20080627SKeen direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHAGES FOR ELECTRIC SERVICE.
CASE NO. IPC-E-08-10
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
STEVEN R. KEEN
1 Q.Would you state your name, address, and
2 present occupation?
3 A.My name is Steven R. Keen and my business
4 address is 1221 West Idaho Street, Boise, Idaho. I am
5 employed by Idaho Power Company as Vice President and
6 Treasurer.
7 Q.What is your educational background?
8 A.I graduated with high honors in 1981 from
9 Idaho State University, Pocatello, Idaho, receiving a
10 Baqhelor of Business Administration degree in Accounting. I
11 have also attended numerous seminars and conferences on
12 accounting and finance issues related to the utility
13 industry. I am a Certified Public Accountant licensed in
14 the State of Idaho.
15 Q.Would you please describe your business
16 experience with Idaho Power Company?
17 A.I joined Idaho Power Company ("Idaho Power"
18 or the "Company") in September, 1982, in the Property
19 Accounting Department. In March 1983, I transferred to the
20 Tax Department as a Tax Accountant. From that time through
21 December 1998, I advanced through every position in the Tax
22 Department including Property Tax Representative, Tax
23 Research Coordinator, and, finally, Corporate Tax Director.
24 In January 1999, I became President of IDACORP Financial
S. KEEN, DI 1
Idaho Power Company
1 Services. In June of 2006, I accepted the position of Vice
2 President and Treasurer of Idaho Power Company and IDACORP,
3 Inc.
4 In the course of my duties with Idaho Power Company,
5 I presented testimony in Idaho Power's last general rate
6 case in Idaho, Case No. IPC-E-07-08. I have also presented
7 tax testimony to the Internal Revenue Service as well as tax
8 and/or capitalization rate testimony to the Departments of
9 Revenue and Taxation for Idaho, Oregon, Wyoming, and Nevada.
10 Q.What are your duties as Vice President and
11 Treasurer of Idaho Power as they relate to this proc~eding?
12 A.I oversee the direct financial planning,
13 procurement, and investment of funds for Idaho Power, as
14 well as supervise corporate liquidity management.
15 My duties and responsibilities include various
16 aspects of all the Company's financings and other financial
17 matters. With respect to long-term financings, sale of
18 bonds and equity, my duties include development of financial
19 plans with senior officers, meeting with representatives of
20 investment banking firms that are interested in underwriting
21 Idaho Power securities, discussions with credit rating
22 agencies, assisting in preparation of financial material
23 including Registration Statements filed with the Securities
24 and Exchange Commission, representing the Company at
S. KEEN, DI 2
Idaho Power Company
1 information meetings for investment banking firms, reviewing
2 information relative to the Company's financings and
3 recommending disposition of net proceeds. With respect to
4 short-term financings, these duties and responsibilities
5 include negotiation of lines of credit with commercial banks
6 and overseeing the sale of commercial paper.
7 Q.Do your responsibilities include
8 communication with members of the financial community?
9 A.Yes. I am in continuous contact with
10 individuals representing investment and commercial banking
11 firms, credit rating agencies, insurance companies,
12 institutional investment firms, and other organizations
13 interested in publicly traded securities that actively
14 follow IDACORP and Idaho Power Company. In association with
15 the Company's Chief Financial Officer and the Director of
16 Investor Relations, my responsibilities include keeping
17 these persons informed of the Company's financial condition,
18 arranging meetings with these people and Idaho Power's
19 senior executive management, and visiting with financial
20 representatives in their respective offices. Some of these
21 members of the investment community have followed the
22 electric utility industry for an extended period of time and
23 have a great deal of expertise in the financial problems and
24 prospects of utilities.
S. KEEN, DI 3
Idaho Power Company
1 Through my continual contact with the financial
2 community and review of investment banking analytical
3 reports and articles issued by these firms and the rating
4 agencies, I am able to keep informed on trends, interest
5 rates, financing costs, security ratings, and other
6 financial developments in the public utility industry.
7 Q.Are you a member of any professional
8 societies or associations?
9 A.Yes. I am a current member and past board
10 president of the Idaho Society of Certified Public
11 Accountants. I am a current member of and past council
12 member of the American Institute of Certified Public
13 Accountants. I am a current member and past board chairman
14 of the Associated Taxpayers of Idaho. I am also the
15 current chairman of the Board of the Idaho Tax Foundation.
16 I am a member of the Idaho Association for Financial
17 Professionals.
18 I also receive information from attendance at
19 conferences and seminars of these and other utility
20 professional groups such as the Edison Electric Institute.
21 Through participation in these events, I gain additional
22 insights into the financial developments affecting Idaho
23 Power Company as well as the electric utility industry.
S. KEEN, DI 4
Idaho Power Company
1 Q.What is the purpose of your testimony in
2 this proceeding?
3 A.I am sponsoring testimony as to the point
4 estimate for Idaho Power Company's rate of return on common
5 equity and the embedded cost of long-term debt, risk
6 factors generally and that are unique to Idaho Power
7 Company, the use of a forecasted year-end 2008 capital
8 structure, and the resultant overall cost of capital used
9 to compute the Company's revenue requirement.
10 Q.What exhibits are you sponsoring?
11 A.I am sponsoring Exhibits numbered 27 and 28.
12 COST OF EQUITY POINT ESTIMATE
13 Q.What return on equity are you recommending
14 in this proceeding?
15 . A.I have selected 11.25 percent as the point
16 estimate for cost of equity for the Company.
17 Q.Does that point estimate align with the
18 recommendations made by the Company's cost of capital
19 witness Mr. Avera?
20 A.It does. The Company's expert witness has
21 recommended a range of between 10.8 and 11.8 percent,
22 excluding the effects of flotation. I have selected a
23 percentage within his recommended range that I believe is
24 appropriate given the concepts put forth by the Company in
S. KEEN, DI 5
Idaho Power Company
1 this case. Elements of our submitted case include requests
2 for reduced regulatory lag and accelerated cash recovery
3 for the carrying cost of a portion of Construction Work in
4 Progress ("CWIP"). Both of these proposals, if accepted by
5 the Commission, would tend to lower the Company's risk
6 profile and warrant a cost of equity below the upper end of
7 Mr. Avera's range.
8 Q.If those concepts are not accepted and not
9 included in a final rate order would that impact your
10 recommendation on the point estimate?
