20110602Steven Keen Direct, Exhibits.pdf

RECEIVED
20fl JUN -I PH 2: 42
!ITIt',v f '-
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPANY FOR
AUTHORITY TO INCREASE ITS RATES
AND CHARGES FOR ELECTRIC SERVICE
TO ITS CUSTOMERS IN THE STATE OF
IDAHO.
CASE NO. IPC-E-ll-08
I DAHO POWER COMPANY
DIRECT TESTIMONY
OF
STEVEN R. KEEN
1 Q.Please state your name, address, and present
2 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 ("Idaho Power" or
6 "Company") as Vice President, Finance and Treasurer.
7 Q. What is your educational background?
8 A. I graduated with high honors in 1981 from
9 Idaho State Uni versi ty, receiving a Bachelor of Business
10 Administration degree in Accounting. I have also attended
11 numerous seminars and conferences on accounting and finance
12 issues related to the utility industry. I am a Certified
13 Public Accountant licensed in the state of Idaho.
14 Q.Please describe your business experience with
15 Idaho Power.
16 A.I joined Idaho Power in September 1982 in the
17 Property Accounting Department. In March 1983, I
18 transferred to the Tax Department as a Tax Accountant.
19 From that time through December 1998, I advanced through
20 various positions in the Tax Department, including Property
21 Tax Representative, Tax Research Coordinator, and, finally,
22 Corporate Tax Director. In January 1999, I became
23 President of IDACORP Financial Services. In June of 2006,
24 I accepted the position of Vice President and Treasurer of
25 Idaho Power and IDACORP, Inc. ("IDACORP") and on June 1,
KEEN, DI 1
Idaho Power Company
1 2010, I became Vice President, Finance and Treasurer of
2 Idaho Power and IDACORP.
3 In the course of my duties with Idaho Power, I
4 presented testimony in Idaho Power's last two general rate
5 cases before the Idaho Public Utilities Commission
6 ("Commission"), Case Nos. IPC-E-07-0S and IPC-E-OS- 10,
7 respectively. I have also presented testimony in a general
S rate case before the Public Utility Commission of Oregon
9 ("OPUC"). In addition, I have presented tax testimony to
10 the Internal Revenue Service as well as tax and/or
11 capi talization rate testimony to the Departments of Revenue
12 and Taxation for Idaho, Oregon, Wyoming, and Nevada.
13 Q.What are your duties as Vice President,
14 Finance and Treasurer of Idaho Power as they relate to this
15 proceeding?
16 A.I oversee the direct financial planning,
17 procurement, and investment of funds for Idaho Power, as
1S well as supervise corporate liquidity management. I also
19 have oversight and responsibility for our financial
20 reporting, both internal and external, and our investor
21 relations function.
22 My duties and responsibilities include various
23 aspects of all the Company's financings and other financial
24 matters. With respect to long-term financings, sale of
25 bonds and sale of equity, my duties include development of
KEEN, DI 2
Idaho Power Company
1 financial plans with senior officers, meeting with
2 representatives of investment banking firms that are
3 interested in underwriting Idaho Power securities,
4 discussions with credit rating agencies, assisting in
5 preparation of financial material (including Registration
6 Statements filed with the Securities and Exchange
7 Commission), representing the Company at informational
8 meetings for investment banking firms, reviewing
9 information relative to the Company's financings, and
10 recommending disposition of net proceeds. With respect to
11 short-term financings, these duties and responsibilities
12 include negotiation of lines of credit with commercial
13 banks and overseeing the sale of commercial paper.
14 Q.Do your responsibilities include communicating
15 with members of the financial community?
16 A.Yes. I am in continuous contact with
1 7 individuals representing investment and commercial banking
18 firms, credit rating agencies, insurance companies,
19 institutional investment firms, and other organizations
20 interested in publicly traded securities, all of whom
2 1 actively follow IDACORP and Idaho Power. Along with the
22 Company's Chief Financial Officer and the Director of
23 Investor Relations, my responsibilities include keeping
24 these representatives of the financial community informed
25 of the Company's financial condition, arranging meetings
KEEN, DI 3
Idaho Power Company
1 with these individuals and Idaho Power's senior executive
2 management, and visiting with financial representatives in
3 their respective offices. Some of these members of the
4 investment community have followed the electric utility
5 industry for an extended period of time and have a great
6 deal of expertise in the financial problems and prospects
7 of utili ties.
S Through my continuous contact with the financial
9 community and review of investment banking analytical
10 reports and articles issued by these firms and the rating
11 agencies, I am able to keep informed on trends, interest
12 rates, financing costs, security ratings, and other
13 financial developments in the public utility industry.
14 Q.Are you a member of any professional societies
15 or associations?
16 A.Yes. I am a current member and past board
17 president of the Idaho Society of Certified Public
1S Accountants. I am a current member of and past council
19 member of the American Institute of Certified Public
20 Accountants. I am a current member and past board chairman
21 of the Associated Taxpayers of Idaho. I am the current
22 board chairman of the Idaho Tax Foundation. I am a member
23 of the Idaho Association for Financial Professionals.
24 Also, in 200S, I was appointed by Idaho Governor Otter to
25
KEEN, DI 4
Idaho Power Company
1 the Board of Commissioners for the Idaho Housing and
2 Finance Association.
3 In addition to the above acti vi ties, I attend
4 numerous conferences and seminars of these and other
5 utility professional groups, such as the Edison Electric
6 Insti tute, on a regular basis. Through participation in
7 these events, I gain additional information and insights
8 into the financial developments affecting Idaho Power, as
9 well as the electric utility industry.
