important. For all these
17 reasons, while I am also presenting other growth rate approaches based on
18 analysts’ estimates in this testimony, I believe it is appropriate also to consider
19 long-term GDP growth in estimating the DCF growth rate.
20 Q. Please summarize the results of your DCF analyses.
21 A. The DCF results for my comparable company group are presented in Exhibit No.
22 16. As shown in the first column of page 1 of that exhibit, the traditional constant
23 growth model indicates a cost of common equity of 10.1 percent to 10.5 percent.
Hadaway, Di - 29
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1 In the second column of page 1,1 recalculate the constant growth results with the
2 growth rate based on long-term forecasted growth in GDP. With the GDP growth
3 rate, the constant growth model indicates a cost of common equity range of 10.3
4 percent to 10.5 percent. Finally, in the third column of page 1,1 present the results
5 from the multistage DCF model. The multistage model indicates a cost of
6 common equity of 10.1 percent. The results from the DCF model, therefore,
7 indicate a reasonable cost of common equity range of 10.1 percent to 10.5
8 percent.
9 Q. What are the results of your equity risk premium studies?
10 A. The details and results of my equity risk premium studies are shown in my
11 Exhibit No. 17. These studies indicate a cost of common equity range of 10.25
12 percent to 10.45 percent.
13 Q. How are your equity risk premium studies structured?
14 A. My equity risk premium studies are divided into two parts. First, I compare
15 electric utility authorized ROEs for the period 1980-2010 to contemporaneous
16 long-term utility interest rates. The differences between the average authorized
17 ROEs and the average interest rate for the year is the indicated equity risk
18 premium. I then add the indicated equity risk premium to the forecasted and
19 current single-A utility bond interest rate to estimate the cost of common equity.
20 Because there is a strong inverse relationship between equity risk premiums and
21 interest rates (when interest rates are high, risk premiums are low and vice versa),
22 further analysis is required to estimate the current equity risk premium level.
23 The inverse relationship between equity risk premiums and interest rate
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levels is well documented in numerous, well-respected academic studies. These
studies typically use regression analysis or other statistical methods to predict or
measure the equity risk premium relationship under varying interest rate
conditions. On page 3 of Exhibit No. 17, I provide regression analyses of the
allowed annual equity risk premiums relative to interest rate levels. The negative
and statistically significant regression coefficients confirm the inverse relationship
between equity risk premiums and interest rates. This means that when interest
rates rise by one percentage point, the cost of equity increases, but by a smaller
amount. Similarly, when interest rates decline by one percentage point, the cost of
equity declines by less than one percentage point. I use this negative interest rate
change coefficient in conjunction with current and forecasted interest rates to
estimate the appropriate cost of common equity.
Can you illustrate the inverse relationship between equity risk premiums and
interest rates without using the statistical analysis described above?
Yes. Statistical analysis is often used, especially in academic research, to
substantiate certain economic and financial relationships. For the equity risk
premiums, however, the issue is so basic that simple observation and averaging of
the data for various time periods makes the inverse relationship clear. In Table 4
below, I have averaged the utility bond yields and equity risk premiums for each
non-overlapping five-year period between 1980 and 2010 from the data in my risk
premium study in Exhibit No. 17, page 1.
Hadaway, Di - 31
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Table 4
Average Five-Year Interest Rates and Equity Risk Premiums
(1980-2010)
Period
Average
Utility Bond
Interest Rate
Average
Equity Risk
Premium
1980-1985 13.96% 1.23%
1986-1990 9.86%3.21%
1991-1995 8.31%3.48%
1996-2000 7.61%3.72%
2001-2005 6.75%4.16%
2006-2010 6.13%4.27%
Source: Exhibit No. 17, page 1.
These data clearly show that equity risk premiums have consistently increased as
interest rates have declined. This result is a simple reflection of the fact that
expected and achieved rates of return in the stock market are not entirely
dependent on changes in interest rates. Because utilities must compete with other
types of equity investments for capital, the COE for utilities does not change by as
much as the observed changes in interest rates. Those who argue that unadjusted
long-term averages of equity risk premiums can be used with current, historically
low interest rates to estimate COE are mistaken. Such an approach to equity risk
premium analysis will consistently understate the required equity rate of return.
Please summarize the results of your cost of equity analysis.
Table 5 below summarizes my results:
Hadaway, Di - 32
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Table 5
Summary of Cost of Equity Estimates
DCF Analvsis Indicated Cost
Constant Growth (Analysts' Growth)10.P/o-10.5%
Constant Growth (GDP Growth)10.3%-10.5%
Multistage Growth Model 10.1%
Reasonable DCF Range 10.1%-10.5%
Eauitv Risk Premium Analysis Indicated Cost
Forecast Utility Debt Yield+ Equity Risk Premium
Equity Risk Premium ROE (5.94% + 4.51%)10.45%
Current Utility Debt + Equity Risk Premium
Equity Risk Premium ROE (5.60% + 4.65%)10.25%
RMP Cost of Equity 10.50%
Q. How should these results be interpreted to determine a reasonable ROE
upon which to base rates for Rocky Mountain Power?
A. The fair and reasonable ROE for RMP is 10.5 percent. This conclusion is
supported by the upper end of my DCF range and by risk premium results based
on projected single-A utility interest rates for 2011. While I typically recommend
the middle of the DCF range, in the present case I believe a higher return should
be allowed to reflect the further increases in capital costs that are expected for
2012 and the equity market turbulence and relatively poor performance for
utilities that continue from the financial crisis. In this environment, setting ROE at
the lower levels that can be obtained from some equity cost estimation models
will understate RMP's market cost of equity capital.
Q. Does this conclude your direct testimony?
A. Yes, it does.
Hadaway, Di - 33
Rocky Mountain Power
Appendix A
Qualifications of Samuel C. Hadaway
I have a Bachelor's degree in economics from Southern Methodist University, as well as
MBA and Ph.D. degrees with concentrations in finance and economics from the
University of Texas at Austin (UT Austin). I am an owner and full-time employee of
FINANCO, Inc. FINANCO provides financial research concerning the cost of capital
and financial condition for regulated companies as well as financial modeling and other
economic studies in litigation support. In addition to my work at FINANCO, I have
served as an adjunct professor in the McCombs School of Business at UT Austin and in
what is now the McCoy College of Business at Texas State University. In my prior
academic work, I taught economics and finance courses and I conducted research and
directed graduate students in the areas of investments and capital market research. I was
previously Director of the Economic Research Division at the Public Utility Commission
of Texas (Texas Commission) where I supervised the Texas Commission's finance,
economics, and accounting staff, and served as the Texas Commission's chief financial
witness in electric and telephone rate cases. I have taught courses at various utility
conferences on cost of capital, capital structure, utility financial condition, and cost
allocation and rate design issues. I have made presentations before the New York
Society of Security Analysts, the National Rate of Return Analysts Forum, and various
other professional and legislative groups. I have served as a vice president and on the
board of directors of the Financial Management Association.
A list of my publications and testimony I have given before various regulatory
bodies and in state and federal courts is contained in my resume, which is included as
Appendix B.
Appendix B
Page 1 of 11
SAMUEL C. HADAWAY
FINANCO, Inc.
Financial Analysis Consultants
3520 Executive Center Drive, Suite 124
Austin, Texas 78731
[phone]
SUMMARY OF QUALIFICATIONS
• Principal, Financial Analysis Consultants (FINANCO, Inc.).
• Ph.D. in Finance and Economics.
• Extensive expert witness testimony in court and before regulatory agencies.
• Management of professional research staff in academic and regulatory organizations.
• Professional presentations before executive development groups, the National Rate of
Return Analysts' Forum, and the New York Society of Security Analysts.
• Financial Management Association, previously Vice President for Practitioner
Services.
EDUCATION
The University of Texas at Austin
Ph.D., Finance and Econometrics
January 1975
The University of Texas at Austin
MBA, Finance
June 1973
Southern Methodist University
BA, Economics
June 1969
OTHER EXPERIENCE
Dissertation: An Evaluation of the
Original and Recent Variants of the
Capital Asset Pricing Model.
Thesis: The Pricing of Risk on the
New York Stock Exchange.
Honors program. Departmental
distinction.
University of Texas at Austin
Adjunct Associate Professor
1985-1988,2004-Present
Texas State University San Marcos
Associate Professor of Finance
1983-1984,2003-2004
Public Utility Commission of Texas
Chief Economist and Director of
Economic Research Division
August 1980-August 1983
Assistant Professor of Finance
Texas Tech University
July 1978-Juiy 1980
University of Alabama
January 1975-June 1978
Corporate Financial Management,
Investments, and Integrative Finance
Cases.
Graduate and undergraduate courses
in Financial Management, Managerial
Economics, and Investment Analysis.
Lead financial witness. Supervised
Commission staff in research and
testimony on rate of return, financial
condition, and economic analysis.
Member of graduate faculty. Conducted
Ph.D. seminars and directed doctoral
dissertations in capital market theory.
Served as consultant to industry,
church and governmental organizations.
Appendix B
Page 2 of 11
FINANCIAL AND ECONOMIC TESTIMONY IN REGULATORY
PROCEEDINGS (Client in parenthesis!
Cost of Money Testimony
• Maine Public Utilities Commission, Docket No. 2011-92, May 5, 2011 (Northern
Utilities, Inc.)
• New Hampshire Public Utilities Commission, Docket No. DG 11-069, May 4,
2011 (Northern Utilities, Inc.)
• Arizona Corporation Commission, Docket No. G-04204A-11-0158, April 8, 2011
(UNS Gas, Inc.)______
• Utah Public Service Commission, Docket No. 10-035-124, January 24,2011 (Rocky
Mountain Power/PacifiCorp).
• Massachusetts Department of Public Utilities, D.P.U. 11.01 (Electric) and D.P.U.
11.02 (Gas), January 14, 2011, (Fitchburg Gas and Electric Light Company d/b/a/
Unitil)
• Wyoming Public Service Commission, Docket No. 20000-384-ER-10, November 22,
2010 (Rocky Mountain Power dba/PacifiCorp).
• Illinois Commerce Commission, Docket No. 10-0467, July 28, 2010 (Commonwealth
Edison Company).
• Missouri Public Service Commission, Case No. ER-2010-0355, June 4, 2010 (Kansas
City Power & Light Company).
• Missouri Public Service Commission, Case No. ER-2010-0356, June 4,2010
(KCP&L Greater Missouri Operations Company).
• Idaho Public Utilities Commission, Case No. PAC-E-10-07, May 28, 2010 (Rocky
Mountain Power/PacifiCorp).
• Washington Utilities and Transportation Commission, Docket UE-100749, May 4,
2010 (PacifiCorp).