11 A.Yes. Without those enhancements I would be
12 recommending a point estimate higher in Mr. Avera's
13 recommended range.
14 Q.Are there other issues that could
15 potentially influence your recommendation?
16 A.Yes. There are planned workshops focusing
17 on various issues that impact the Company's ability to earn
18 its allowed rate of return. The impacts of the Load Growth
19 Adjustment Rate ("LGAR") will be addressed along with
20 certain other potential changes to the Power Cost
21 Adjustment ("PCA") mechanism. If these issues are resolved
22 in a manner that lessens the negative impacts on the
23 Company, my recommended cost of equity would move lower.
24 If the outcome of these workshops significantly reduces the
S. KEEN, DI 6
Idaho Power Company
1 Company's exposure to the variability of power supply
2 costs and the Company is no longer penalized for bearing
3 the burden of accommodating growth in our service
4 terri tory, I could support a lower cost of equity wi thin
5 Mr. Avera's recommended range. However, that
6 recommendation could only be made if the workshops result
7 in a favorable order to the Company that lowers risk.
8 RISK FACTORS
9 Q.Could you briefly outline what conditions
10 require a return on common equity of 11.25 percent?
11 A.Yes. I will summarize them here and discuss
12 them in greater detail later in my testimony. In addition
13 to the reasons advanced by Mr. Avera, I believe that, at a
14 minimum, an 11.25 percent return on equity is required to
15 properly account for the risks confronting Idaho Power
16 Company, namely: (1) the significant variability in power
17 supply costs that exists due to a predominately
18 hydroelectric generating base subj ect to the uncertainties
19 of weather and water, (2) the effects of pricing changes in
20 a volatile wholesale power supply market in the Western
21 United States and specifically the Northwest, coupled with
22 its effect on the PCA mechanism (3) the impacts related to
23 the current methodology utilized in the LGAR in the PCA,
24 (4) the persistence of water issues and water litigation in
S. KEEN, DI 7
Idaho Power Company
1 Idaho, (5) the renewal of federal licenses for the
2 Company's hydroelectric projects, primarily the Hells
3 Canyon Complex, which provides 40 percent of the Company's
4 total generating capacity and particularly the significant
5 cost of relicensing that project, (6) the impact of
6 Qualified Facility ("QF") related expenditures, (7) the
7 inability of the Company to recover the significant capital
8 investment required for present and growing electrical
9 requirements and service reliability for its customers on a
10 timely basis, (8) the general decline in credit quality of
11 the Company, and (9) the inability of the Company to earn
12 an actual return on capital that is anywhere near a
13 reasonable allowed rate of return.
14 Q.Are some of these risk conditions the same
15 risk conditions that have been raised in past Idaho Power
16 rate proceedings?
17 A.Yes. These risks still exist and the
18 passage of time has exacerbated their potential impact on
19 the Company.
20 Q.Are there other risks, less specific to
21 Idaho Power Company, that also impact your recommendation?
22 A.Yes. There are general financial risks such
23 as increased volatility in the financial markets and what I
24 view as a heightened sensitivity to risk exposure that has
s. KEEN, DI 8
Idaho Power Company
1 evolved since the U. s. housing market began experiencing
2 problems in 2007. There are also industry specific risks,
3 such as unknown costs relative to carbon emissions, an
4 industry-wide need for infrastructure improvements, and
5 increased capital investment as well as inflationary
6 pressures that increase costs of both operating expenses
7 and capital outlays. All of these factors combine to make
8 a challenging environment in which the Company must compete
9 with others in the electric utility industry, for both
10 resources and capital, to serve the needs of its customers
11 and shareowners. While I do not intend to elaborate
12 further on these risk areas, they are factors worthy of
13 notation that point to an increased level of risk exposure
14 for the Company.
15 i.Hydro Variability
16 Q.Please describe the risks specific to Idaho
17 Power's predominately hydroelectric generating base which
18 is subject to the uncertainties of weather and water.
19 A.Idaho Power Company and its customers have
20 historically enjoyed the benefits of a hydroelectric-based
21 utility. The availability of hydroelectric power depends
22 on the amount of snow pack in the mountains upstream of
23 Idaho Power's hydroelectric facilities, reservoir storage,
24 springtime snow pack run-off, rainfall and other weather
S. KEEN, DI 9
Idaho Power Company
1 and stream flow management considerations. During low
2 water years, when stream flows into Idaho Power's
3 hydroelectric proj ects are reduced, Idaho Power's
4 hydroelectric generation is reduced. Extreme temperatures
5 increase demand for power by customers who use electricity
6 for cooling and heating, and moderate temperatures decrease
7 demand for power. Precipi tation or the lack thereof also
8 directly affects the Company's irrigation load. Weather
9 and hydro-production are inextricably linked. Reduced
10 hydroelectric generation resulting from below normal water
11 flows requires the Company to use more expensive thermal
12 generation and/or purchased power to meet the electrical
13 needs of its customers.
14 2.Pricing Vola tili ty and the PCA
15 Q.Does the Company's PCA remove this weather
16 and water risk?
17 A.Not entirely. Although the Idaho Commission
18 grants recovery for the majority of the variations in power
19 supply expense through the Company's PCA, the recovery is
20 less than 100 percent. Although originally viewed by the
21 Company as an earnings stability mechanism, the PCA has
22 provided less stability than anticipated. The risks
23 associated with the Idaho jurisdictional 10 percent of
24 variations in power supply expenses (the portion the
S. KEEN, DI 10
Idaho Power Company
1 Company's shareholders are required to absorb) are having
2 an increasingly significant adverse financial impact on the
3 earnings capability of the Company. Actual results no
4 longer provide the level of earnings stability originally
5 contemplated by the Company.