10 Q.What is the purpose of your testimony in this
11 proceeding?
12 A.I am sponsoring testimony discussing financial
13 risk factors generally, risk factors that are unique to
14 Idaho Power which justify the return on equity ("ROE")
15 point estimate supported in the Direct Testimony of Idaho
16 Power's ROE expert Dr. William E. Avera as the minimum
17 acceptable ROE for Idaho Power, the use of a forecasted
18 year-end 2011 capital structure, the embedded cost of long-
19 term debt and the resultant overall cost of capital used to
20 compute the Company's revenue requirement.
21 Q.What exhibits are you sponsoring?
22 A.I am sponsoring Exhibit Nos. 11-13.
23 I . COST OF EQUITY POINT ESTIMATE
24 Q.What ROE is the Company requesting in this
25 proceeding?
KEEN, DI 5
Idaho Power Company
1 A.The Company requests 10.5 percent as the point
2 estimate to be used for cost of equity.
3 Q.Does that point estimate align with the
4 recommendations made by the Company's outside expert
5 regarding the Company's cost of capital?
6 A.Yes. The recommendation is within the range
7 suggested by Dr. Avera but at the low end of his "bare
8 bones" recommended range. The Company's recommendation is
9 submitted with the belief that it is the minimum required
10 ROE necessary to not weaken the ability to attract capital
11 at reasonable rates in today's financial markets.
12 Q.How did you arrive at your recommendation?
13 A.While I feel my later discussion of risk
14 factors justifies a ROE in excess of 10.5 percent, as
15 supported by Dr. Avera, I have taken into account the
16 general level of economic conditions in Idaho Power's
17 service terri tory and selected the lowest end of the
18 recommended range. The Commission has signaled in recent
19 orders that it is sensitive to the burdens and impacts the
20 current economic conditions have placed upon the Company's
21 service territory. Idaho Power has heard that message,
22 and, correspondingly, has adopted a conservative approach
23 in all areas of this rate filing. In that light, the
24 Company is seeking here a minimum level of ROE at 10.5
25 percent.
KEEN, DI 6
Idaho Power Company
1 Q.Did you consider the recent ROE decisions in
2 the Idaho jurisdiction?
3 A.Yes. Two cases that were reviewed in regard
4 to this filing were the Avista Corporation's ("Avista")
5 general rate case which was settled in October of 2010 and
6 the Rocky Mountain Power general rate case reconsideration
7 order issued in April 2011. In the Avista case, a
8 settlement agreement was reached, and both the settlement
9 and the Commission's final order approving the settlement
10 were silent as to an adj ustment to Avista's authorized ROE.
11 Order No. 32070, Case No. AVU-E-10-01. Prior to this
12 settlement, in 2009, Avista had received a 10.5 percent ROE
13 in the Idaho jurisdiction, which equaled Idaho Power's
14 then-current authorized ROE.
15 The recent ROE of 9.9 percent that was set in the
16 decision for PacifiCorp's, d/b/a Rocky Mountain Power, was
17 notable and somewhat concerning. Reconsideration Order No.
18 32224, PAC-E-10-07. With the rate set below 10 percent,
19 the initial reaction by the financial community was that it
20 seemed very low and could signal a move toward a less
21 favorable regulatory environment in Idaho. However, I
22 think Rocky Mountain Power' s position as a utility can be
23 distinguished from Idaho Power's, thus justifying a
24 difference in authorized ROE.
25
KEEN, DI 7
Idaho Power Company
1 Q.Please discuss the differences between Rocky
2 Mountain Power and Idaho Power that justify a difference
3 in authorized ROE
4 A.Certainly. First, you must consider that Rocky
5 Mountain Power's parent company, PacifiCorp, is a larger,
6 mul tij urisdictional utility. It also carries a higher
7 overall corporate credit rating than Idaho Power with
8 Standard & Poor's, although Moody's rates Rocky Mountain
9 Power and Idaho Power equally. Looking at the Standard &
10 Poor's ratings publication on April 30, 2011, PacifiCorp
11 carries an A- corporate credit rating compared to Idaho
12 Power's BBB. This is a full two step advantage and conveys
13 that Idaho Power is viewed as having more risk relative to
14 PacifiCorp by Standard & Poor's. Second, the fact that
15 PacifiCorp is owned by MidAmerican Energy Holdings Co.,
16 which is privately held and majority owned by Berkshire
17 Hathaway (which carries an AA+ corporate credit rating),
18 was also pointed out in the Standard & Poor's document.
19 Unlike PacifiCorp, Idaho Power does not have a stronger
20 parent company to look to in times of financial distress.
21 In fact, IDACORP's credit metrics are slightly lower than
22 Idaho Power's.
23 As you will see later in my testimony, recent
24 regulatory decisions in the Idaho jurisdiction affecting
25 Idaho Power have been viewed as being credi t supportive and
KEEN, DI 8
Idaho Power Company
1 have helped stop a general decline in Idaho Power's credit
2 ratings. While a lower ROE was recently granted to one
3 utili ty in the Idaho jurisdiction, the facts and
4 circumstances surrounding that single decision do not
5 necessarily extend to Idaho Power. Considering the
6 differences in size and credit quality, there is certainly
7 evidence to support that Idaho Power should be granted an
8 ROE higher than the recent decision for PacifiCorp's
9 subsidiary, Rocky Mountain Power, in Idaho. My recommended
10 10.5 percent ROE is justifiably higher than the Rocky
11 Mountain Power decision, in line with the previous Avista
12 decision, and at the lower end of the range currently
13 recommended by Dr. Avera.