• New Hampshire Public Utilities Commission, Docket No. DE 10-055, April 15, 2010
(Unitil Energy Systems)
• Oregon Public Utility Commission, Docket No. UE-217, March 1, 2010 (PacifiCorp).
• Texas Public Utility Commission, Docket No. 37744, December 30, 2009,(Entergy
Texas, Inc.)
• Kansas Corporation Commission, Docket No. 10-KCPE-415-RTS, December 17,
2009 (Kansas City Power & Light Company).
• Texas Public Utility Commission, Docket No. 37690, December 9, 2009,(El Paso
Electric Company).
• California Public Utilities Commission, Application No. 09-11-015, November 20,
2009 (PacifiCorp).
• Federal Energy Regulatory Commission, Docket No. ER10-230-000, November 6,
2009 (Kansas City Power & Light Company and KCP&L Greater Missouri
Operations Company).
• Wyoming Public Service Commission, Docket No. 20000-352-ER-09, October 2,
2009 (Rocky Mountain Power dba/PacifiCorp).
• Arkansas Public Service Commission, Docket No. 09-084-U, September 4, 2009,
(Entergy-Arkansas)
• Texas Public Utility Commission, Docket No. 37364, August 28, 2009,(American
Electric Power-SWEPCO)
• Utah Public Service Commission, Docket No. 09-035-23, June 23, 2009 (Rocky
Mountain Power/PacifiCorp).
• New Mexico Public Regulation Commission, Case No. 09-00171-UT, May 2009, (El
Paso Electric Company).
• Oregon Public Utility Commission, Docket No. UE-207, April 2, 2009 (PacifiCorp).
• Arkansas Public Service Commission, Docket No. 09-008-U, February 19,2009
(American Electric Power-SWEPCO).
• Washington Utilities and Transportation Commission, Docket UE-090205, February
9, 2009 (PacifiCorp).
Appendix B
Page 3 of 11
• Idaho Public Utilities Commission, Case No. PAC-E-08-07, September 19, 2008
(Rocky Mountain Power/PacifiCorp).
• Missouri Public Service Commission, Case No. ER-2009-089, September 5, 2008
(Kansas City Power & Light Company).
• Kansas Corporation Commission, Docket No. 09-KCPE-246-RTS, September 5,
2008 (Kansas City Power & Light Company).
• Missouri Public Service Commission, Case No. ER-2009-090, September 5, 2008
(Aquila, Inc. dba/KCP&L Greater Missouri Operations Company).
• Utah Public Service Commission, Docket No. 08-035-38, July 17, 2008 (Rocky
Mountain Power/PacifiCorp).
• Wyoming Public Service Commission, Docket No. 20000-333-ER-08, July 2008
(Rocky Mountain Power dba/PacifiCorp).
• Texas Public Utility Commission, Docket No. 35717, June 27, 2008, (Oncor Electric
Delivery Company LLC).
• Washington Utilities and Transportation Commission, Docket UG-080546, March 28,
2008 (NW Natural).
• Washington Utilities and Transportation Commission, Docket UE-080220, February
6, 2008 (PacifiCorp).
• Utah Public Service Commission, Docket No. 07-035-93, December 17, 2007
(PacifiCorp).
• Illinois Commerce Commission, Docket No. 07-0566, October 17, 2007
(Commonwealth Edison Company).
• Texas Public Utility Commission, Docket No. 34800, September 26, 2007, (Entergy
Gulf States, Inc.)
• Texas Public Utility Commission, Docket No. 34040, August 28,2007, (Oncor/TXU
Electric Delivery Company)
• Massachusetts Department of Public Utilities, D.P.U. 07-71, August 17, 2007,
(Fitchburg Gas and Electric Light Company d/b/a/ Unitil)
• Arizona Corporation Commission, Docket No. E-01933A-07-0402, July 2,2007,
(Tucson Electric Power Company).
• Wyoming Public Service Commission, Docket No. 20000-277-ER-07, June 29, 2007
(Rocky Mountain Power dba/PacifiCorp).
• Idaho Public Utilities Commission, Case No. PAC-E-05-1, June 8, 2007 (Rocky
Mountain Power dba/PacifiCorp).
• Kansas Corporation Commission, Docket No. 07-KCPE-905-RTS, March 1, 2007
(Kansas City Power & Light Company).
• New Mexico Public Regulation Commission, Case No. 07-00077-UT, February 21,
2007, (Public Service Company of New Mexico).
• Missouri Public Service Commission, Case No. ER-2006-0291, February 1, 2007
(Kansas City Power & Light Company).
• Texas PUC Docket Nos. 33734, January 22,2007 (Electric Transmission Texas,
LLC).
• Texas PUC Docket Nos. 33309 and 33310, November 2006, (AEP Texas Central
Company and AEP Texas North Company).
• Louisiana Public Service Commission, Docket No. U-23327, October 2006 and
January 2005 (Southwestern Electric Power Company, American Electric Power
Company)
• Missouri Public Service Commission, Case No. ER-2007-0004, July 3, 2006 (Aquila,
Inc.).
• New Mexico Public Regulation Commission, Case No. 06-00258-UT, June 30, 2006
(El Paso Electric Company).
• New Mexico Public Regulation Commission, Case No. 06-00210-UT, May 30, 2006
(Public Service Company of New Mexico).
• Texas Public Utility Commission, Docket No. 32093, April 14,2006 (CenterPoint
Energy-Houston Electric, LLC).
Appendix B
Page 4 of 11
• Utah Public Service Commission, Docket No. 06-035-21, March 7, 2006
(PacifiCorp).
• Oregon Public Utility Commission, Case No. UE-179, February 23,2006
(PacifiCorp).
• Kansas Corporation Commission, Docket No. 06-KCPE-828-RTS, January 31, 2006
(Kansas City Power & Light Company).
• Missouri Public Service Commission, Case No. ER-2006-0314, January 27, 2006
(Kansas City Power & Light Company).
• California Public Utilities Commission, Docket No. 05-11-022, November 29, 2005
(PacifiCorp).
• Texas Public Utility Commission, Docket No. 31994, November 5, 2005 (Texas-New
Mexico Power Company).
• New Hampshire Public Utilities Commission, Docket No. DE 05-178, November 4,
2005 (Unitil Energy Systems).
• Wyoming Public Service Commission, Docket No. 20000-ER-05-230, October 14,
2005 (PacifiCorp).
• Minnesota Public Utilities Commission, Docket. No. G-008/GR-05-1380, October
2005 (CenterPoint Energy Minnegasco).
• Texas Railroad Commission, Gas Utilities Division No. 9625, September 2005
(CenterPoint Energy Entex).
• Illinois Commerce Commission, Docket No. 05-0597, August 31, 2005
(Commonwealth Edison Company).
• Washington Utilities and Transportation Commission, Docket ,UE-050684/General
Rate Case, May 2005 (PacifiCorp).
• Missouri Public Service Commission, Case No. ER-2005-0436, May 2005 (Aquila,
Inc.).
• Idaho Public Utilities Commission, Case No. PAC-E-05-1, January 14, 2005
(PacifiCorp).
• Arkansas Public Service Commission, Docket No. 04-121-U, December 3, 2004
(CenterPoint Energy Arkla).
• Oregon Public Utility Commission, Case No. UE-170, November 12, 2004
(PacifiCorp).
• Texas Public Utility Commission, Docket No. 29206, November 8, 2004 (Texas-New
Mexico Power Company).
• Texas Railroad Commission, Gas Utilities Division Nos. 9533 and 9534, October 13,
2004 (CenterPoint Energy Entex).
• Texas Public Utility Commission, Docket No. 29526, August 18 and September 2,
2004 (CenterPoint Energy Houston Electric).
• Utah Public Service Commission, Docket No. 04-2035-, August 4, 2004 (PacifiCorp).
• Oklahoma Corporation Commission, Cause No. PUD-200400187, July 2,2004,
(CenterPoint Energy Arkla).
• Minnesota Public Utilities Commission, Docket No. G-008/GR-04-901, July 2004,
(CenterPoint Energy Minnegasco).
• Washington Utilities and Transportation Commission, Docket ,UE-032065/General
Rate Case, December 2003 (PacifiCorp).
• Washington Utilities and Transportation Commission, Docket ,UG-031885,
November 2003 (Northwest Natural Gas Company.).
• Wyoming Public Service Commission, Docket No. 20000-ER-03-198, May 2003
(PacifiCorp).
• Public Service Commission of Utah, Docket No. 03-2035-02, May 2003
(PacifiCorp).
• Public Utility Commission of Oregon, Case. UE-147, March 2003 (PacifiCorp).
• Wyoming Public Service Commission, Docket No. 20000-ER-00-162, May 2002
(PacifiCorp).
• Public Utility Commission of Oregon, UG-152, November 2002 (Northwest Natural).
Appendix B
Page 5 of 11
• Massachusetts Department of Telecommunications and Energy, D.T.E. 02-24/24,
May 2002 (Fitchburg Gas and Electric Light Company).
• New Hampshire Public Utilities Commission, Docket No. DE 01-247, January 2002
(Unitil Corporation).
• Washington Utilities and Transportation Commission, Docket UE-011569,70,UG-
011571, November 2001 (Puget Sound Energy, Inc.).
• California Public Utilities Commission, Docket No. 01-03-026, September and
December 2001 (PacifiCorp).
• New Mexico Public Regulation Commission, Docket No. 3643, July 2001 (Texas-
New Mexico Power Company).
• Texas Natural Resources Conservation Commission, Docket No. 2001-1074/5-URC,
May 2001 (AquaSource Utility, Inc.).
• Massachusetts Department of Telecommunications and Energy, Docket No. 99-118,
May 2001 (Fitchburg Gas and Electric Light Company).
• Public Service Commission of Utah, Docket No. 01 -035-01, January 2001
(PacifiCorp)
• Federal Energy Regulatory Commission, Docket No. ER-01-651, January 2001
(Southwestern Electric Power Company).
• Wyoming Public Service Commission, Docket No. 20000-ER-00-162, December
2000 (PacifiCorp).
• Public Utility Commission of Oregon, Case. UE-116, November 2000, (PacifiCorp)
• Public Utility Commission of Texas, Docket No. 22344, September 2000, (AEP
Texas Companies, Entergy Gulf States, Inc., Reliant Energy HL&P, Texas-New
Mexico Power Company, TXU Electric Company)
• Public Utility Commission of Oregon, Case UE-111, August 2000, (PacifiCorp)
• Texas Public Utility Commission, Docket Nos. 22352,3,4, March 2000 (Central
Power and Light Co., Southwestern Electric Power Co., West Texas Utilities Co.).
• Texas Public Utility Commission, Docket No. 22355, March 2000 (Reliant Energy,
Inc.).