6 Q.Why have the earnings stability benefits of
7 the PCA to the Company declined?
8 A.While I do not profess to be an expert on
9 the details of the PCA mechanism,from a financial
10 perspective, I can identify one very significant factor
11 affecting the PCA that has materially affected earnings
12 stability.
13 Q.Please elaborate.
14 A.The Commission in 1993 authorized a PCA
15 mechanism with the principal parts being fuel expenses, a
16 deduction for surplus sales, purchased power expenses, and
17 an adjustment to compensate for the difference between
18 actual
19
20 was a
21 rates
22 All of
23
load and the load used to establish base rates.
At the time the PCA was established in 1993, there
fundamental relationship between FERC jurisdictional
for purchases and sales and Idaho Power retail rates.
the prices or rates were cost-based.
In 1997, FERC determined that it would permit
24 market-based rates as opposed to cost-based rates. While
S. KEEN, DI 11
Idaho Power Company
1 Idaho retail rates remained cost based, FERC jurisdictional
2 rates for sales and purchases became market based. The
3 cost or price for both FERC jurisdictional power purchases
4 and sales attributable to Idaho Power increased
5 significantly. This created an enormous difference between
6 the monetary amounts for purchased power and surplus sales
7 that the parties considered in 1992 and 1993 when the PCA
8 methodology was established and the costs and prices
9 experienced in recent years. This volumetric change is
10 truly monumental when you consider the financial size of
11 Idaho Power. Company witness Said informed me that average
12 Idaho Power purchases for the period 1993 though 1996 were
13 at an average expense of $22,389,000 per year. For the
14 period 1997 through 2007, the average Idaho Power purchases
15 were at an average expense of $217,265,000. Likewise,
16 surplus sales for the period 1993 through 1996 were at an
17 average revenue of $42,060,000. For the period 1997
18 through 2007, the average sales were at an average revenue
19 of $186,711,000.
20 Q.Did you ask Mr. Said to provide you with
21 information as to the decline in PCA earnings stability
22 benefits since the inception of the PCA due to increased
23 prices?
S. KEEN, DI 12
Idaho Power Company
1 A.Yes. Mr. Said has informed me that at the
2 time of the inception of the PCA, the Company, interested
3 parties, and the Commission envisioned power supply
4 expenses would vary $120 million from a high-water scenario
5 to a low-water scenario. With base rates set at the mean
6 of the range and 90 percent sharing by customers, the
7 Company's exposure to adverse water power supply expenses
8 was $6 million (1/2 * $120 million * 10 percent = $6
9 million).
10 Mr. Said also informed me that the range of power
11 supply expenses from a high-water scenario to a low-water
12 scenario is now $290 million. Using the same computation I
13 just presented, the Company's current exposure to adverse
14 water is $14.5 million (1/2 * $290 million * 10 percent) .
15 That means that the risk exposure today is 2.4 times as
16 great as it was at the time the PCA was adopted. This
17 increased dollar amount that is at risk should be
18 recognized in the Company's return on equity in light of
19 FERC market-based rates and how those purchase power costs
20 are calculated and treated in the Idaho PCA mechanism.
21 Q.Does your recommended 11.25 percent return
22 on equity reflect this increased risk to the Company based
23 upon the expanding range of power supply expense
24 possibilities?
S. KEEN, DI 13
Idaho Power Company
1 A.I allowed for the increased volatility in
2 the markets, assuming the current PCA operates as ordered
3 in the Company's most recent general rate case. In doing
4 so, I am assuming there remains a possibility in the future
5 for the PCA mechanism to be sYmmetrical and for both
6 benefit and cost sharing to occur. However, if the PCA
7 requires the shareowners to absorb 10 percent of the costs
8 every year resulting from weather and escalating market
9 prices, my recommended return on equity is too low.
10 Q.If the PCA only results in cost sharing
11 (recovering less than 100 percent of its power supply
12 costs) going forward, as it has for each of the last eight
13 years, is your recommended return sufficient to attract
14 capital at reasonable prices?
15 A.No.
16 3.LGA Implications
17 Q.On January 9, 2007, the Commission issued
18 Order No. 30215 concerning the LGAR in the PCA mechanism.
19 Are you aware of that order?
20 A.Yes.
21 Q.How was that Order received by the financial
22 community?
23 A.It heightened their concern that the Company
24 will be unable to earn its allowed rate of return. A. G.
S. KEEN, DI 14
Idaho Power Company
1 Edwards & Sons, Inc., issued a research report on February
2 16, 2007, stating: "The revised LGAR mechanism and use of
3 the historical test years in rate cases makes it difficult
4 for IDA to earn its allowed ROE in periods of strong
5 customer and rate base growth." A similar report from
6 Wachovia Capital Markets, LLC, on February 15, 2007,
7 states:
8
9
10
11
12
13
14
15
16
17
18
19
With the resulting regulatory lag and
reduced prospects for Idaho Power to
recover its authorized return on
equity, in our view, the decision
reduces confidence in the regulatory
backdrop, especially as the Company
begins to enter a new base-load build
cycle. Moreover, more frequent rate
case filings equate to more cost,
more time, and more uncertainty.
Q.In Order No. 30215, did the Commission
20 discuss the relationship between the load growth adjustment
21 and the return on equity?
22 A.Yes. In that Order, the Commission stated:
23 " (B) ecause this process (the adjustment of load growth
24 recovery) puts the Company at some business and financial
25 risk, it is awarded a commensurate equity return."(Order
26 No. 30215 at p. 10).
27 Q.What does the Commission's statement mean to
28 you?
S. KEEN, DI 15
Idaho Power Company
1 A.It communicates to me that the additional
2 risks borne by the Company due to the denial of load growth
3 costs are to be offset by a commensurate equity return. As
4 the load growth adjustment rate increases, the return on
5 equity component must also increase.
6 Q.On February 28, 2008, the Commission issued
7 Order No. 30508 ordering a change in the Company's base
8 rates. Are you aware of that order?