14 II . RISK FACTORS
15 Q.Could you briefly outline the risks
16 confronting the Company that form the basis for your
17 recommendation of a 10.5 percent ROE as the minimum
18 acceptable authorized return?
19 A.Yes. I will summarize them here and discuss
20 them in greater detail later in my testimony. I believe
21 that, at a minimum, a 10.5 percent ROE is required to
22 properly account for the risks confronting Idaho Power for
23 the following reasons:
24
25
KEEN, DI 9
Idaho Power Company
1 (1 )The general decline in credit quality
2 of the Company and its impact on meeting ongoing capital
3 funding requirements;
4 (2 )The difficulty in earning an actual
5 return on capital on a sustained basis that is near the
6 Company's authorized rate of return;
7 (3 )The perceived risk in the financial
8 communi ty associated with the variability of the Company's
9 hydroelectric generating base and risks associated with
10 variances in the weather;
11 ( 4 )The renewal of federal licenses for the
12 Company's hydroelectric proj ects, primarily the Hells
13 Canyon Complex, which provides on average 40 percent of the
14 Company's total generating capacity, and particularly the
15 cost of relicensing that proj ect;
16 (5 )The impact of large and growing
17 Qualifying Facility ("QF") related expenditures;
18 (6)The difficulty of the Company to
19 recover on a timely basis the significant capital
20 investment required for present and growing electrical
21 requirements and service reliability for its customers; and
22 (7 )The Company's small size and
23 concentrated regulatory risk (i.e., 95 percent of our
24 business is in Idaho).
25
KEEN, DI 10
Idaho Power Company
1 Q.Are some of these risk conditions the same
2 risk conditions that have been raised in past Idaho Power
3 rate proceedings?
4 A.Yes. Most of these risks have existed with
5 the Company over the years but their impacts and
6 significance can change (and have changed) and I attempt to
7 address those implications here.
S Q.Are there other risks, less specific to Idaho
9 Power, that also impact your recommendation?
10 A.Yes. There are general financial risks such
11 as increased volatility in the financial markets and what I
12 view as a heightened sensi ti vi ty to risk exposure that has
13 evol ved since the United States housing market began
14 experiencing problems in 2007, and which was magnified by
15 the very significant disruption in the financial markets
16 that occurred in 200S. There are also industry specific
17 risks, such as unknown costs relative to carbon emissions,
lS an industry-wide need for infrastructure improvements, and
19 increased capital investment, as well as inflationary
20 pressures that increase costs of both operating expenses
21 and capital outlays. While the financial disruption has
22 mitigated somewhat, particularly in relation to corporate
23 finance in the past year, the improvement has been met with
24 interest rate uncertainty and a growing fear that future
25 borrowing costs could rise dramatically. Recently, the
KEEN, DI 11
Idaho Power Company
1 Federal Reserve has indicated that it may be less active in
2 its effort to keep interest rates low, which creates
3 expectations for rising debt costs in the near future. All
4 of these factors combine to make a challenging environment
5 in which the Company must compete with others in the
6 electric utility industry, for both resources and capital,
7 to serve the needs of its customers and shareowners. While
S I do not intend to elaborate further on more general risks,
9 they are factors worthy of note that point to increased
10 risks for the Company.
11 1.Declininq Credit Ra tinqs .
12 Q.What is the status of Idaho Power's credit
13 ratings?
14 A.Idaho Power's credit ratings as of March 31,
15 2011, are as follows:
Corporate Credit Rating BBB Baa 1
Senior Secured Debt A-A2
Senior Unsecured Debt BBB Baa 1
Short-Term Tax-Exempt Debt BBB/A-2 Baa 1
Commercial Paper A-2 P-2
Credit Facility None Baa 1
Rating Outlook Stable Stable
16 Q.Standard & Poor's Corporation ("S&P")
1 7 downgraded the Company's credit rating in January of 200S.
1S What prompted this action?
KEEN, DI 12
Idaho Power Company
1 A.S&P lowered the corporate credit ratings for
2 both Idaho Power and IDACORP from BBB+ to BBB, citing cash
3 flow concerns, the then-current proposed general rate
4 settlement in Case No. IPC-E-07-0S, and specifically
5 mentioning the impacts of declining load growth. S&P's
6 research update on January 31, 200S, stated:
7 The rating action was driven by aS gradual deterioration of cash flow9 coverage and last week's proposed10 general rate case settlement, which11 does not sufficiently address long-12 term ratemaking issues tied to13 rising costs and load growth14 pressures. Over time, average credit15 metrics have deteriorated, and the16 company has been unable to stabilize17 returns and cash flow with existing1S rate mechanisms. The proposed19 settlement calls for an average 5.220 percent rate increase but does not21 settle some important, policy-22 related issues in the case, such as23 the use of a forecasted test year or24 the appropriate level of the load25 growth adj ustment credit.
26 Q.Have there been other recent rating agency
27 actions?
2S A.Yes. In the intervening time between the S&P
29 action and this filing, both Fitch Ratings and Moody's
30 Investors Services, Inc. ("Moody's") changed their ratings
31 outlooks for both Idaho Power and IDACORP from "stable" to
32 "negative" in 200S then back to "stable" in 2010. On July
33 S, 2009, Moody's reaffirmed their negative outlook on Idaho
KEEN, DI 13
Idaho Power Company
1 Power's corporate credit rating and commented regarding
2 their continued concern:
3 Key concerns continue to focus on4 hydro condi tions gi ven the
5 persistence of drought conditions
6 during the past decade and higher7 than historical average planned
8 capi tal spending despi te recent9 steps to curtail or delay certain10 proj ects. Moreover, while key credit11 metrics are beginning to trend12 upward, further strengthening of13 cash flow and continued conservative14 financing strategies are necessary15 to allay our concerns and improve16 the company's weak position within17 the Baal rating category. To18 accomplish this, continued support19 from state regulators in anticipated20 future general rate cases will also21 remain an important rating driver.