• Texas Public Utility Commission, Docket No. 22349, March 2000 (Texas-New
Mexico Power Co.).
• Texas Public Utility Commission, Docket No. 22350, March 2000 (TXU Electric).
• Washington Utilities and Transportation Commission, Docket UE-991831, November
1999 (PacifiCorp).
• Public Service Commission of Utah, Docket No. 99-035-10, September 1999
(PacifiCorp)
• Louisiana Public Service Commission Docket No. U-23029, August 1999
(Southwestern Electric Power Company)
• Wyoming Public Service Commission, Docket No. 2000-ER-99-145, July 1999,
January 2000 (PacifiCorp, dba Pacific Power and Light Company).
• Texas PUC Docket No. 20150, March 1999 (Entergy Gulf States, Inc.)
• Federal Energy Regulatory Commission Docket No. ER-98-3177-00, May and
December 1998 (Southwestern Electric Power Company).
• Public Service Commission of Utah, Docket No. 97-035-01, June 1998 (PacifiCorp,
dba Utah Power and Light Company).
• Massachusetts Dept, of Telecommunications and Energy, Docket No. DTE 98-51,
May 1998, (Fitchburg Gas and Electric Light Company, a subsidiary of Unitil Corp.)
• Texas PUC, Docket No. 18490, March 1998, (Texas Utilities Electric Company)
• Texas PUC Docket No. 17751, March 1998 and July 1997 (Texas-New Mexico
Power Company).
• Federal Energy Regulatory Commission Docket No. RP-97, February 1998 and May
1997 (Koch Gateway Pipeline Company).
• Federal Energy Regulatory Commission Docket No. ER-97-4468-000, December
1997 (Puget Sound Power & Light).
Appendix B
Page 6 of 11
• Oklahoma Corporation Commission, Cause No. PUD 960000214, August 1997
(Public Service Company of Oklahoma).
• Oregon Public Utility Commission Docket No. UE-94, April 1996, (PacifiCorp).
• Texas PUC Docket No. 15643, May and September 1996, (Central Power and Light
and West Texas Utilities Company).
• Federal Energy Regulatory Commission Docket No. ER-96, April 1996 (Puget Sound
Power & Light).
• Federal Energy Regulatoiy Commission Docket No. ER96, February 1996, (Central
and South West Corporation).
• Washington Utilities & Transportation Commission Docket No. UE-951270,
November 1995 (Puget Sound Power & Light).
• Texas PUC Docket No. 14965, November 1995, (Central Power and Light).
• Texas PUC Docket No. 13369, February 1995 (West Texas Utilities).
• Texas PUC Docket No. 12065, July and December 1994, (Houston Lighting &
Power).
• Texas PUC, Docket No. 12820, July and November 1994, (Central Power and Light).
• Texas PUC Docket No. 12900, March 1994, and New Mexico PUC Case No. 2531,
August 1993, (TNP Enterprises).
• Texas PUC, Docket No. 12815, March 1994, (Pedemales Electric Cooperative).
• Florida Public Service Commission, Docket No. 930987-EI, December 1993, (TECO
Energy).
• Iowa Department of Commerce, Docket No. RPU-93-9, December 1993, (US West
Communications).
• Texas PUC Dkt. No. 11735, May and September 1993, (Texas Utilities Electric
Company)
• Oklahoma Corporation Commission, Cause No. PUD 001342, October 1992 (Public
Service Company of Oklahoma).
• Texas PUC Dkt. No. 9983, November 1991, (Southwest Texas Telephone Company).
• Texas PUC Dkt. No. 9850, November 1990, Houston Lighting & Power Company).
• Texas PUC Dkt. Nos. 8480/8482, January 1989; City of Austin Dkt. No. 1, August
1988 and July 1987, (City of Austin Electric Department).
• Missouri Public Service Commission Case No. ER-90-101, July 1990 (UtiliCorp).
• Texas PUC Dkt. No. 9945, December 1990; Texas PUC Dkt. No. 9165, November
1989, (El Paso Electric Company).
• Texas PUC Dkt. No. 9427, July 1990, (Lower Colorado River Authority Association
of Wholesale Customers).
• Oregon Public Utility Commission, March 1990, (Pacific Power & Light Company).
• Utah Public Service Commission, November 1989, (Utah Power & Light Company).
• Texas PUC Dkt. No. 5610, September 1988, (GTE Southwest).
• Iowa State Utilities Board, September 1988, (Northwestern Bell Telephone
Company).
• Texas Water Commission, Dkt. Nos. RC-022 and RC-023, November 1986, (City of
Houston Water Department).
• Pennsylvania PUC Dkt. Nos. R-842770 and R-842771, May 1985, (Bethlehem Steel).
Capital Structure Testimony:
• Federal Energy Regulatory Commission Docket No. RP-97, May 1997 (Koch
Gateway Pipeline Company).
• Illinois Commerce Commission Dkt. No. 93-0252 Remand, July 1996, (Sprint).
• California PUC (Appl. No. 92-05-004) April 1993 and May 1993, (Pacific Telesis).
• Montana PSC, Dkt. No. 90.12.86, November 1991, (US West Communications).
• Massachusetts PUC Dkt. No. 86-33, June 1987, (New England Telephone Company).
• Maine PUC Dkt. No. 85-159, February 1987, (New England Telephone Company).
• New Hampshire PUC Dkt. No. 85-181, September 1986, (New England Telephone
Company).
Appendix B
Page 7 of 11
• Maine PUC Dkt. No. 83-213, March 1984, (New England Telephone Company).
Regulatory Policy and Other Regulatory Issues:
• Texas PUC Docket No.31056, September 16,2005, (AEP Texas Central Company).
• New Hampshire PUC Docket No. DE 03-086, May 2003, (Unitil Corporation).
• Texas PUC Docket No. 26194, May 2003 (El Paso Electric Company)
• Texas PUC Docket No. 22622, June 15, 2001 (TXU Electric)
• Texas PUC Docket No. 20125, November 1999 (Entergy Gulf States, Inc.)
• Texas PUC Docket No. 21112, July 1999 and New Mexico Public Regulation
Commission Case No. 3103, July 1999 (Texas-New Mexico Power Company)
• Texas PUC Docket No. 20292, May 1999 (Central Power and Light Co.)
• Texas PUC Docket No. 20150, November 1998 (Entergy Gulf States, Inc.)
• New Mexico PUC Case No. 2769, May 1997, (Texas-New Mexico Power Company).
• Texas PUC Dkt. No. 15296, September 1996, (City of College Station, Texas).
• Texas PUC Dkt. No. 14965 Competitive Issues Phase, August 1996 (Central Power
and Light Company).
• Texas PUC Dkt. No. 12456, May 1994, (Texas Utilities Electric Company).
• Texas PUC, Dkt. No. 12700/12701 and Federal Energy Regulatory Commission,
Docket No. EC94-000, January 1994, (El Paso Electric Company).
• Florida Public Service Commission Generic Purchased Power Proceedings, October
1993 (TECO Energy).
• Texas PUC, Docket No. 11248, December 1992 (Barbara Faskins).
• Texas PUC Dkt. No. 10894, January and June 1992, (Gulf States Utilities Company).
• State Corporation Commission of Kansas, Dkt. No. 175,456-U, August 1991,
(UtiliCorp United).
• Texas PUC Dkt. No. 9561, May 1990; Texas PUC Dkt. Nos. 6668/8646, July 1989
and February 1990, (Central Power and Light Company).
• Texas PUC Dkt. No. 9300, April 1990 and June 1990, (Texas Utilities Electric Co.).
• Texas PUC Dkt. No. 10200, August 1991, (Texas-New Mexico Power Company).
• Texas PUC Dkt. No. 7289, May 1987, (West Texas Utilities Company).
• Texas PUC Dkt. No. 7195, January 1987, (North Star Steel Texas).
• New Mexico PSC Case No. 1916, April 1986, (Public Service Company of New
Mexico).
• Texas PUC Dkt. No. 6525, March 1986, (North Star Steel Texas).
• Texas PUC Dkt. No. 6375, November 1985, (Valley Industrial Council).
• Texas PUC Dkt. No. 6220, April 1985, (North Star Steel Texas).
• Texas PUC Dkt. No. 5940, March 1985, (West Texas Municipal Power Agency).
• Texas PUC Dkt. No. 5820, October 1984, (North Star Steel Texas).
• Texas PUC Dkt. No. 5779, September 1984, (Texas Industrial Energy Consumers).
• Texas PUC Dkt. No. 5560, April 1984, (North Star Steel Texas).
• Arizona PSC Dkt. No. U-1345-83-155, January 1984 and May 1984 (Arizona Public
Service Company Shareholders Association).
Insurance Rate Testimony:
• Texas Department of Insurance, Docket No. 2673, January 2008, (Texas Land Title
Association).
• Texas Department of Insurance, Docket No. 2601, December 2006, (Texas Land Title
Association).
• Texas Department of Insurance, Docket No. 2394, November 1999, (Texas Title
Insurance Agents).
• Senate Interim Committee on Title Insurance of the Texas Legislature, February 6,
1998
Appendix B
Page 8 of 11
• Texas Department of Insurance, Docket No. 2279, October 1997, (Texas Title
Insurance Agents).
• Texas Department of Insurance, January 1996, (Independent Metropolitan Title
Insurance Agents of Texas).
• Texas Insurance Board, January 1992, (Texas Land Title Association).
• Texas Insurance Board, December 1990, (Texas Land Title Association).
• Texas Insurance Board, November 1989, (Texas Land Title Association).
• Texas Insurance Board, December 1987, (Texas Land Title Association).
Testimony On Behalf Of Texas PUC Staff:
• Texland Electric Cooperative, Dkt. No. 3896, February 1983
• El Paso Electric Company, Dkt. No. 4620, September 1982.
• Southwestern Bell Telephone Company, Dkt. No. 4545, August 1982.
• Central Power and Light Company, Dkt. No. 4400, May 1982.
• Texas-New Mexico Power Company, Dkt. 4240, March 1982.
• Texas Power and Light Company, Dkt. No. 3780, May 1981.
• General Telephone Company of the Southwest, Dkt. No. 3690, April 1981.
• Mid-South Electric Cooperative, Dkt. No. 3656, March 1981.
• West Texas Utilities Company, Dkt. No. 3473, December 1980.
• Houston Lighting & Power Company, Dkt. No. 3320, September 1980.
ECONOMIC ANALYSIS AND TESTIMONY
Antitrust Litigation:
• Marginal Cost Analysis of Concrete Production/Predatory Pricing (Stiles)
• Analysis of Lost Business Opportunity due to denial of Waste Disposal Site Permit
(Browning-Ferris Industries, Inc.).