9 A.Yes.
10 Q.How did that order address the LGAR in the
11 PCA mechanism?
12 A.Order No. 30508 adopted the relevant
13 portions of a settlement stipulation which essentially did
14 two things relative to the LGAR. The parties to the
15 stipulation agreed "to make a good-faith effort to develop
16 a mechanism to adjust or replace the current LGAR to
17 address the costs of serving load growth between rate
18 cases." In addition, for the 2008 PCA, it was decided that
19 "the LGAR will be $62.79 per MWH applied to one-half of the
20 load growth occurring during each month wi thin the PCA
21 year."
22 Q.How was that Order received by the financial
23 community?
S. KEEN, DI 16
Idaho Power Company
1 A. It was viewed as somewhat positive but
2 inadequate. It did not fully settle certain issues, such
3 as the LGAR, in a manner that lessened the impacts on the
4 Company. When the proposed settlement was announced,
5 Standard and Poor's responded by lowering the corporate
6 credit ratings for both Idaho Power and IDACORP from BBB+
7 to BBB. Additionally, both Fitch Ratings and Moody's
8 Investors Service made reference to short-comings in the
9 PCA mechanism and negative impacts from the load growth
10 adjustment as contributing to their negative ratings
11 outlooks later in 2008.
12 RBC Capital Markets also made reference to both the
13 settlement and the load growth issues in their February 14,
14 2008, Equity Research Company Update. Under a column
15 headline of "Disappointing rate case settlement leaves
16 important questions unresolved," they stated:
17 . . . changes to the LGAR mechanism18 and discussions about a forecasted19 test year were tabled pending further
20 discussions. S&P downgraded IDA to
21 BBB from BBB+ dùe to the pending rate22 case outcome and its impact on cash23 flows.
2425 RBC Capital Markets also indicated additional
26 concern about the load growth adjustment mechanism stating:
27 "The current Load Growth Adjustment Mechanism (LGAR) in
28 place essentially punishes IDA for this growth."
S. KEEN, DI 17
Idaho Power Company
1 Q.Does your rate of return recommendation
2 reflect the financial community's concerns regarding the
3 load growth adjustment?
4 A.My rate of return is intended to reflect the
5 Company's current level of risk. At 11.25 percent, the
6 return is higher than the Company's prior authorized rate
7 of return and the changes to load growth-related power
8 costs have contributed to that increase. My recommended
9 rate of return on common equity would need to be increased
10 further if the upcoming load growth adjustment workshops
11 were to result in the Company bearing any greater portion
12 of the costs associated with serving increases in customer
13 load. Likewise, a reduction in, or removal of, the
14 Company's exposure to load growth related costs would allow
15 for a reduction in my recommended return on common equity
16 rate and would be welcomed by the financial community. I
17 would expect a favorable change in this risk category to be
18 noticed in future Company ratings actions and the credit
19 rating is a key component of determining the cost of future
20 debt issuances.
21 4.Water Issues
22 Q.Are there any other water or weather-related
23 risks of the Company that you would like to comment on?
S. KEEN, DI 18
Idaho Power Company
1 A.Yes. Comments from credit rating agencies
2 and analysts have expressed concern about the potential
3 impacts from aquifer recharge and water rights. Reliance
4 on hydro generation in general has come under scrutiny with
5 recent history delivering so many below-normal water years
6 in our region. While it is difficult to quantify potential
7 exposures, the heightened level of discussions and
8 disagreements within the state on these issues have
9 increased the Company's risk profile in the financial
10 community.
11 Q.Has anyone in the financial community tried
12 to quantify the risks relative to hydro exposure for the
13 Company?
14 A.Yes. While all of the rating agencies and
15 much of the equity analyst community have commented on the
16 significant level of risk the Company faces in regard to
17 its high reliance on hydro power, Standard & Poors actually
18 reviewed the hydro issue specifically for Northwest
19 utilities.
20 On January 28, 2008, Standard & Poors issued a
21 report titled "Pacific Northwest Hydrology And Its Impact
22 On Investor-Owned Utilities' Credit Quality." This report
23 took an in-depth look at hydro implications for investor
24 owned utilities in the Northwest. In regard to Idaho Power
S. KEEN, DI 19
Idaho Power Company
1 specifically, Standard & Poor's stated that "Idaho Power's
2 regulatory mechanisms are strong, relative to the other
3 companies in our survey, but not strong enough to overcome
4 significant exposure to the variable flows of the Snake
5 River." They went on to indicate the financial
6 implications to the Company related to this and other
7 factors as described below:
8
9
10
11
12
13
14
15
16
17
18
19
20
21
2223 5.
Despi te having both a PCA and an
update process, the mechanisms have
not been able to fully insulate the
company from the highly variable andgenerally low flow conditions that
have persisted on the Snake River for
the greater part of the past decade.
Idaho Power i s financial performance
has been also hampered by a load
growth adj ustment mechanism that has
resulted in a cash loss on new
customers, and regulatory lag due to
the use of a historical test year for
the non-fuel component of rates.
Relicensing the Hells Canyon Complex
24 Q.Please describe the risks regarding the
25 renewal of federal licenses for the Company's hydroelectric
26 proj ects .
27 A.Idaho Power Company is the only investor-
28 owned electric utility in the United States with 55 percent
29 of its generation derived from hydro generating facilities
30 under normal water conditions. With such a large portion
31 of the Company's generation resources based on hydro
S. KEEN, DI 20
Idaho Power Company
1 facilities, a negative result from efforts to renew the
2 federal licenses of these facilities could have a
3 significant financial impact on the Company and the prices
4 its consumers pay for electricity. Because of its
5 importance, the Company has committed to expend significant
6 financial and human resources to obtain new licenses for
7 its hydro generating capacity from the FERC.
8 Q.What are the associated financial risks to
9 the Company from relicensing its hydro generating capacity?
10 A.Once an application is filed, the time frame
11 to actually receive an order from the FERC is unknown.