22 On March 30, 2010, Moody's revised its outlook for
23 both Idaho Power and IDACORP back to stable with the
24 following comments in a press release:
25 The change to a stable rating26 outlook for IPC reflects the
27 company's strengthened financial and28 operating profile resulting from a29 series of regulatory decisions
30 during 2009 and 2010, which evidence31 a strong support for credit quality.
32 On the same date, in its updated credit opinion for
33 Idaho Power, Moody's cited the following in regard to how a
34 supporti ve regulatory environment bodes well for credit
35 quality:
KEEN, DI 14
Idaho Power Company
1
2
3
4
5
6
7
8
9
10
11
12
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14
15
16
Favorable regulatory practices inIdaho, which is IPC's principaljurisdiction, include 1) a relatively
swift seven month statutory period
governing rate cases; 2) frequent
decisions based on settlements instead
of litigated proceedings; 3) reasonable
allowed returns on equity; 4) reliance
on an assortment of cost tracking andadjustment mechanisms, periodic
utilization of single-issue rate cases
and partially forecast test years to
avoid undue rate lag; and 5) pre-
approval of future rate treatment for
certain capital investments allowed
under state law.
17 Q.Does this indicate that credit ratings of
18 Idaho Power are now on an upward path?
19 A.No. I do believe recent regulatory actions
20 combined with more positive actual financial results have
21 stopped the decline in Idaho Power's credit ratings.
22 However, I also believe Idaho Power will need to show
23 sustained results before movement in a positive direction
24 occurs. In the Moody's credit opinion on March 31, 2010,
25 it offered the following comments on what would be required
26 to move the Company's credit ratings upward:
27 A rating upgrade is unlikely in the
28 near-to-medium term; however, IPC's29 rating outlook could turn to30 positive if the benefits from recent31 rate relief carry through and there32 are no material changes in the33 degree of regulatory supporti veness34 in future rate filings.
KEEN, DI 15
Idaho Power Company
1 In regard to what could move Idaho Power's ratings
2 down, it commented:
3 The rating would likely be revised
4 downward if the recently improved5 regulatory support wanes or if
6 conservati ve funding strategies are
7 not adhered to, thereby contributing
8 to undue pressure on metrics.
910 They also offered specific comments regarding cash
11 flow metrics, indicating that sustainable levels of
12 improvement would be needed to support a posi ti ve outlook
13 and that poor metrics for an extended period of time could
14 resul t in a ratings downgrade.
15 Q.Did Standard & Poor's offer any similar
16 comments?
17 A.Yes. In S&P's May 20, 2011, research report,
18 it noted the following in its credit outlook:
19 The stable outlook reflects our20 expectation of sufficient operating21 cash flows to support financial22 metrics that are adequate for the23 ratings, the ability to internally24 fund a significant portion of25 capital expenditures, and adequate26 management of regulatory27 relationships. We could lower the28 ratings if the company does not29 carefully manage costs and30 investments to ensure full recovery31 and the maintenance of credit32 metrics, especially in light of a
33 weakening economy. We could raise34 the ratings if the company is able35 to consistently achieve36 significantly stronger financial37 metrics, including adj usted FFO to
KEEN, DI 16
Idaho Power Company
1
2
3
4
5
6
debt of 20% or more and adjusted
debt to capital of 50% or less, in
addi tion to solidly managing
regulatory relationships, but higher
ratings are unlikely in the near
term.
7 Q.Given that, do you believe that the current
8 credit ratings of Idaho Power are adequate?
9 A.Yes. Idaho Power is able to raise capital in
10 today's markets with its current ratings. However, new
11 debt/bond issues are at a higher cost than if Idaho Power's
12 credi t ratings were higher (i. e., the higher the credit
13 rating, the lower the debt financing cost).
14 One large threat to Idaho Power's current ratings is
15 unforeseen risk. Should an unforeseen event cause Idaho
16 Power's short-term credit ratings to be lowered, it could
17 become extremely difficult for the Company to issue
18 commercial paper. The commercial paper market is very
19 competitive, and a reduction to the Company's short-term
20 credit rating would make its commercial paper illiquid in
21 the market and more expensive to issue. This would
22 significantly limit the options Idaho Power has available
23 to meet ongoing cash requirements, such as funding capital
24 improvements and paying for deviations in power supply
25 costs, and would likely result in higher interest costs
26 that ultimately flow through to the Company's customers.
27 The unforeseen risk has a potentially greater impact when a
KEEN, DI 17
Idaho Power Company
1 company is closer to the bottom of what is considered
2 "investment grade."
3 Q.What is the lowest rating that is considered
4 investment grade?
5 A.For S&P that rating is BBB-. Idaho Power's
6 corporate credit rating is currently one step above that
7 bottom rating. Its senior unsecured debt rating is at BBB
8 and its secured debt rating is currently at A-. A
9 significant concern for me, as the officer primarily
10 responsible for providing the Company's capital, is how
11 close Idaho Power is to the bottom of investment grade
12 status.
13 Q.Can you illustrate the recent trend in ratings
14 for the Company and show the relationship to the level that
15 is considered investment grade?
16 A.Yes. I have sponsored Exhibit No. 11, which
17 clearly shows the downward trend to Company ratings and
18 shows how close the current ratings are to the bottom level
19 for investment grade companies.