• Analysis of Electric Power Transmission Costs in Purchased Power Dispute, 1995,
(City of College Station, Texas).
Contract Litigation:
• Analysis of Cogeneration Contract/Economic Viability Issues(Texas-New Mexico
Power Company)
• Definition of Electric Sales/Franchise Fee Contract Dispute (Reliant Energy HL&P)
• Analysis of Purchased Power Agreement/Breach of Contract (Texas-New Mexico
Power Company)
• Regulatory Commission Provisions in Franchise Fee Ordinance Dispute (Central
Power & Light Company)
• Analysis of Economic Damages resulting from attempted Acquisition of Highway
Construction Company (Dillingham Construction Corporation).
• Analysis of Economic Damages due to Contract Interference in Acquisition of
Electric Utility Cooperative (PacifiCorp).
• Analysis of Economic Damages due to Patent Infringement of Boiler Cleaning
Process (Dowell-Schlumberger/The Dow Chemical Company).
• Analysis of Lost Profits in Highway Construction Dispute, Jones Bros., Plaintiff, v.
Flour Daniel, Balfour Beatty, Lambrecht, and Lone Star Infrastructure, LLC,
Defendants, 53rd Judicial District Court of Travis County, Texas, Cause No.
GN204386, 2005, (Flour, et al)
• Analysis of Lost Profits in Insurance Dispute, Nickelson v. International
Shipbreaking Ltd., LLC, et al, 332nd District Court, Hidalgo County, Texas, Cause
No. C-482-01-F, 2005, (Great American Insurance Company).
Appendix B
Page 9 of 11
• Analysis of Lost Profits and Other Economic Damages due to Patent Infringement,
Climb Tech, Guthrie, & Schwartz Design, Plaintiffs, v. Verble, Hagler, Reeves,
Valcor Industries, Inc., Defendants, U.S. District Court, Western District, Austin,
Texas, Civil Action No. l:05-cv-864-LY, 2008, (Verble, Hagler, et al).
Lender Liability/Securities Litigation:
• ERISA Valuation of Retail Drug Store Chain (Sommers Drug Stores Company).
• Analysis of Lost Business Opportunities in Failed Businesses where Lenders Refused
to Extend or Foreclosed Loans (FirstCity Bank Texas, McAllen State Bank, General
Electric Credit Corporation).
• Usury and Punitive Damages Analysis based on Property Valuation in Failed Real
Estate Venture, 1995, (Tomen America, Inc.).
Personal Injury/Wrongful Death/Lost Earnings Capacity Litigation:
• Analysis of Lost Earnings Capacity and Punitive Damages due to Industrial Accident
(Worsham, Forsythe and Wooldridge).
• Analysis of Lost Earnings Capacity due to Improper Termination (Lloyd Gosselink,
Ryan & Fowler).
• Present Value Analysis of Lost Earnings and Future Medical Costs due to Medical
Malpractice (Sierra Medical Center).
• Present Value Analysis of Life Care Plan, U.S. District Court, Eastern District of
Texas, Texarkana Division, Chisum v. Ford Motor Company, Civil Action No. 5:05-
cv-0045, 2005, (Ford Motor Company).
• Analysis of Lost Earnings Capacity due to Industrial Accident, 122n District Court,
Galveston County, Texas, Trevino v. BP Products North America, Inc., Cause No.
05-cv-0341, 2006, (BP Products North America, Inc.
Product Warranty/Liability Litigation:
• Analysis of Lost Profits due to Equipment Failure in Cogeneration Facility (WF
Energy/Travelers Insurance Company).
• Analysis of Economic Damages due to Grain Elevator Explosion (Degesch Chemical
Company).
• Analysis of Economic Damages due to failure of Plastic Pipe Water Lines (Western
Plastics, Inc.)
• Analysis of Rail Car Repair and Maintenance Costs in Product Warranty Dispute
(Youngstown Steel Door Company).
• Analysis of Lost Profits due to Equipment Failure in Electric Power Plant, Houston
Casualty Co., Comision Federal de Electricidad, and Seguros Comercial America
S. A. de C.V. (Plaintiffs) v. Siemens Power Corporation, et al, District Court of Dallas
County Texas, Cause No. DV-99-02749, 2005, (Siemens).
• Analysis of Lost Profits due to Manufacturing Parts Failure, Sanijet Corp. (Plaintiff)
v. Lexor International, Inc., U.S. District Court, Northern Division of Texas, Dallas,
Texas, Case No. 3:06-cv-1258-B ECF (Lexor International)
Property Tax Litigation:
• Evaluation of Electric Utility Distribution System (Jasper-Newton Electric
Cooperative).
• Evaluations of Electric Utility Generating Plants (West Texas Utilities Company).
Appendix B
Page 10 of 11
Valuations of Closely Held Businesses in Litigation Support and Federal Estate Tax
Planning.
PROFESSIONAL PRESENTATIONS
"Fundamentals of Financial Management and Reporting for Non-Financial Managers,"
Austin Energy, July 2000.
"Fundamentals of Finance and Accounting," the IC2 Institute, University of Texas at
Austin, December 1996 and 1997.
"Fundamentals of Financial Analysis and Project Evaluation," Central and South West
Companies, April, May, and June 1997.
"Fundamentals of Financial Management and Valuation," West Texas Utilities Company,
November 1995.
"Financial Modeling: Testing the Reasonableness of Regulatory Results," University of
Texas Center for Legal and Regulatory Studies Conference, June 1991.
"Estimating the Cost of Equity Capital," University of Texas at Austin Utilities
Conference, June 1989, June 1990.
"Regulation: The Bottom Line," Texas Society of Certified Public Accountants, Annual
Utilities Conference, Austin, Texas, April 1990.
"Alternative Treatments of Large Plant Additions — Modeling the Alternatives,"
University of Texas at Dallas Public Utilities Conference, July 1989.
"Industrial Customer Electrical Requirements," Edison Electric Institute Financial
Conference, Scottsdale, Arizona, October 1988.
"Acquisitions and Consolidations in the Electric Power Industry," Conference on
Emerging Issues of Competition in the Electric Utility Industry, University of
Texas at Austin, May 1988.
"The General Fund Transfer - Is It A Tax? Is It A Dividend Payout? Is It Fair?" The
Texas Public Power Association Annual Meeting, Austin, May 1984.
"Avoiding 'Rate Shock' - Preoperational Phase-In Through CWIP in Rate Base," Edison
Electric Institute, Finance Committee Annual Meeting, May 1983.
"A Cost-Benefit Analysis of Alternative Bond Ratings Among Electric Utility
Companies in Texas," (with B.L. Heidebrecht and J.L. Nash), Texas Senate
Subcommittee on Consumer Affairs, December 1982.
"Texas PUC Rate of Return and Construction Work in Progress Methods," New York
Society of Security Analysts, New York, August 1982.
"In Support of Debt Service Requirements as a Guide to Setting Rates of Return for
Subsidiaries," Financial Forum, National Society of Rate of Return Analysts,
Washington, D.C., May 1982.
PUBLICATIONS
"Institutional Constraints on Public Fund Performance," (with B.L. Hadaway) Journal of
Portfolio Management, Winter 1989.
"Implications of Savings and Loan Conversions in a Deregulated World," (with B.L.
Hadaway) Journal of Bank Research, Spring 1984.
"Regulatory Treatment of Construction Work in Progress," abstract, (with B.L.
Heidebrecht and J. L. Nash), Rate & Regulation Review, Edison Electric Institute,
December 20,1982.
"Financial Integrity and Market-to-Book Ratios in an Efficient Market," (with W. L.
Beedles), Gas Pricing & Ratemaking, December 7, 1982.
"An Analysis of the Performance Characteristics of Converted Savings and Loan
Associations," (with B.L. Hadaway) Journal of Financial Research, Fall 1981.
"Inflation Protection from Multi-Asset Sector Investments: A Long-Run Examination of
Correlation Relationships with Inflation Rates," (with B.L. Hadaway), Review of
Business and Economic Research, Spring 1981.
Appendix B
Page 11 of 11
"Converting to a Stock Company-Association Characteristics Before and After
Conversion," (with B.L. Hadaway), Federal Home Loan Bank Board Journal,
October 1980.
"A Large-Sample Comparative Test for Seasonality in Individual Common Stocks,"
(with D.P. Rochester), Journal of Economics and Business, Fall 1980.
"Diversification Possibilities in Agricultural Land Investments," Appraisal Journal,
October 1978.
"Further Evidence on Seasonality in Common Stocks," (with D.P. Rochester), Journal of
Financial and Quantitative Analysis, March 1978.
. Appendix C
Page 1 of 5
Appendix C
Technical Discussion of Discounted Cash Flow
And Risk Premium Models
General Stock Price DCF Model
The DCF model is predicated on the concept that stock prices are the present value or
discounted value of all future dividends that investors expect to receive. In the most
general form, the DCF model is expressed in the following formula:
Po = Di/(l+k) + D2/(l+k)2 + ... + Doo/O+kf (1)
where Po is today's stock price; Di, D2, etc. are all future dividends and k is the discount
rate, or the investor's required rate of return on equity. Equation (1) is a routine present
value calculation based on the assumption that the stock's price is the present value of all
dividends expected to be paid in the future.
Constant Growth DCF Model
Under the additional assumption that dividends are expected to grow at a constant rate
"g" and that k is strictly greater than g, equation (1) can be solved for k and rearranged
into the simple form:
k = D,/P0 + g (2)
Equation (2) is the familiar constant growth DCF model for cost of equity estimation,
where Dj/Po is the expected dividend yield and g is the long-term expected dividend
growth rate.
Multi-stage DCF Models
Under circumstances when growth rates are expected to fluctuate or when future growth
rates are highly uncertain, the constant growth model may not give reliable results.
Although the DCF model itself is still valid (equation 1 is mathematically correct), under
Appendix C
Page 2 of 5
such circumstances the simplified form of the model must be modified to capture market
expectations accurately.
Over the past several years, events in the electric utility industry have challenged
the constant growth assumption of the traditional DCF model. Since the mid-1980s,
dividend growth expectations for many electric utilities have fluctuated widely. In fact,
over one-third of the electric utilities in the U.S. reduced or eliminated their common
dividends during this time period. Some of these companies have reestablished their
dividends, producing exceptionally high growth rates. Under these circumstances, long­
term growth rate estimates may be highly uncertain, and estimating a reliable "constant"
growth rate for many companies is often difficult.
When growth expectations are uncertain, the more general version of the model
represented in equation (1) should be solved explicitly over a finite "transition" period
while uncertainty prevails. The constant growth version of the model can then be applied
after the transition period, under the assumption that more stable conditions will prevail
in the future. There are two alternatives for dealing with the nonconstant growth
transition period.