12 This uncertainty combined with the potential loss of
13 generation capability due to operational changes, and the
14 magnitude of the financial impact of unknown Protection,
15 Mitigation, and Enhancement ("PM&E") costs are financial
16 risks to the Company.
17 Q.Are there other hydro relicensing-based
18 financial risks considered by the investment community?
19 A.Yes. For any particular generating
20 facility, the worst possible outcome would be the loss of
21 the license to a competing party. Along with the
22 uncertainty as to the eventual receipt of licenses and the
23 costs involved in preparing for the license applications,
24 costs of PM&E related to these projects are also difficult
S. KEEN, DI 21
Idaho Power Company
1 to quantify. The potential financial magnitude of these
2 PM&E and their effect on the Company's low-cost hydro
3 generation resources threaten the financial stability of a
4 company the size of Idaho Power and the ultimate rates it
5 must charge its customers. These amounts will vary between
6 each facility; however, in all cases, they can be
7 significant due to lost generation capacity, generation at
8 a higher cost, and the decreased ability of the Company to
9 time and control water releases.
10 If the Company cannot generate when it is most
11 advantageous for the system, then some of the economic
12 value of the generation has been lost even if the amount of
13 total generation does not change. In addition to the hydro
14 relicensing risk, the Company continually faces significant
15 capital, operating, and other costs relating to compliance
16 with current environmental statutes, rules, and
17 regulations. These costs may be even higher in the future
18 as a result of, among other factors, changes in legislation
19 and enforcement policies and the potential additional
20 requirements imposed in connection with the relicensing of
21 the Company's hydroelectric projects.
22 Q.Please address the risk specifically
23 associated with the Company's relicensing effort before the
24 FERC for the Hells Canyon generating facilities.
S. KEEN, DI 22
Idaho Power Company
1 A.The Hells Canyon generating facilities
2 comprised of Hells Canyon, Oxbow, and Brownlee dams make up
3 67 percent of the Company's hydro generation capacity and
4 40 percent of its total generation capacity. The Hells
5 Canyon license application was filed in July 2003 and
6 accepted by the FERC for filing in December 2003. The FERC
7 process moves at a slow and deliberate pace due to the
8 large number of interested parties involved in evaluating
9 the application, thus the timing of the issuance of a new
10 Hells Canyon facilities license remains uncertain.
11 Historically, FERC has given the Company an annual license
12 renewal (under the existing old license) until the formal
13 new license is issued. It is difficult to predict the
14 ultimate financial impact of the relicense until the new
15 FERC license is issued and all of the relicense conditions
16 are known.
17 Q.Please comment on the relicensing efforts
18 that the Company has already undertaken.
19 A.As part of the FERC relicensing regulations
20 and pursuant to the Federal Power Act, the Company is
21 required to conduct numerous studies and evaluations
22 concerning botanical issues, land management issues,
23 hydraulic issues, flow modeling issues, sedimentary issues,
24 water quality issues, aquatic issues, recreation issues,
S. KEEN, DI 23
Idaho Power Company
1 cultural resource issues, and fish and wildlife issues.
2 Q.How does the Company account for the cost of
3 these proj ects?
4 A.Although Company witness Miller describes
5 this in greater detail in her testimony, Idaho Power books
6 the proj ect costs to CWIP because they are part of the
7 relicensing process pursuant to FERC and state accounting
8 requirements. While the costs are included in CWIP, the
9 Company accrues a capitalization charge commonly referred
10 to as an Allowance for Funds Used during Construction
11 ("AFUDC"). The AFUDC is a non-cash item that represents
12 the cost of related debt and equity financing. The
13 component for AFUDC attributable to borrowed funds is
14 included as a reduction to interest expense, while the
15 equity component is included in other income. The total
16 amount of AFUDC is charged to CWIP.
17 Q.What will occur when the Company receives a
18 new license for the Hells Canyon facilities?
19 A.The amounts in CWIP will be transferred to
20 plant in service and the accumulation of AFUDC will cease.
21 The result will be a large increase in rate base with
22 earnings of the Company declining since there will be no
23 AFUDC. Because this is a relicense of an existing hydro
24 facili ty, there will be no increase (if not a decrease due
s. KEEN, DI 24
Idaho Power Company
1 to operational changes) in the generation of power and thus
2 no increase in sales revenues. The financial industry sees
3 this as a risk that confronts the Company which can be
4 summarized as follows: upon receipt of a relicense, (1)
5 the Company's earnings will go down (no AFUDC) , (2) the
6 Company's rate base will go up (transfer from CWIP) , and
7 (3) no additional sales revenues (same plant but new
8 license). For the. period of time the new rate base is
9 under review by the Commission, the Company will earn no
10 return on roughly $100 million of investment. This lag
11 combined with the potential for some disallowance is a
12 significant risk factor.
13 Q.The Company is suggesting certain changes in
14 the methodology surrounding AFUDC regarding CWIP balances
15 for relicensing. If adopted, will this remove the risk
16 that you refer to above?
17 A.No. The recommended change will keep this
18 risk factor from continuing to grow but it does not fully
19 remove the exposures described above. If accepted by the
20 Commission, the recommendation by Company witness Miller
21 will keep the CWIP balance related to relicensing from
22 growing but it does not deal with the large accumulation of
23 costs already in CWIP that will need to one day be
24 transferred to rate base. As of December 31,2007, that
S. KEEN, DI 25
Idaho Power Company
1 balance was $95.6 Million.
2 6.QF Concerns
3 Q.Does the regulatory treatment of energy
4 purchases the Company makes from PURPA QFs increase the
5 financial risk to Idaho Power?
6 A.Yes. The regulatory treatment of QF
7 expenditures provides for a one-for-one recovery of dollars
8 expended, but does not provide for a return to compensate
9 the Company for this activity. The Company is, in effect,
10 buying and selling energy pursuant to a legal mandate,
11 without any compensation for providing this service.