20 2.Reasonable Actual Results.
21 Q.Do you have an opinion as to why the rating
22 agencies have taken their previous actions to reduce Idaho
23 Power's credit ratings?
24 A.Yes, I do. I believe the single largest
25 contributor is the fact that the Company's actual results
KEEN, DI 18
Idaho Power Company
1 have been significantly and consistently below its
2 authorized rate of return.
3 Q.Has the Company been able to earn its allowed
4 return on equity in recent years?
5 A.No. During the years 2004 and 2005, Idaho
6 Power's authorized return on equity was 10.25 percent. In
7 those years, the Company earned a ROE of 7.2 percent and
S 7.7 percent, respectively. In 2006, Idaho Power's actual
9 ROE was higher but still barely over 9 percent in a year
10 that enjoyed good hydro conditions. In 2007, Idaho Power
11 only earned an actual return on equity of 6.9 percent.
12 During 200S, Idaho Power actually earned 7.9 percent in a
13 year when the allowed return on equity was being debated
14 and ultimately decided to be reasonable at 10.5 percent.
15 In 2009, the Company earned 9.6 percent, and, in 2010, the
16 Company had its best year in recent memory earning a 10
17 percent ROE. However, as I will explain later in my
lS testimony Idaho Power was able to achieve a 10 percent ROE
19 in 2010 only because it was able to realize the benefits of
20 a tax method change. If you remove the one time benefits
21 of the tax method change, the ROE was only 7.9 percent in
22 2010.
23 The gap between allowed and actual is quite evident
24 when placed on a graph, as depicted in the testimony of Mr.
25 Darrel Anderson.
KEEN, DI 19
Idaho Power Company
1 Q.How is this continual earnings short-fall
2 percei ved in the financial community?
3 A.I believe that the financial community and the
4 rating agencies are both focused on and concerned about
5 this short-fall. Recent ratings actions are looking
6 directly at the actual results of Idaho Power's regulatory
7 efforts. Both the investment community and the ratings
8 agencies expect actual rates of return to be near
9 authorized levels, or at least to occur at or above
10 authorized levels as often as they fall below them. They
11 are both also looking for more consistency in cash flows.
12 Q.What are the impacts if ratings agencies and
13 financial markets are continually disappointed with actual
14 results?
15 A.The impact is that the Company and its
16 customers eventually incur higher costs of capital. Lower
17 ratings actions contribute to higher costs of debt while
18 dissatisfaction in the financial markets can mean lower
19 stock valuation, which leads to greater numbers of equity
20 share issuances, ultimately driving total cost of capital
21 higher.
22 Q.Did the regulatory stipulation and settlement
23 in Case No. IPC-E-09-30 ("Stipulation") have any impact on
24 the Company's ability to earn a better return on equity?
25
KEEN, DI 20
Idaho Power Company
1 A.Yes. There were several benefits from the
2 Stipulation that were viewed favorably by the financial
3 communi ty. The concept of having a minimum ROE that had a
4 methodology for achieving that return each year was helpful
5 and viewed as a very positive and supportive regulatory
6 decision. Additionally, the fact that a modest amount of
7 improvement in cash revenues was included as part of the
8 Stipulation added validity to the overall agreement. The
9 earnings support that was offered by the 9.5 percent
10 threshold return on equity was bolstered by the opportunity
11 to amortize additional accumulated deferred investment tax
12 credi ts ("ADITC"). That impact would have helped Company
13 earnings but would not have provided cash benefit. The
14 combined impacts of the rate adjustments that occurred on
15 June 1, 2010, offered cash flow benefits to the Company
16 while decreasing rates for customers. The combination of
17 these two items was viewed in a posi ti ve light.
18 Q.Did the Company actually amortize additional
19 ADITC in 2010?
20 A.No. Initial projections for the 2010 year
21 included additional amortization of up to $25 million of
22 ADITC. By year end, no additional ADITC was utilized due
23 to the one-time benefit recognized for the tax method
24 change related to capitalized repair costs ("Repairs"). A
25 one-time tax benefit of $44.5 million was recorded relating
KEEN, DI 21
Idaho Power Company
1 to the 2009 and prior tax years. In addition, an $11.7
2 million tax benefit for the estimated annual deduction was
3 recorded for the 2010 year. This issue remained in dispute
4 with the Internal Revenue Service during 2010; thus, a
5 liability for uncertain tax positions was also accrued
6 relating to these two amounts totaling $ 14. 7 million. Wi th
7 $56.2 million of posi ti ve income impacts netted with the
8 uncertain tax position liability of $14.7 million, 2010 was
9 benefited by $41.5 million of additional income. This
10 increase eliminated any need to amortize additional ADITC.
11 Q.Without the benefit of the Repairs method
12 change in 2010 is it likely the Company would have needed
13 to amortize additional ADITC?
14 A.Yes.
15 Q.Will there be ongoing benefits from the
16 Repairs method change that could benefit the Company in
17 future years?
18 A.Yes. There is an ongoing tax benefit
19 associated with the Repairs deduction; it will provide some
20 benefit to 2011 and the full value of that benefit is
21 included in this rate filing as a decrease to expense.
22 This effectively lowers the annual request by approximately
23 $8 million more than Idaho Power's prior Repairs deduction
24 methodology would have. In addition, the Company will
25 continue to have the ability to use the Repairs deduction
KEEN, DI 22
Idaho Power Company
1 depending upon the amount of investment the Company makes
2 in future qualified repair items.