Terminal Price Multi-stage DCF Model
Under the "terminal price" multi-stage growth approach, equation (1) is written in a
slightly different form:
Po = Di/(l+k) + D2/(l+k)2 + ... + Px/(l+k)T (3)
where the variables are the same as in equation (1) except that Px is the estimated stock
price at the end of the transition period T. Under the assumption that normal growth
resumes after the transition period, the price Px is then expected to be based on constant
Appendix C
Page 3 of 5
growth assumptions. With the terminal price approach, the estimated cost of equity, k, is
just the rate of return that investors would expect to earn if they bought the stock at
today's market price, held it and received dividends through the transition period (until
period T), and then sold it for price Pt. In this approach, the analyst's task is to estimate
the rate of return that investors expect to receive given the current level of market prices
they are willing to pay.
Generalized Multi-stage DCF Model
Under the general "multistage" growth approach, equation (1) is simply expanded to
incorporate two or more growth rate periods, with the assumption that a permanent
constant growth rate can be estimated for some point in the future:
Po = D o (l+ g i)/(l+ k ) + ... + D 2( 1 +g2)n/(1 +k)n+
... + [D T (l+ g T) (T+1)/(k -g T )]/(l+ k )T (4 )
where the variables are the same as in equation (1), but gi represents the growth rate for
the first period; D2 is the dividend at the beginning of the second period and g2 is the
growth rate for the second period; and Dt is the dividend at the beginning of the third
period and gx for the period from year T (the end of the transition period) to infinity. The
difficult task for analysts in the multistage approach is determining the various growth
rates for each period.
Although less convenient for exposition purposes, the multi-stage models are
based on the same valid capital market assumptions as the constant growth version. This
approach simply requires more explicit data inputs and more work to solve for the
discount rate, k. Fortunately, the required data are available from investment and
Appendix C
Page 4 of 5
economic forecasting services, and computer algorithms can easily produce the required
solutions.
Equity Risk Premium Models
Equity risk premium model are based on the assumption that equity securities are riskier
than debt and, therefore, that equity investors require a higher rate of return. This basic
premise is well supported by legal and economic distinctions between debt and equity
securities, and it is widely accepted as a fundamental capital market principle. For
example, debt holders' claims to the earnings and assets of the borrower have priority
over all claims of equity investors. The contractual interest on mortgage debt must be
paid in full before any dividends can be paid to shareholders, and secured mortgage
claims must be fully satisfied before any assets can be distributed to shareholders in
bankruptcy. Also, the fixed-income nature of interest payments makes year-to-year
returns from bonds typically more stable than capital gains and dividend payments on
stocks. All these factors demonstrate the more risky position of stockholders and support
the equity risk premium concept.
The risk premium approach is useful because it is founded on current market
interest rates, which are directly observable. This feature assures that risk premium
estimates of the cost of equity begin with a sound basis, which is tied directly to current
market interest rates. However, in regulatory practice there is often considerable debate
about how risk premium data should be used and interpreted. Since the basic task is to
gauge investors’ required returns on long-term investments, some argue that the
estimated equity risk premiums should cover the longest possible time period. Others
argue that market relationships between debt and equity from several decades ago are
Appendix C
Page 5 of 5
irrelevant and that only recent debt-equity return observations should be used in
estimating investor requirements. There is no consensus on this issue. Since analysts
cannot observe or measure investors' expectations directly, it is not possible to know
exactly how such expectations are formed or, therefore, to know exactly what time period
is most appropriate in a risk premium analysis.
The important point in the equity risk premium analysis is to answer the following
question: "What rate of return should equity investors reasonably expect relative to
returns that are currently available from long-term bonds?"
Summary of DCF and Equity Risk Premium Approaches
The DCF and equity risk premium models have become the most widely accepted in
regulatory practice. The DCF model and a review of equity risk premium data generally
provide a reasonable estimate of the cost of equity. While estimating the DCF growth
rate is controversial, the dividend yield is straightforward, and the model's results
generally comport with capital market behavior. The equity risk premium approach
provides further confirmation. While its inputs and the interpretation of its results require
informed judgment, under normal market conditions the risk premium approach is a
useful addition to the overall analysis.
m \ W 21 W 10' 58 Case No. PAC-E-11-12
Exhibit No. 13
10r.s ^ j ~ Witness: Samuel C. Hadaway
yTr‘ i n ’
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Samuel C. Hadaway
Comparable Company Fundamentals
May 2011
Rocky Mountain Power
Comparable Company Fundamental Characteristics
(1) (2) (3)
______________C apital S tru ctu re (2010)______________
% R eg u lated C redit R ating C om m on Equity L ong-T erm D ebt P referred S tock
No. C om p an y R ev en u e S& P M oody's R atio R atio R atio
1 ALLETE 92.1%A- B a a l 55.8%44.2% 0.0%
2 Alliant E nergy C o.92.4% A-/BBB+ A 2/A3 49.5% 46.3%4.2%
3 B lack Hills C orp 85.7% BBB+ A3 4 8.1% 51.9% 0.0%
4 D TE E nergy C o. 77.6%A A2 4 8.7%51.3%0.0%
5 E dison Internat.80.4%BBB+ A1 44.3%51.8% 3.9%
6 E m pire District 98.6% BBB+ A3 48.7% 51.3% 0.0%
7 E ntergy C orp. 77.8% A-/BBB+ B a a l 42.1%56.3% 1.6%
8 ID A CO RP 84.0% A- A2 50.7% 49.3%0.0%
9 PG & E C orp.100.0% BBB+ A3 49.3% 49.6% 1.1%
10 P ortland G en eral 100.0% A- A3 47.0% 53.0%0.0%
11 SCA N A C orp. 72.9% A- A3 47.1%52.9% 0.0%
12 S e m p ra E nergy 75.7%A+A a3 49.6%49.4% 1.0%
13 S o u th ern C o. 84.7% A A2/A3 44.5%52.5% 3.0%
14 V ectren C orp.73.4% A- A2 50.1%49.9%0.0%
15 W isconsin E nergy 99.1% A-A1 49.0% 50.6%0.4%
16 X cel E nergy Inc.99.3% A A3 46.3% 53.1%0.6%
A v erag e 87.1%A- A2/A3 48.2% 50.8% 1.0%
Column Sources:
(1) Most recent company 10-Ks.
(2) AUS Utility Reports, May 2011.
(3) Value Line Investment Survey, Electric Utility (East), Feb 25, 2011; (Central), Mar 25, 2011; (West), May 6, 2011.
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Rocky Mountain Power
Authorized Electric Utility Equity Returns
A verage A uthorized ROE 2006 No.2007 No. 2008 No.2009 No.2010 No. 2011 No.
All Electric Utilities 10.36% 26 10.36% 39 10.46%37 10.48% 39 10.34%59 10.35% 14
V ertically-Integrated Utilities 10.57% 15 10.56% 28 10.45% 25 10.63% 27 10.38%42 10.18%7
Delivery-Only Utilities 9.91% 10 9.86%11 9.78%7 10.15% 10 9.98% 15 9.81% 5
P ow er P lant Only C a se s 11.90% 1 NA 0 11.44%5 10.18%2 12.30%2 12.30%2
Data Source:
Regulatory Focus, "Major Rate Case Decisions," Regulatory Research Associates, April 5, 2011; January 7, 2011;
January 12, 2009; and January 30, 2007. Data for 2011 is through the 1st Quarter.
pcr.FIVED
Case No. PAC-E-11-12
Exhibit No. 14
Witness: Samuel C. Hadaway
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Samuel C. Hadaway
Capital Market Costs
May 2011
AH®*58
Rocky Mountain Power
Historical Capital Market Costs
2001 2002 2003 2004 2005 2006 2007 2008 2009 2010
Prime Rate 6.9% 4.7%4.1%4.3%6.2%8.0% 8.1% 5.1% 3.3% 3.3%
Consumer Price Index 1.6% 2.5% 2.0% 3.3% 3.3% 2.5%4.1%0.0% 2.8%1.4%
Long-Term Treasuries 5.5%5.4%5.0% 5.1%4.7%5.0%4.8%4.3%4.1% 4.3%
Moody's Avg Utility Debt 7.7% 7.5%6.6%6.2% 5.7%6.1%6.1% 6.7% 6.3% 5.6%
Moody's A Utility Debt 7.8%7.4%6.6%6.2%5.7%6.1%6.1%6.5%6.0% 5.5%
SOURCES:
Prime Interest Rate - Federal Reserve Bank of St. Louis website
Consumer Price Index For All Urban Consumers: All Items (Seasonally Adjusted, December to December) - Federal Reserve Bank of St. Louis website
Long-Term Treasuries - Federal Reserve Bank of St. Louis website; 30-year Treasury bonds 2001 and 2007-2010; 20-year Treasury bonds 2002-2006
Moody's Average Utility Debt - Moody's (Mergent) Bond Record
Moody's A Utility Debt - Moody's (Mergent) Bond Record
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Exhibit No. 14 Page 2 of 3
Case No. PAC-E-11-12
Witness: Samuel C. Hadaway
Rocky Mountain Power
Long-Term Interest Rate Trends
Single-A 30-Year Single-A
Month Utility Rate Treasury Rate Utility Spread
Jan-08 6.02 4.33 1.69
Feb-08 6.21 4.52 1.69
Mar-08 6.21 4.39 1.82
Apr-08 6.29 4.44 1.85
May-08 6.28 4.60 1.68
Jun-08 6.38 4.69 1.69
Jul-08 6.40 4.57 1.83
Aug-08 6.37 4.50 1.87
Sep-08 6.49 4.27 2.22
Oct-08 7.56 4.17 3.39
Nov-08 7.60 4.00 3.60
Dec-08 6.52 2.87 3.65
Jan-09 6.39 3.13 3.26
Feb-09 6.30 3.59 2.71
Mar-09 6.42 3.64 2.78
Apr-09 6.48 3.76 2.72
May-09 6.49 4.23 2.26
Jun-09 6.20 4.52 1.68
Jul-09 5.97 4.41 1.56
Aug-09 5.71 4.37 1.34
Sep-09 5.53 4.19 1.34
Oct-09 5.55 4.19 1.36
Nov-09 5.64 4.31 1.33
Dec-09 5.79 4.49 1.30
Jan-10 5.77 4.60 1.17
Feb-10 5.87 4.62 1.25
Mar-10 5.84 4.64 1.20
Apr-10 5.81 4.69 1.12
May-10 5.50 4.29 1.21
Jun-10 5.46 4.13 1.33
Jul-10 5.26 3.99 1.27
Aug-10 5.01 3.80 1.21
S ep-10 5.01 3.77 1.24
O ct-10 5.10 3.87 1.23
Nov-10 5.37 4.19 1.18
D ec-10 5.56 4.42 1.14
Jan -1 1 5.57 4.52 1.05
Feb-11 5.68 4.65 1.03
M ar-11 5.56 4.51 1.05
Apr-11 5.55 4.50 1.05
3-Mo Avg 5.60 4.55 1.04
12-Mo Avg 5.39 4.22 1.17
Sources: Mergent Bond Record (Utility Rates); www.federalreserve.gov (Treasury Rates).