12 Simplistically, this regulatory treatment is similar to
13 requiring a person operating a business to buy a product at
14 the same price it must be sold. The mere dollar-for-dollar
15 recovery of QF expenditures, but no return for the use of
16 the Company's balance sheet and liquidity in managing QF
17 programs, is viewed as a significant risk by the rating
18 agencies. They are not making a judgment related to the
19 appropriateness of QF energy purchase programs, but merely
20 pointing out the cost of the financial risk (s) arising from
21 a QF transaction, and that this risk should be reflected in
22 a higher return on equity to credit the Company for its QF
23 contracts.
S. KEEN, DI 26
Idaho Power Company
1 Q.Has the Commission previously considered a
2 proposal to compensate the Company for its management of QF
3 programs?
4 A.Yes. In determining the appropriate rates
5 to be paid for power and energy sold to Idaho Power
6 pursuant to section 210 of the PURPA Act of 1978, the
7 Commission through Order 18190 at page 21 indicated:
8 In another context, Staff witness
9 Drummond proposed that Idaho Power be
10 given a management fee amounting to11 five percent of the gross paYments
12 made to CSPP's (QFs). The Commission13 wiii do all in its power to encourage
14 Idaho Power to manage such proj ects15 in an orderly fashion. Orderly
16 management includes adequate staffing17 and clear lines of authority among18 personnel assigned to deal with19 CSPPs; good faith negotiating of20 contracts and expeditious processing21 of worthy applications; and, above22 al 1 , a showing that the Company has23 integrated cogeneration and small24 power resources into its own25 planning, construction and financing
26 programs. When orderly management is
27 demonstrated, the Commission will28 reconsider the question of an
29 appropriate management fee or an30 equity adjustment.
31
32 According to Company witness Said, the current
33 expected normalized cost for QF purchases is approximately
34 $63.3 million. Utilizing a five percent management fee, as
35 recommended above by Staff witness Drummond, on these
36 normalized QF costs would result in a paYment to the
S. KEEN, DI 27
Idaho Power Company
1 Company of approximately $3.165 million. Mr. Said
2 evaluated the impact of an additional $3.165 million of
3 required revenues and approximated that the increase would
4 correlate to an additional 20 basis points of ROE. That
5 increase would bring my recommended ROE to 11.45 percent.
6 Q.Do the rating agencies recognize the
7 financial costs of QF-related transactions?
8 A.Yes. Like other electric utilities, when
9 the Company adds to its rate base, it must use some portion
10 of shareholder equity to fund the investment. The Company
11 must maintain its proportion of equity to debt above a
12 certain level as it continues this investment process. If
13 it does not, the debt level increases and the Company will
14 face the threat of a bond rating downgrade. Conversely,
15 when the Company enters into a QF contract for purchased
16 power, an obligation not reflected in its financial
17 statements, an increase in equity is needed to maintain
18 credit quality. Unless an equity component is provided to
19 offset the debt-like obligation of long-term QF purchase
20 power contracts, the Company faces off-balance sheet
21 financial risk. For financial commitments that do not
22 appear on the balance sheet, credit rating analysts impute
23 the debt and interest equivalents on the financial
24 statements of the Company to achieve a more accurate
S. KEEN, DI 28
Idaho Power Company
1 picture of the risk associated with their investment. The
2 added equity needed to offset this imputed debt and
3 interest represents the effect that long-term purchased
4 power commitments have on the cost of capital. Any
5 increase in the long-term obligation of a utility related
6 to its capacity and energy resources will have to be backed
7 by an appropriate amount of equity in the eyes of the
8 investment community.
9 In reviewing its evaluation of the credit
10 implications of QF-related expenditures, S&P in May of
11 2003, noted that such agreements are "debt-like in nature"
12 and that the increased financial risk must be considered in
13 evaluating a utility's credit risks.
14 Standard & Poor's Ratings Services15 views electric utility purchased-
16 power agreements (PPA) as debt-like17 in nature, and has historically18 capitalized these obligations on a19 sliding scale known as a "risk20 spectrum." Standard & Poor's applies21 a 0% to 100% "risk factor" to the net
22 present value (NPV) of the PPA
23 capacity paYments, and designates24 this amount as the debt equivalent.
2526 * * *
2728 Standard & Poor's evaluates the29 benefits and risks of purchased power30 by adjusting a purchasing utility's31 reported financial statements to
32 allow for more meaningful comparisons33 with utilities that build generation.34 Utilities that build typically
S. KEEN, DI 29
Idaho Power Company
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
finance construction with a mix of
debt and equity. A utility that
leases a power plant has entered into
a debt transaction for that facility;a capi tal lease appears on the
utility's balance sheet as debt. A
PPA is a similar fixed commitment.
When a utility enters into a long-
term PPA with a fixed-cost component,
it takes on financial risk.
Furthermore, utili ties are typically
not financially compensated for the
risks they assume in purchasing
power, as purchased power is usually
recovered dollar-for-dollar as an
operating expense.
7.Growth and Timely Cost Recovery
19 Q.Please describe the risks relative to the
20 Company's ability to recover significant capital investment
21 required for present and growing electrical requirements.
22 A.As the Company's generation and transmission
23 systems age and customer electrical requirements increase,
24 additional investment is required to meet reliability
25 standards and the additional demand on its electrical
26 infrastructure. The Company's latest forecast proj ects a
27 construction budget of between $270 to $290 million in 2008
28 and an approximate $900 million of new construction
29 expenditures over the three-year period of 2008 through
30 2010. The $900 million estimate excludes any estimated
31 expenditures related to certain large transmission projects
32 or costs associated with a base load combined cycle
s. KEEN, DI 30
Idaho Power Company
1 combustion turbine that could increase construction costs
2 during this time frame. Construction investments of this
3 magnitude introduce two elements of risk: first, the
4 ability of the Company to attract the required capital and,
5 secondly, the recovery of these investments is on a
6 deferred basis and subj ect to the regulatory process.
7 Q.
8 authorized
9 A.
10 equity has
11 years.
12 Q.
Has the Company been able to earn its
return on equity during recent years?
No. In fact, the Company's actual return on
been less than 9 percent for the last five
What has prevented the Company from earning
13 its authorized or allowed return on equity?