3 Q.You mentioned that a liability for uncertain
4 tax positions was established. How is that handled in the
5 future?
6 A.The issues surrounding the Repairs method
7 change were effectively settled with the Internal Revenue
8 Service in April of 2011. The result of that settlement
9 utilized all but approximately $3 million of the liability.
10 In other words, approximately $12 million of concessions
11 were made, lowering the tax benefit of the Repairs method
12 change, in order to reach agreement. The remaining $3
13 million of benefit is expected to be recognized in the
14 second quarter of 2011.
15 Q.Do you expect to need to amortize additional
16 ADITC in the 2011 year?
17 A.Yes. In the Company's recent first quarter
18 earnings release, Idaho Power reaffirmed its expectation
19 that in 2011 it will need to amortize up to $15 million of
20 additional ADITC. The $15 million was unchanged from Idaho
21 Power's original estimates for the year. This amount,
22 however, did not include the benefit of the $3 million of
23 uncertain tax position liability reversal since that event
24 occurred after the quarter end. Even with that adjustment,
25 it is expected that the Company will be below the 9.5
KEEN, DI 23
Idaho Power Company
1 percent return on year end common equity in the Idaho
2 jurisdiction such that additional amortization of ADITC
3 will be needed.
4 Q.Are there any other potential one-time
5 adjustments that could benefit 2011?
6 A.An additional tax method change relating to
7 the 2009 income tax return occurred in 2010, the income tax
8 benefits of which were offset by recording a liability for
9 uncertain tax positions equal to 100 percent of the
10 benefit. This method change relates to Idaho Power's
11 method of capitalizing overhead costs for tax purposes
12 ("UNICAP"). The method change for UNICAP was not a
13 taxpayer initiated method change but was based on
14 methodology derived by the Internal Revenue Service. The
15 methodology was new, and while benefiting the Company with
16 additional current tax benefits, created results similar to
17 a method change proposed by the Company in previous years
18 that was later contested and significantly reduced by the
19 Internal Revenue Service. The size of the change was also
20 of such a magnitude that it elevated Idaho Power's 2009
21 refund claim to a level that required approval by the U. S.
22 Congress's Joint Committee on Taxation ("Joint Committee").
23 Given all of these facts, the Company established a
24 liabili ty for uncertain tax positions which netted against
25 the original claim bringing the 2010 net tax benefit to $0.
KEEN, DI 24
Idaho Power Company
1 At year end 2010, the gross UNICAP method change
2 impact was approximately $ 60 million. As time passes, this
3 benefit at inception becomes smaller as depreciation
4 continues to be claimed on the property additions to which
5 the overheads related. The amount at March 31, 2011, was
6 $58 million; however, additional benefits for new
7 deductions relating to ongoing years will also be recorded
8 if the issue is ultimately approved by the Joint Committee.
9 In April 2011, the UNICAP issue was submitted along
10 with the rest of the 2009 tax return to the Joint Committee
11 for review. The Company believes submission at this early
12 date enhances the possibility for resolution in 2011. If
13 approval is received, a net benefit in excess of $ 60
14 million is expected to be recognized in 2011. If this
15 occurs, it will likely eliminate the need to amortize any
16 additional ADITC in 2011, and the Company will likely
17 exceed its authorized ROE of 10.5 percent. Amounts over
18 the 10.5 percent level in 2011 will be available for
19 sharing under the 2010 Stipulation.
20 Additionally, if the UNICAP benefit is recognized in
21 2011, Idaho Power will not have used any of the $45 million
22 of ADITC available to it under the settlement agreement.
23 Thus, these deferred tax benefits would be preserved for
24 future periods to benefit customers or could be used for
25 other regulatory considerations.
KEEN, DI 25
Idaho Power Company
1 Q.Are the ongoing benefits from the UNICAP
2 method change included in this case similar to the Repairs
3 method change?
4 A.At this time, they are not included because
5 the Joint Committee has not approved the Company's 2009
6 refund. However, a UNICAP deduction consistent with Idaho
7 Power's prior method has been included, thus providing some
8 rate benefit. If approval is received from the Joint
9 Committee, it would be appropriate for the increased annual
10 benefits to be included in a general rate case.
11 Q.Are there other tax benefits that you are
12 aware of that could benefit the current or future periods?
13 A.At this time, there are no other anticipated
14 or pending method change issues and the Company has no
15 maj or changes to its tax policy that would deliver
16 significant benefits to either 2011 or future years. The
17 two large items that have occurred recently are rare, and
18 even more unusual to have the impacts from two such
19 adjustments so close together in time. There is a federal
20 tax depreciation benefit known as Bonus Depreciation that
21 was granted to a broad range of taxpayers, including Idaho
22 Power, and while providing cash benefits to the Company, it
23 does not have income benefits such as either the Repairs or
24 UNICAP methods. Bonus Depreciation has been utilized by
25 the federal government, off and on, for the last decade as
KEEN, DI 26
Idaho Power Company
1 an economic stimulus measure. The Company has typically
2 taken advantage of the deduction when offered. Cash flow
3 will be benefited in 2011 by the Bonus Depreciation
4 deduction. Current tax expense will be lower with an
5 offsetting deferred tax that leaves the income impact at
6 $ o. The deferred taxes will add to the balance of
7 accumulated deferred income taxes at year end. The
8 accumulated deferred income tax balances, for items
9 included in rate base, are a net reduction to rate base,
10 thus benefiting customers. While Bonus Depreciation is
11 available in 2011 and 2012, there is no income or return on
12 equity support associated with this deduction.
13 Q.How do the ratings agencies view the impacts
14 of Bonus Depreciation?