Three month average is for February 2011 -April 2011.
Twelve month average is for May 2010-April 2011.
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00 Economic indicators
Seasonally Adjusted Annual Rates — Dollar Figures in Billions
on-in _ COfH *1 con-i 0 _
R2010 E2011 E2012 R2010 E2011 E2012 Q3 RQ4 Q1 Q2 Q3 Q4 Q1 Q2
$14,660.4 $15,321.0 $15,981.1 3.8 4.5 4.3
Gross Domestic Product
GDP (current dollars) $14,745.1 $14,871.4 $15,018.5 $15,218.0 $15,438.9 $15,608.6 $15,770.4 $15,887.6
3.8 4.5 4.3 - - -Annual rate of increase (%) 4.6 3.5 4.0 5.4 5.9 4.5 4.2 3.0
2.9 2.9 2.6 - - -Annual rate of increase-real GDP (%) 2.6 3.1 2.7 3.3 3.2 3.8 2.2 1.8
1.0 1.5 1.6 ---Annual rate of increase-GDP deflator (%)2.1 0.4 1.2 2.1 2.6 0.7 2.0 1.2
$9,313.6 $9,563.7 $9,777.4 1.7 2.7 2.2
'Components of Real GDP
Personal consumption expenditures $9,330.6 $9,422.9 $9,456.9 $9,531.0 $9,604.8 $9,662.1 $9,709.3 $9,757.7
1.7 2.7 2.2 - - -% change 2.4 4.0 1.4 3.2 3.1 2.4 2.0 2.0
1,178.3 1,285.3 1,343.4 7.7 9.1 4.5 Durable goods 1,179.3 1,237.2 1,257.4 1,272.3 1,300.5 1,311.1 1,323.5 1,339.9
2,072.6 2,124.6 2,165.3 2.7 2.5 1.9 Nondurable goods 2,076.2 2,097.4 2,100.2 2,117.8 2,133.3 2,147.3 2,155.2 2,161.5
6,064.7 6,170.8 6,292.8 0.5 1.7 2.0 Services 6,076.9 6,099.2 6,113.3 6,156.0 6,190.2 6,223.5 6,252.0 6,280.2
1,365.0 1,490.7 1,587.6 5.7 9.2 6.5 Nonresidental fixed investment 1,388.0 1,413.9 1,424.2 1,459.9 1,519.6 1,558.9 1,565.7 1,575.4
5.7 9.2 6.5 - - -% change 10.0 7.7 3.0 10.4 17.4 10.7 1.8 2.5
1,056.1 1,201.0 1,316.8 15.3 13.7 9.6 Producers durable equipment 1,084.2 1,104.5 1,131.6 1,165.3 1,229.5 1,277.3 1,288.7 1,306.4
323.0 318.2 382.8 (3.3) (1.5)20.3 Residental fixed investment 313.8 316.3 310.9 312.3 316.6 333.1 346.1 367.5
(3.3) (1.5)20.3 - - -% change (28.0) 3.1 (6.7)1.8 5.7 22.4 16.6 27.2
62.6 76.9 52.8 - - -Net change in business inventories 121.4 16.2 83.8 57.8 70.1 95.9 85.8 57.8
2,568.4 2,540.0 2,490.6 1.0 (1.1)(1.9) Gov't purchases of goods & services 2,589.6 2,578.8 2,546.1 2,552.0 2,539.7 2,522.0 2,504.2 2,496.6
1,076.9 1,076.2 1,040.8 4.8 (0.1)(3.3)Federal 1,094.3 1,093.4 1,076.3 1,082.8 1,077.1 1,068.6 1,056.8 1,045.4
1,497.4 1,470.1 1,455.2 (1.4) (1.8)(1.0)State & local 1,501.7 1,491.9 1,476.1 1,475.7 1,469.0 1,459.8 1,453.4 1,456.7
(422.5) (378.3) (303.5) - - - Net exports (505.0) (397.7)(386.7)(364.3)(385.7)(376.5) (338.0) (316.5)
1,665.5 1,832.2 2,025.2 11.7 10.0 10.5 Exports 1,679.3 1,714.3 1,761.2 1,802.2 1,857.6 1,907.7 1,957.6 2,003.2
2,088.1 2,210.5 2,328.7 12.6 5.9 5.3 Imports 2,184.3 2,112.0 2,147.9 2,166.5 2,243.2 2,284.2 2,295.6 2,319.8
$12,546.7 $13,210.8 $13,699.7 3.1 5.3 3.7
"Income & Profits
Personal income $12,595.5 $12,724.0 $12,969.3 $13,133.7 $13,303.2 $13,437.1 $13,470.2 $13,622.4
11,380.0 11,893.0 12,253.0 3.1 4.5 3.0 Disposable personal income 11,417.3 11,518.9 11,697.8 11,833.5 11,965.1 12,075.5 12,064.7 12,193.5
5.8 5.6 4.6 -- -Savings rate (%)6.0 5.5 5.8 5.6 5.5 5.4 4.4 4.6
1,801.1 1,691.1 1,692.2 36.8 (6.1)0.1 Corporate profits before taxes 1,845.7 1,797.4 1,748.4 1,689.1 1,671.9 1,655.0 1,693.3 1,663.9
1,384.5 1,223.3 1,248.7 30.4 (11.6)2.1 Corporate profits after taxes 1,416.3 1,369.3 1,264.7 1,223.0 1,209.1 1,196.5 1,245.9 1,229.6
77.34 97.27 99.43 50.8 25.8 2.2 TEarnings per share (S&P 500)72.04 77.34 84.37 89.33 94.61 97.27 98.76 98.31
1.6 2.9 2.1
fPrices & Interest Rates
Consumer price index 1.4 2.6 5.1 3.1 2.2 1.5 2.3 1.6
0.1 0.3 2.1 - - -Treasury bills 0.2 0.1 0.1 0.2 0.3 0.5 1.0 1.6
3.2 3.9 5.5 -- -10-yr notes 2.8 2.9 3.5 3.7 4.0 4.3 4.8 5.3
4.3 4.9 6.3 - - - 30-yr bonds 3.9 4.2 4.6 4.7 5.0 5.3 5.7 6.1
4.9 5.5 7.2 ---New issue rate-corporate bonds 4.6 4.9 5.1 5.3 5.6 6.0 6.5 7.0
585.4 612.1 979.4 5.6 4.6 60.0
Other Key Indicators
Housing starts (1,000 units SAAR)588.3 534.3 535.1 561.2 637.8 714.5 802.4 915.4
11.5 13.2 14.3 11.0 14.2 8.8 Auto & truck sales (1,000,000 units) 11.6 12.3 13.0 12.5 13.6 13.6 13.9 14.3
9.6 8.7 8.4 - --Unemployment rate (%) 9.6 9.6 8.9 8.8 8.6 8.5 8.4 8.4
(3.0) (6.9)(2.2)---§U.S. dollar (8.5)(14.4) (6.2)(8.1) (4.0) (4.6) (1.8) (0.7)
Note: Annual changes are from prior year and quarterly changes are from prior quarter. Figures may not add to totals because of rounding. A-Advance data. P-Preliminary. E-Estimated. R-Revised.
*2005 Chain-weighted dollars. "Current dollars. ^Trailing 4 quarters. tAverage for period. §Quarterly % changes at quarterly rates. This forecast prepared by Standard & Poor's.