14 A.I have previously addressed in my testimony
15 several issues which I believe adversely impact the
16 Company's ability to earn its authorized return. However,
17 in my opinion, the reliance on historical test year
18 information is a primary reason the Company fails to earn
19 its authorized or allowed return on equity at this time. I
20 believe this opinion is universally held by financial
21 analysts that follow Idaho Power/IDACORP. Idaho Power is
22 in a consistent position of always recovering its costs on
23 a historical basis when its costs are constantly increasing
24 on a prospective basis. As a result, there is a consistent
S. KEEN, DI 31
Idaho Power Company
1 recovery lag. As long as Idaho Power is building to meet
2 future demands while collecting rates based in the past, it
3 can never "catch-up."
4 Q.What effect does growth have on the use of
5 historical data?
6 A.Growth inherently worsens the effects.
7 Operation & Maintenance ("O&M") expenses typically rise
8 faster than inflation as new facilities and personnel are
9 added to meet growing customer demands. Yet recovery is
10 based on lower historical costs and staffing levels from a
11 prior period. Likewise, the allowed rate of return is
12 applied to a rate base from a prior historical period and
13 new plant additions suffer some period of zero percent
14 return awaiting eventual rate base treatment.
15 8.Declining Credit Ratings
16 Q.What is the status of Idaho Power Company's
17 credit ratings?
S. KEEN, DI 32
Idaho Power Company
1 A.Idaho Power Company's credit ratings as of
2 June 20, 2008, are as follows:
Corporate Credit BBB Baa 1 None
Rating
Senior Secured Debt A-A3 A-
Senior Unsecured BBB-Baa 1 BBB+
Debt (prelim)
Short-Term Tax-BBB/A-2 Baa 1/VMIG-2 None
Exempt Debt
Commercial Paper A-2 P-2 F-2
Credit Facility None Baa 1 None
Rating Outlook Stable Negative Negative
3
4 Q.Standard & Poor's downgraded the Company's
5 credit rating in January of 2008. What prompted this
6 action?
7 A.Standard and Poor's lowered the corporate
8 credit ratings for both Idaho Power and IDACORP from BBB+
9 to BBB, citing cash flow concerns, the proposed general
10 rate settlement, and specifically mentioning the impacts of
11 load growth. Their research update on January 31, 2008,
12 stated:
13 The rating action was driven by a14 gradual deterioration of cash flow15 coverage and last week i s proposed16 general rate case settlement, which17 does not sufficiently address long-18 term ratemaking issues tied to rising19 costs and load growth pressures. Over20 time, average credit metrics have21 deteriorated, and the company has22 been unable to stabilize returns and23 cash flow with existing rate
24 mechanisms. The proposed settlement
S. KEEN, DI 33
Idaho Power Company
1
2
3
4
5
6
7
8
9
calls for an average 5.2% rate
increase but does not settle some
important, policy-related issues in
the case, such as the use of a
forecasted test year or the
appropriate level of the load growth
adjustment credit.
Q.Have there been other ratings actions in
10 2008?
11 A.Yes. Both Fitch Ratings and Moody's
12 Investors Service recently changed their ratings outlooks
13 for both Idaho Power and IDACORP to "negative" from
14 "stable" on March 20, 2008, and June 03, 2008,
15 respectively.
16 Q.Do you believe that the current credit
17 ratings of Idaho Power Company are adequate?
18 A.Other utilities with the same credit ratings
19 as Idaho Power Company are able to raise capital in today's
20 markets. However, these new debt/bond issues are at a
21 higher cost than if these utilities had a higher credit
22 rating (the higher the credit rating, the lower the cost) .
23 This results in passing on higher interest costs to
24 customers over the life of the bonds.
25 One large threat to Idaho Power Company's current
26 ratings is unforeseen risk. Should an unforeseen event
27 cause Idaho Power Company's short-term credit ratings to be
28 lowered, Idaho Power Company would no longer be able to
S. KEEN, DI 34
Idaho Power Company
1 issue commercial paper. This would limit the options Idaho
2 POwer Company has available to meet on-going cash
3 requirements, such as funding capital improvements and
4 paying for deviations in power supply costs, and would
5 likely result in higher interest costs to the customer.
6 The unforeseen risk has a potentially greater impact when a
7 company is closer to the bottom of what is considered
8 "investment grade."
9 Q.What is the lowest rating that is considered
10 investment grade?
11 A.For Standard & Poors that rating is BBB-.
12 Idaho Power's corporate credit rating is currently one step
13 above that bottom rating. Its senior unsecured debt rating
14 is actually at that bottom level and its secured debt
15 rating is currently at A-. A significant concern for me,
16 as the officer primarily responsible for providing the
17 Company's capital, is how close Idaho Power is to the
18 bottom of investment grade status. The concern is only
19 heightened by the need to raise increasing amounts of
20 capital in the near future for some fundamental
21 infrastructure improvements. The last time Idaho Power
22 faced this situation we carried much better credit ratings
23 than today.
S. KEEN, DI 35
Idaho Power Company
1 9.Reasonable Actual Results
2 Q.Why do you think the rating agencies have
3 taken their recent actions to reduce Idaho Power's credit
4 ratings?
5 A.I think the single largest contributor is
6 the fact that actual results have varied so significantly
7 from any type of expected return. Idaho Power's last
8 return on equity arising from the settlement of the 2005
9 general rate case was 10.6 percent and while several rate
10 actions have been completed since that time, the
11 approximate expectation for a regulated return has stayed
12 very close to that figure. Yet in actuality, the realized
13 returns have been far below that figure, not reaching
14 double digits since 2002.
15 Q.Has the Company been able to earn its
16 allowed return on equity in recent years?