15 A.Standard & Poor's issued an update
16 specifically on Bonus Depreciation on May 9, 2011. In that
17 report S&P generally concludes that bonus depreciation is
18 good for cash flow but that they do not see the same
19 positive impact on credit ratings. They make their point
20 strongly with two separate document headings. First, that
21 "Bonus Depreciation Will Improve Cash Flow . . " then
22 ". . But Not Credit Quality." Under the first heading,
23 S&P points out that Bonus Depreciation will increase cash
24 flow as well as cash flow metrics. Under the second
25 heading, S&P points out, "However, while we view bonus
KEEN, DI 27
Idaho Power Company
1 depreciation as real cash that a company has at its
2 disposal, we minimize its importance in our fundamental
3 credit analysis because it is not sustainable." In Idaho
4 Power's discussions with both Moody's and Standard &
5 Poor's, they found it posi ti ve that the Company planned to
6 utilize the additional cash that results from Bonus
7 Depreciation to minimize existing and future capital
8 funding needs.
9 Q.Looking ahead, what does Idaho Power believe
10 is the broader implication of the previously discussed one-
11 time tax benefit?
12 A.The Company has delivered better financial
13 results in recent years, although still below its
14 authorized rates of return, due to the benefits of one-time
15 ini tiati ves and the Stipulation. As seen in the prior
16 comments from the ratings agencies, the improved actual
17 resul ts combined with a supportive regulatory environment
18 have been viewed posi ti vely. The one-time events related
19 to the Repairs method change allowed Idaho Power to finish
20 2010 without needing to amortize additional ADITC. In
21 2011, Idaho Power projects the need to amortize some
22 additional ADITC, unless another one-time event, the UNICAP
23 method, is approved by the Joint Committee. Both of these
24 events, the Repairs and UNICAP method changes, provide the
25 majority of their value in a single period. They may lift
KEEN, DI 28
Idaho Power Company
1 a single year's performance, but they do not provide the
2 sustained, ongoing level of support needed by Idaho Power
3 to maintain or enhance its credit quality. Returning to
4 one of my earlier comments, in 2010, the Company looks
5 quite reasonable with a 10 percent actual return on equity;
6 it is far better than the years immediately prior.
7 However, when you remove the benefits of the Repairs method
8 change, the actual return would have been 7.9 percent
9 (assuming no additional amortization of ADITC). It is this
10 unassisted level of return that requires additional
11 regulatory support and calls for at least the very
12 conservati ve ROE of 10.5 percent that Idaho Power has
13 requested in this filing.
14 3.Hydro and Weather Variability.
15 Q.Please describe the risks specific to Idaho
16 Power's predominately hydroelectric generating base.
17 A.Idaho Power and its customers have
18 historically enjoyed the benefits of a hydroelectric-based
19 utility. The availability of hydroelectric power depends
20 on the amount of snow pack in the mountains upstream of
21 Idaho Power's hydroelectric facilities, reservoir storage,
22 springtime snow pack run-off, rainfall, temperature, and
23 other weather variability, combined with other stream flow
24 management considerations. During low water years, when
25 stream flows into Idaho Power's hydroelectric projects are
KEEN, DI 29
Idaho Power Company
1 reduced, Idaho Power's hydroelectric generation is reduced.
2 Extreme temperatures increase demand for power by
3 customers, who use electricity for cooling and heating, and
4 moderate temperatures decrease demand for power.
5 Precipitation or the lack thereof also directly affects the
6 Company's irrigation load. Weather and hydro-production
7 are inextricably linked. Reduced hydroelectric generation
8 resul ting from below normal water flows requires the
9 Company to use more expensive thermal generation and/or
10 purchased power to meet the electrical needs of its
11 customers.
12 Q.Are there any other water or weather-related
13 risks of the Company that you would like to comment on?
14 A.Yes. Comments from credit rating agencies and
15 equity analysts have expressed concern about the potential
16 impacts from aquifer recharge and water rights. The
17 Company's reliance on hydro generation in general has come
18 under scrutiny with recent history delivering so many
19 below-normal water years in the Company's region. Some of
20 the water issues impacting Idaho Power occur primarily in
21 the Idaho service territory but they impact the general
22 risk profile of the Company. While it is difficult to
23 quantify potential exposures, the heightened level of
24 discussions and disagreements regarding water related
25
KEEN, DI 30
Idaho Power Company
1 issues have increased the Company's risk profile in the
2 financial community.
3 Q.Has anyone in the financial community tried to
4 quantify the risks relative to hydro exposure for the
5 Company?
6 A.Yes. While all of the rating agencies and
7 many in the equity analyst community have commented on the
8 significant level of risk the Company faces in regard to
9 its high reliance on hydro power, S&P actually reviewed the
10 hydro issue specifically for Northwest utilities. On
11 January 28, 2008, S&P issued a report titled, "Pacific
12 Northwest Hydrology and Its Impact on Investor-Owned
13 Utilities' Credit Quality." This report took an in-depth
14 look at hydro implications for investor-owned utilities in
15 the Northwest. Regarding Idaho Power, the January 2008 S&P
16 report stated that, "Idaho Power's regulatory mechanisms
17 are strong, relative to the other companies in our survey,
18 but not strong enough to overcome significant exposure to
19 the variable flows of the Snake River." The report went on
20 to indicate the financial implications to the Company
21 related to this and other factors as described below:
22 Despi te having both a PCA and an
23 update process, the mechanisms have24 not been able to fully insulate the25 company from the highly variable and26 generally low flow conditions that27 have persisted on the Snake River28 for the greater part of the past
KEEN, DI 31
Idaho Power Company
1
2
3
4
5
6
7
8
decade. Idaho Power'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.