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m m - t v w 10:58 Case No. PAC-E-11-12
Exhibit No. 15
UTlLlT’E^ ^ A Witness: Samuel C. Hadaway
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Samuel C. Hadaway
GDP Growth Rate
May 2011
R ocky M ountain P ow er
GDP Growth Rate Forecast
Nominal
GDP
%
Change
GDP Price
Deflator
%
Change CPI
%
Change
1950 313.3 15.0 25.0
1951 347.9 11.0%15.9 5.6% 26.5 6.0%
1952 371.4 6.8%16.1 1.5% 26.7 0.9%
1953 375.9 1.2%16.2 0.8% 26.9 0.6%
1954 389.4 3.6%16.4 0.8% 26.8 -0.4%
1955 426.0 9.4%16.8 2.6% 26.9 0.4%
1956 448.1 5.2%17.3 3.3% 27.6 2.8%
1957 461.5 3.0%17.8 2.7%28.5 3.0%
1958 485.0 5.1%18.3 2.5% 29.0 1.8%
1959 513.2 5.8% 18.4 0.9% 29.4 1.5%
1960 523.7 2.0% 18.7 1.4%29.8 1.4%
1961 562.6 7.4%18.9 1.1% 30.0 0.7%
1962 593.3 5.5%19.1 1.3%30.4 1.2%
1963 633.5 6.8%19.4 1.4%30.9 1.6%
1964 675.6 6.6%19.7 1.5% 31.3 1.2%
1965 747.5 10.6%20.1 2.0% 31.9 1.9%
1966 806.9 7.9%20.8 3.5% 32.9 3.4%
1967 852.7 5.7%21.4 3.1%34.0 3.3%
1968 936.2 9.8%22.4 4.6% 35.6 4.7%
1969 1004.5 7.3%23.6 5.2% 37.7 5.9%
1970 1052.7 4.8%24.7 5.0% 39.8 5.6%
1971 1151.4 9.4%25.9 4.7% 41.1 3.3%
1972 1286.6 11.7%27.1 4.5% 42.5 3.4%
1973 1431.8 11.3%28.9 6.8% 46.3 8.9%
1974 1552.8 8.5%32.0 10.7%51.9 12.1%
1975 1713.9 10.4%34.4 7.6% 55.6 7.1%
1976 1884.5 10.0%36.3 5.4% 58.4 5.0%
1977 2110.8 12.0% 38.7 6.7% 62.3 6.7%
1978 2416.0 14.5%41.5 7.3%67.9 9.0%
1979 2659.4 10.1%45.2 8.7%76.9 13.3%
1980 2915.3 9.6%49.6 9.7% 86.4 12.4%
1981 3194.7 9.6%53.6 8.3% 94.1 8.9%
1982 3312.5 3.7%56.4 5.2% 97.7 3.8%
1983 3688.1 11.3%58.3 3.3% 101.4 3.8%
1984 4034.0 9.4%60.4 3.6% 105.5 4.0%
1985 4318.7 7.1%62.1 2.8% 109.5 3.8%
1986 4543.3 5.2%63.5 2.3%110.8 1.2%
1987 4883.1 7.5%65.5 3.1%115.6 4.3%
1988 5251.0 7.5%67.9 3.7%120.7 4.4%
1989 5581.7 6.3%70.3 3.5% 126.3 4.6%
1990 5846.0 4.7%73.2 4.2%134.2 6.3%
1991 6092.5 4.2%75.5 3.2% 138.2 3.0%
1992 6493.6 6.6% 77.1 2.2% 142.3 3.0%
1993 6813.8 4.9%78.8 2.2%146.3 2.8%
1994 7248.2 6.4%80.5 2.1% 150.1 2.6%
1995 7542.5 4.1%82.1 2.0% 153.9 2.5%
1996 8023.0 6.4%83.6 1.8% 159.1 3.4%
1997 8505.7 6.0% 85.0 1.6% 161.8 1.7%
1998 9027.5 6.1%85.9 1.1% 164.4 1.6%
1999 9607.7 6.4%87.2 1.5% 168.8 2.7%
2000 10129.8 5.4%89.4 2.5%174.6 3.4%
2001 10373.1 2.4%91.2 2.0% 177.4 1.6%
2002 10766.9 3.8%92.8 1.8% 181.8 2.5%
2003 11416.5 6.0%94.8 2.1% 185.5 2.0%
2004 12144.9 6.4%97.9 3.2% 191.7 3.3%
2005 12915.6 6.3%101.3 3.5%198.1 3.3%
2006 13611.5 5.4%104.2 2.9% 203.1 2.5%
2007 14291.3 5.0%106.9 2.6% 211.4 4.1%
2008 14191.2 -0.7%109.2 2.1% 211.3 0.0%
2009 14277.3 0.6%109.7 0.4%217.2 2.8%
2010 14861.0 4.1%111.2 1.4%220.2 1.4%
10-Year Average 3.9%2.2% 2.4%
20-Year Average 4.8%2.1%2.5%
30-Year Average 5.6%2.7% 3.2%
40-Year Average 6.9%3.9% 4.4%
50-Year Average 7.0% 3.7%4.1%
60-Year Average 6.7%3.4%3.7%
Average of Periods 5.8% 3.0% 3.4%
Source: St. Louis Federal Reserve Bank, www.research.stlouisfed.org
Rocky Mountain Power
Exhibit No. 15 Page 1 of 1
Case No. PAC-E-11-12
Witness: Samuel C. Hadaway
PFP.FWED
Case No. PAC-E-11-12
Exhibit No. 16
Witness: Samuel C. Hadaway
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Samuel C. Hadaway
Discounted Cash Flow Analysis
May 2011
211! MAY 2 1 A M P 5 8
Rocky Mountain Power
Discounted Cash Flow Analysis
Summary Of DCF Model Results
Company
Constant Growth
DCF Model
Analysts' Growth Rates
Constant Growth
DCF Model
Long-Term GDP Growth
Low Near-Term Growth
Two-Stage Growth
DCF Model
1 ALLETE 9.4% 10.5% 10.1%
2 Alliant Energy Co.11.2%10.4% 10.2%
3 Black Hills Corp 11.7%10.4% 9.9%
4 DTE Energy Co. 9.9%10.8%10.6%
5 Edison Internat. 7.9%9.3%9.0%
6 Empire District 12.4%11.7% 11.1%
7 Entergy Corp.6t4%10.7%10.3%
8 IDACORP 7.7% 9.0%9.1%
9 PG&E Corp. 10.6%10.2%10.1%
10 Portland General 10.5%10.5% 10.3%
11 SCANACorp. 9.1%10.7% 10.2%
12 Sempra Energy 9.4%9.7% 9.7%
13 Southern Co. 10.5%11.0%10.7%
14 Vectren Corp. 10.6%11.1% 10.6%
15 Wisconsin Energy 11.4%9.3% 9.7%
16 Xcel Energy Inc. 9.8%10.2%9.9%
GROUP AVERAGE 10.1%10.3% 10.1%
GROUP MEDIAN 10.5%10.5% 10.1%
Sources: Value Line Investment Survey, Electric Utility (East), Feb 25, 2011; (Central), Mar 25, 2011; (West), May 6, 2011.
Analysts' growth result for Entergy at 6.4% is below the current cost of single-A debt (5.60% from
Exhibit No. 14, p. 2) plus 100 basis points and is eliminated.
NOTE: SEE PAGE 5 OF THIS EXHIBIT FOR FURTHER EXPLANATION OF EACH COLUMN.
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Constant Growth DCF Model
Analysts" Growth Rates
(1)(2) (3)(4)(5)(6)(7) (8)(9)
Next Analysts' Estimated Growth
Company
Recent
Price(PO)
Year's
Div(D1)
Dividend
Yield
Value
Line Zacks Thomson Reuters
Average
Growth
ROE
K=Div Yld+G
1 ALLETE 38.30 1.80 4.70% 4.50% 5.00%5.00% 4.33%4.71% 9.4%
2 Alliant Energy Co.38.74 1.78 4.59%7.00% 5.50% 8.23% 5.55%6.57% 11.2%
3 Black Hills Corp 32.12 1.48 4.61% 10.50% 6.00% 6.00%6.00% 7.13%11.7%
4 DTE Energy Co. 48.00 2.40 5.00% 5.50% 5.00%4.88% 4.39%4.94% 9.9%
5 Edison Internat. 37.05 1.31 3.54% NA 5.00% 3.45% 4.69%4.38% 7.9%
6 Empire District
7 Entergy Corp.
21.58
fifl M
1.28
R AO
5.93%
A R7%
7.00%
1 nn%
NA
1 «sn%
6.00%
NA
NA
° '>A%
6.50%
1 <iR%
12.4%
fi A°/n
8 IDACORP 37.83 1.20 3.17% 4.00% 4.70%4.67% 4.67% 4.51%7.7%
9 PG&E Corp. 45.03 1.98 4.40%7.00% 5.50% 6.08% 6.06%6.16% 10.6%
10 Portland General 23.53 1.11 4.72% 7.50% 5.20%4.65% 5.89% 5.81% 10.5%
11 SCANACorp. 40.24 1.98 4.92% 3.00% 4.60% 4.68%4.47% 4.19% 9.1%
12 Sempra Energy 52.90 2.08 3.93% 3.50% 7.00% 5.63%5.72% 5.46% 9.4%
13 Southern Co.37.81 1.96 5.18% 5.00% 5.00% 5.51%5.60% 5.28% 10.5%
14 Vectren Corp. 26.72 1.41 5.28% 5.50% 5.00%5.35%5.35% 5.30% 10.6%
15 Wisconsin Energy 29.80 1.04 3.49% 7.50% 8.00%8.12% 7.84% 7.87%11.4%
16 Xcel Energy Inc.23.83 1.06 4.45% 5.00% 4.90%5.44% 5.90% 5.31% 9.8%
GROUP AVERAGE
GROUP MEDIAN
35.56 1.59 4.53%
4.61%
5.89% 5.46% 5.58%5.46% 5.61% 10.1%
10.5%
Sources: Value Line Investment Survey, Electric Utility (East), Feb 25, 2011; (Central), Mar 25, 2011; (West), May 6, 2011.
The result for Entergy at 6.4% is below the current cost of single-A debt (5.60% from Exhibit No. 14), p. 2) plus 100
basis points and is eliminated.
NOTE: SEE PAGE 5 OF THIS EXHIBIT FOR FURTHER EXPLANATION OF EACH COLUMN.
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Constant Growth DCF Model
Long-Term GDP Growth
(10)(11) (12) (13)(14)
Recent
Next
Year's Dividend GDP ROE
Company Price(PO) Div(D1)Yield Growth K=DivYld+G
1 ALLETE 38.30 1.80 4.70% 5.80%10.5%
2 Alliant Energy Co.38.74 1.78 4.59%5.80%10.4%
3 Black Hills Corp 32.12 1.48 4.61% 5.80%10.4%
4 DTE Energy Co.48.00 2.40 5.00% 5.80% 10.8%
5 Edison Internat.37.05 1.31 3.54% 5.80% 9.3%
6 Empire District 21.58 1.28 5.93% 5.80%11.7%
7 Entergy Corp.69.84 3.40 4.87% 5.80%10.7%
8 IDACORP 37.83 1.20 3.17% 5.80%9.0%
9 PG&E Corp.45.03 1.98 4.40%5.80%10.2%
10 Portland General 23.53 1.11 4.72% 5.80%10.5%
11 SCANACorp.40.24 1.98 4.92% 5.80%10.7%
12 Sempra Energy 52.90 2.08 3.93% 5.80%9.7%
13 Southern Co.37.81 1.96 5.18%5.80% 11.0%
14 Vectren Corp.26.72 1.41 5.28% 5.80%11.1%
15 Wisconsin Energy 29.80 1.04 3.49% 5.80%9.3%
16 Xcel Energy Inc.23.83 1.06 4.45% 5.80%10.2%
GROUP AVERAGE
GROUP MEDIAN
37.71 1.70 4.55%
4.65%
5.80%10.3%
10.5%
Sources: Value Line Investment Survey, Electric Utility (East), Feb 25, 2011; (Central), Mar 25, 2011; (West), May 6, 2011.