17 A.No. During the years 2004 and 2005, Idaho
18 Power's authorized return on equity was 10.25 percent. In
19 those years the Company earned a return on equity of 7.2
20 percent and 7.7 percent, respectively. In 2006, Idaho
21 Power's actual return on equity was higher but still barely
22 over 9 percent in a year that enjoyed good hydro
23 conditions. In 2007, Idaho Power only earned an actual
24 return on equity of 6. 9 percent. In fact, the actual
s. KEEN, DI 36
Idaho Power Company
1 return on equity for the Company has not been above 10
2 percent since 2002 when the Company earned 10.9 percent
3 against an allowed return on equity of 11.5 percent.
4 Q.What drives this continual earnings short-
5 fall?
6 A.I believe the primary contributors to be the
7 effects of regulatory lag and a combination of negative
8 impacts arising out of variability in hydroelectric
9 generation. Although I have addressed several other risk
10 factors in my testimony that also contribute to the short-
11 fall, I would like to emphasize that the financial
12 community and the recent ratings actions are looking very
13 directly at the actual results of Idaho Power's regulatory
14 efforts. They expect realized rates of return to be near
15 allowed levels, or at least occurring at or above allowed
16 levels as often as they fall below them. The financial
17 community is also certainly looking for more consistency in
18 cash flows.
19 CAITAL STRUCTUR
20 Q.Would you please describe Exhibit No.27?
21 A.Exhibit No. 27 details the calculation of
22 the Idaho Power Company capital structure for long-term
23 debt, the common equity balance resulting from the
24 Company's forecasted year-end 2008 capital structure as
s. KEEN, DI 37
Idaho Power Company
1 provided to me by Ms. Lori Smith, and the resulting overall
2 rate of return that I am recommending.
3 Q.The capital structure presented on Exhibit
4 No. 27 incorporates changes to the Company's financial
5 reporting of its capital structure. Could you please
6 discuss the rationale for the variance?
7 A.For financial reporting purposes, the
8 American Falls Bond Guarantee and the Milner Dam Note
9 Guarantee are included in the long-term debt portion of the
10 capital structure. For ratemaking purposes, the interest
11 costs associated with both the American Falls and the
12 Milner debt securities are treated as O&M expenses. Even
13 with these exclusions, the capital structure presented in
14 my Exhibit No. 27 is reasonable in light of industry and
15 rating agency criteria.
16 Q.Would you please comment on Exhibi t No.2 8?
17 A.Exhibit No. 28 details the calculation of
18 the cost of debt used in the estimated year-end 2008
19 capital structure. The cost of debt is 5.927 percent.
20 Please note that one forecasted bond issuance of $125
21 million appears on line 12. The $125 million issue will be
22 used to redeem outstanding short-term commercial paper as
23 well as financing ongoing capital expenditures. The
24 interest rate for this issuance was derived by averaging
S. KEEN, DI 38
Idaho Power Company
1 quotes for ten-year First Mortgage bonds from three
2 inve~tment banks as of April 7, 2008. In addition, the
3 Company assumed that the Sweetwater and Humboldt County
4 bonds would be remarketed in a fixed, ten-year mode before
5 the end of the year. Idaho Power averaged quotes from two
6 investment banks for similarly rated bonds. These rates
7 were estimated at the time the overall cost of capital
8 rates were needed to prepare a rate case filing.
9 Q.Does the Company utilize variable rate
10 securities in its long-term capitalization?
11 A.Yes. The Company currently utilizes one
12 variable rate security in its long-term capitalization.
13 The Port of Morrow (Boardman) Pollution Control Revenue
14 Bonds Variable Rate Series 2000 ($4.36 million) is listed
15 on line 15 of the exhibit.
16 Q.Would you please describe the variable rate
17 nature of this pollution control bond?
18 A.This variable rate pollution control bond,
19 although considered a long-term security, has features that
20 allow the Company to take advantage of rates applicable to
21 short-term securities. The interest rate is determined the
22 first day of a weekly period by a Remarketing Agent. The
23 Remarketing Agent examines tax-exempt obligations
24 comparable to the Boardman Variable Bonds known to have
S. KEEN, DI 39
Idaho Power Company
1 been priced or traded under the then-prevailing market
2 conditions and finds the lowest rate which would enable
3 sale of the Boardman Variable Rate Bonds.
4 Q.How did you determine what rate to use for
5 the Boardman Variable Rate Bond?
6 A.I used the methodology authorized in the
7 2003 rate case (Order No. 29505) that utilizes the average
8 rates observed for this specific bond over the last five
9 years.
10 Q.Please comment on the structure and rates
11 for the Humboldt and Sweetwater County bonds and how they
12 differ from the last rate case.
13 A.In the last rate case, the Sweetwater and
14 Humboldt County bonds were in an auction rate mode that
15 reset periodically (every seven days for Sweetwater and
16 every 35 days for Humboldt). The mode had produced short-
17 term rates for the long-dated securities even lower than
18 the Boardman Variable rate bonds and these benefits have
19 been passed on to the customer through a lower overall cost
20 of capital structure since 2003. However, in February of
21 2008, the entire auction rate market began to deteriorate
22 rapidly based on overall credit worries in the market,
23 specifically around the mono-line insurers which guarantee
24 a large portion of the debt in this market. Both the
S. KEEN, DI 40
Idaho Power Company
1 Sweetwater and Humboldt bonds began to experience much
2 higher reset rates through the auction process (e. g . ,
3 between seven - ten percent for Sweetwater). The Company
4 arranged for a short-term loan and used the proceeds to
5 purchase these bonds and hold them in Idaho Power's name.
6 This is a temporary solution, and the Company expects to
7 remarket these bonds in a longer term fixed mode before the
8 short-term loan expires in March of 2009.
9 OVERAL COST OF CAITAL
10 Q.What is the overall cost of capital for
11 Idaho Power Company?
12 A.As shown on Exhibi t No. 27, us ing the
13 projected year-end 2008 capital structure provided to me by
14 Ms. Smith, the cost of capital presented in my testimony,
15 and incorporating the 11.25 percent cost of equity, the
16 resultant overall cost of capital for Idaho Power Company
17 is 8.55 percent.
18 Q.Does this conclude your direct testimony in
19 this case?
20 A.Yes, it does.
S. KEEN, DI 41
Idaho Power Company