NOTE: SEE PAGE 5 OF THIS EXHIBIT FOR FURTHER EXPLANATION OF EACH COLUMN.Ro
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Low Near-Term Growth
Two-Stage Growth DCF Model
(15)(16)(17)(18)(19)(20)(21) (22)(23) (24) (25)
Company
2012
Div
2015
Div
Annual
Change
to 2015
CASH FLOWS ROE=lnternal
Rate of Return
(Yrs 0-150)
Recent
Price
Year 1
Div
Year 2
Div
Year 3
Div
Year 4
Div
Year 5 Year 5-150
Div Div Growth
1 ALLETE 1.80 1.95 0.05 -38.30 1.80 1.85 1.90 1.95 2.06 5.80% 10.1%
2 Alliant Energy Co. 1.78 2.00 0.07 -38.74 1.78 1.85 1.93 2.00 2.12 5.80%10.2%
3 Black Hills Corp 1.48 1.55 0.02 -32.12 1.48 1.50 1.53 1.55 1.64 5.80% 9.9%
4 DTE Energy Co. 2.40 2.70 0.10 -48.00 2.40 2.50 2.60 2.70 2.86 5.80%10.6%
5 Edison Internat.1.31 1.40 0.03 -37.05 1.31 1.34 1.37 1.40 1.48 5.80%9.0%
6 Empire District 1.28 1.35 0.02 -21.58 1.28 1.30 1.33 1.35 1.43 5.80%11.1%
7 Entergy Corp. 3.40 3.70 0.10 -69.84 3.40 3.50 3.60 3.70 3.91 5.80% 10.3%
8 IDACORP 1.20 1.50 0.10 -37.83 1.20 1.30 1.40 1.50 1.59 5.80% 9.1%
9 PG&E Corp.1.98 2.30 0.11 -45.03 1.98 2.09 2.19 2.30 2.43 5.80%10.1%
10 Portland General 1.11 1.25 0.05 -23.53 1.11 1.16 1.20 1.25 1.32 5.80%10.3%
11 SCANA Corp. 1.98 2.10 0.04 -40.24 1.98 2.02 2.06 2.10 2.22 5.80%10.2%
12 Sempra Energy 2.08 2.45 0.12 -52.90 2.08 2.20 2.33 2.45 2.59 5.80%9.7%
13 Southern Co.1.96 2.20 0.08 -37.81 1.96 2.04 2.12 2.20 2.33 5.80%10.7%
14 Vectren Corp.1.41 1.50 0.03 -26.72 1.41 1.44 1.47 1.50 1.59 5.80%10.6%
15 Wisconsin Energy 1.04 1.40 0.12 -29.80 1.04 1.16 1.28 1.40 1.48 5.80%9.7%
16 Xcel Energy Inc. 1.06 1.15 0.03 -23.83 1.06 1.09 1.12 1.15 1.22 5.80% 9.9%
GROUP AVERAGE
GROUP MEDIAN
10.1%
10.1%
Sources: Value Line Investment Survey, Electric Utility (East), Feb 25, 2011; (Central), Mar 25, 2011; (West), May 6, 2011.
NOTE: SEE PAGE 5 OF THIS EXHIBIT FOR FURTHER EXPLANATION OF EACH COLUMN.Ro
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Rocky Mountain Power
Discounted Cash Flow Analysis
Column Descriptions
Column
Column
Column
Column
Column
Column
Column
Column
Column
Column
Column
Column
Column
1: Three-month Average Price per Share (Feb 2011-Apr 2011)Column 14:Column 12 Plus Column 13
2: 2012 Div per Share from Value Line Column 15:Averge 2011/2012 Div per Share from Value Line
3: Column 2 Divided by Column 1 Column 16:Estimated 2015 Div per Share from Value Line
4: "Est'd *08-10 to '14-'16" Earnings Growth Reported by Value Line Column 17: (Column 16 Minus Column 15) Divided by Three
5: "Next 5 Years" Company Growth Estimate as Column 18: See Column 1
Reported by Zacks.com
Column 19: See Column 15
6: "Next 5 Years (per annum) Growth Estimate Reported
by Thomson Financial Network (at Yahoo Finance)Column 20:Column 19 Plus Column 17
7: Mean "LT Growth Rate (%)” Reported by Reuters.com Column 21: Column 20 Plus Column 17
8: Average of Columns 4-7 Column 22:Column 21 Plus Column 17
9: Column 3 Plus Column 8 Column 23: Column 22 Increased by the Growth
10: See Column 1
Column 24:
Rate Shown in Column 24
See Column 13
11: See Column 2
Column 25:The Internal Rate of Return of the Cash Flows
12: Column 11 Divided by Column 10 in Columns 18-23 along with the Dividends
13: Average of GDP Growth During the Last 10 year, 20 year,
for the Years 6-150 Implied by the Growth
Rates shown in Column 24
30 year, 40 year, 50 year, and 60 year growth periods.
See Exhibit No. 15
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R E C E I V E D
2!!! I MAY 2 7 AM 10- 5 9 Case N o p a c . ^ \ . n
Exhibit No. 17
U T 'riT ' " r Vn i Witness: Samuel C. Hadaway
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOUNTAIN POWER
Exhibit Accompanying Direct Testimony of Samuel C. Hadaway
Risk Premium Analysis
May 2011
Rocky Mountain Power
Exhibit No. 17 Page 1 of 3
Case No. PAC-E-11-12
Witness: Samuel C. Hadaway
Rocky Mountain Power
Risk Premium Analysis
(Based on Projected Interest Rates)
MOODY’S AVERAGE AUTHORIZED
PUBLIC UTILITY ELECTRIC
BOND YIELD (1) RETURNS (2)
INDICATED
RISK
PREMIUM
1980 13.15% 14.23%1.08%
1981 15.62% 15.22%-0.40%
1982 15.33% 15.78%0.45%
1983 13.31% 15.36%2.05%
1984 14.03%15.32% 1.29%
1985 12.29% 15.20%2.91%
1986 9.46%13.93%4.47%
1987 9.98% 12.99%3.01%
1988 10.45%12.79%2.34%
1989 9.66% 12.97% 3.31%
1990 9.76%12.70%2.94%
1991 9.21% 12.55%3.34%
1992 8.57%12.09%3.52%
1993 7.56% 11.41%3.85%
1994 8.30% 11.34%3.04%
1995 7.91%11.55%3.64%
1996 7.74% 11.39%3.65%
1997 7.63%11.40%3.77%
1998 7.00% 11.66%4.66%
1999 7.55% 10.77%3.22%
2000 8.14% 11.43% 3.29%
2001 7.72%11.09%3.37%
2002 7.53% 11.16%3.63%
2003 6.61% 10.97%4.36%
2004 6.20% 10.75%4.55%
2005 5.67% 10.54%4.87%
2006 6.08% 10.36%4.28%
2007 6.11%10.36%4.25%
2008 6.65% 10.46%3.81%
2009 6.28% 10.48%4.20%
2010 5.55%10.34% 4.79%
AVERAGE 8.94% 12.21%3.28%
INDICATED COST OF EQUITY
PROJECTED SINGLE-A UTILITY BOND YIELD*
MOODY'S AVG ANNUAL YIELD DURING STUDY
INTEREST RATE DIFFERENCE
5.94%
8.94%
-3.00%
INTEREST RATE CHANGE COEFFICIENT
ADUSTMENT TO AVG RISK PREMIUM
-41.31%
1.24%
BASIC RISK PREMIUM
INTEREST RATE ADJUSTMENT
EQUITY RISK PREMIUM
3.28%
1.24%
4.51%
PROJECTED SINGLE-A UTILITY BOND YIELD*
INDICATED EQUITY RETURN
5.94%
10.45%
(1) Moody's Investors Service
(2) Regulatory Focus, Regulatory Research Associates, Inc.
’Projected single-A bond yield is 104 basis points over projected long-term Treasury bond rate of 4.9% from
Exhibit No. 14, p. 3. The single-A spread is for 3 months ended April 2011 from Exhibit No. 14, p. 2.
Rocky Mountain Power
Exhibit No. 17 Page 2 of 3
Case No. PAC-E-11-12
Witness: Samuel C. Hadaway
Rocky Mountain Power
Risk Premium Analysis
(Based on Current Interest Rates)
MOODY'S AVERAGE AUTHORIZED INDICATED
PUBLIC UTILITY ELECTRIC RISK
BOND YIELD (1)RETURNS (2) PREMIUM
1980 13.15% 14.23% 1.08%
1981 15.62% 15.22%-0.40%
1982 15.33% 15.78% 0.45%
1983 13.31%15.36%2.05%
1984 14.03% 15.32% 1.29%
1985 12.29% 15.20% 2.91%
1986 9.46%13.93%4.47%
1987 9.98%12.99% 3.01%
1988 10.45% 12.79% 2.34%
1989 9.66%12.97% 3.31%
1990 9.76% 12.70% 2.94%
1991 9.21%12.55%3.34%
1992 8.57%12.09%3.52%
1993 7.56% 11.41% 3.85%
1994 8.30% 11.34% 3.04%
1995 7.91%11.55%3.64%
1996 7.74%11.39% 3.65%
1997 7.63%11.40%3.77%
1998 7.00% 11.66% 4.66%
1999 7.55% 10.77% 3.22%
2000 8.14%11.43%3.29%
2001 7.72%11.09%3.37%
2002 7.53%11.16% 3.63%
2003 6.61%10.97% 4.36%
2004 6.20% 10.75% 4.55%
2005 5.67% 10.54% 4.87%
2006 6.08% 10.36% 4.28%
2007 6.11%10.36% 4.25%
2008 6.65% 10.46% 3.81%
2009 6.28%10.48%4.20%
2010 5.55% 10.34%4.79%
AVERAGE 8.94% 12.21% 3.28%
INDICATED COST OF EQUITY
CURRENT SINGLE-A UTILITY BOND YIELD*
MOODY'S AVG ANNUAL YIELD DURING STUDY
INTEREST RATE DIFFERENCE
5.60%
8.94%
-3.34%
INTEREST RATE CHANGE COEFFICIENT
ADUSTMENT TO AVG RISK PREMIUM
-41.31%
1.38%
BASIC RISK PREMIUM
INTEREST RATE ADJUSTMENT
EQUITY RISK PREMIUM
3.28%
1.38%
4.65%
CURRENT SINGLE-A UTILITY BOND YIELD*
INDICATED EQUITY RETURN
5.60%
10.25%
(1) Moody's Investors Service
(2) Regulatory Focus, Regulatory Research Associates, Inc.
‘Current single-A utility bond yield is three month average of Moody's Single-A Public Utility Bond Yield
Average through April 2011 from Exhibit No. 14, p. 2.
Rocky Mountain Power
Exhibit No. 17 Page 3 of 3
Case No. PAC-E-11-12
Witness: Samuel C. Hadaway
Rocky Mountain Power
Risk Premium Analysis
Regression Analysis & Interest Rate Change Coefficient
Authorized Equity Risk Premiums vs. Utility Interest Rates
(1980-2010)
6%
5% -
4% -
3% -
2% -
y = -0.4131x + 0.0697
R2 = 0.86641% -
0% ■
-1%
13%15%5%7%9%
Average Utility Interest Rates
11%
SUMMARY OUTPUT
Regression Statistics
Multiple R 0.930796942
R Square 0.866382947
Adjusted R Square 0.861775462
Standard Error 0.004709335
Observations 31
ANOVA
df SS MS F Significance F
Regression 1 0.00417028 0.00417028 188.0381651 3.31898E-14
Residual 29 0.000643157 2.21778E-05
Total 30 0.004813437
Intercept
X Variable 1
Coefficients Standard Error t Stat_______P-value_____Lower 95% Upper 95% Lower 95.0% Upper 95.0%
0.069671148 0.00282187 24.68970458 5.07645E-21 0.063899775 0.075442521 0.063899775 0.075442521
-0.413068255 0.030123041 -13.71270087 3.31898E-14 -0.474676791 -0.351459719 -0.474676791 -0.351459719