9 Q.Do the Company's established mechanisms for
10 handling variations in power supply costs remove this
11 weather and water risk?
12 A.To a large extent, yes. However, because the
13 established mechanisms do not insulate the Company from the
14 effects of 100 percent of all power cost variations, larger
15 variations translate to more volatility for financial
1 6 results. This higher volatility is viewed as elevated risk
17 by the financial community.
18 Q.Has the financial community viewed the recent
19 changes to the PCA in Idaho as helpful in regard to this
20 risk?
21 A.Yes. The financial community's perception is
22 that recent changes to the PCA mechanism have helped reduce
23 but not completely eliminate some financial risk.
24 4.Relicensinq the Hells Canyon Complex.
25 Q.Please describe the risks associated with the
26 renewal of federal licenses for the Company's hydroelectric
27 proj ects.
KEEN, DI 32
Idaho Power Company
1 A.Idaho Power is the only investor-owned
2 electric utility in the United States that, under normal
3 water conditions , derives as much as 55 percent of its
4 Company-owned total system generation from hydro generating
5 facili ties. Wi th such a large percentage of the Company's
6 generation resources reliant on hydro facilities, a failure
7 to successfully renew the federal licenses of these
8 facilities could have a dramatic financial impact on the
9 Company and the prices its consumers pay for electricity.
10 For this reason, the Company has committed to expend
11 significant financial and human resources to obtain new
12 Federal Energy Regulatory Commission ("FERC") licenses for
13 its hydro generating capacity.
14 Q.What are the financial risks associated with
15 the Company's efforts to relicense its hydro generating
16 facilities?
17 A.Once a relicense application is filed, the
18 utili ty has no idea as to how long it will be before an
19 order is received from the FERC. This uncertainty,
20 combined with the potential loss of generation capability
21 due to operational requirements, and the magnitude of the
22 financial impact of unknown Protection, Mitigation, and
23 Enhancement ("PM&E") costs create financial risks for the
24 Company.
25
KEEN, DI 33
Idaho Power Company
1 Q.Are there other hydro relicensing-based
2 financial risks considered by the investment community?
3 A.Yes. For any particular generating facility,
4 the worst possible outcome would be the loss of the license
5 to a competing party. Along with the uncertainty as to the
6 eventual receipt of licenses and the costs involved in
7 preparing for the license applications, costs of PM&E
8 related to these proj ects are also difficult to quantify.
9 The potential financial magnitude of these PM&E costs and
10 their affect on the Company's low-cost hydro generation
11 resources threaten the financial stability of a company the
12 size of Idaho Power and the ultimate rates it must charge
13 its customers. These amounts will vary among facilities;
14 however, in all cases, they can be significant due to lost
15 generation capacity, generation at a higher cost, and the
16 decreased ability of the Company to time and control water
17 releases.
18 If the Company cannot generate when it is most
19 advantageous for the system, then some of the economic
20 value of the generation will be lost even if the amount of
21 total generation does not change. In addition to the hydro
22 relicensing risk, the Company continually faces significant
23 capital, operating, and other costs relating to compliance
24 with current environmental statutes, rules, and
25 regulations. These costs may be even higher in the future
KEEN, DI 34
Idaho Power Company
1 as a result of, among other factors, changes in legislation
2 and enforcement policies and the potential additional
3 requirements imposed in connection with the relicensing of
4 the Company's hydroelectric proj ects.
5 Q.Please address the risk specifically
6 associated with the Company's relicensing effort before the
7 FERC for the Hells Canyon generating facilities.
8 A.Idaho Power's Hells Canyon generating
9 facilities, comprised of Hells Canyon, Oxbow, and Brownlee
10 dams, make up 67 percent of the Company's hydro generation
11 capacity and 40 percent of its total generation capacity.
12 The Hells Canyon license application was filed in July 2003
13 and accepted by the FERC for filing in December 2003. The
14 FERC process moves at a slow and deliberate pace due to the
15 large number of interested parties involved in evaluating
16 the application. Therefore, the timing of the issuance of
17 a new Hells Canyon facilities license remains uncertain.
18 Historically, FERC has given the Company an annual license
19 renewal (under the existing old license) until the formal
20 new license is issued. It is difficult to predict the
21 ultimate financial impact of the relicense until the new
22 FERC license is issued and all of the relicense conditions
23 are known.
24 Q.Please comment on the relicensing efforts that
25 the Company has already undertaken.
KEEN, DI 35
Idaho Power Company
1 A.As part of the FERC relicensing regulations
2 and pursuant to the Federal Power Act, the Company is
3 required to conduct numerous studies and evaluations
4 concerning botanical, land management, hydraulic, flow
5 modeling, sedimentary, water quality, aquatic, recreation,
6 cultural resource, and fish and wildlife issues.
7 Q.How does the Company account for the cost of
8 these projects?
9 A.Idaho Power books the proj ect costs to
10 Construction Work in Progress ("CWIP") because they are
11 part of the relicensing process pursuant to FERC and state
12 accounting requirements. While the costs are included in
13 CWIP, the Company accrues a capitalization charge commonly
14 referred to as an Allowance for Funds Used during
15 Construction ("AFUDC"). The AFUDC is a non-cash item that
16 represents the cost of related debt and equity financing.
17 The component for AFUDC attributable to borrowed funds is
18 included as a reduction to interest expense, while the
19 equity component is included in other income. The total
20 amount of AFUDC is charged to CWIP.
21 Q.What were the accumulated costs related to the
22 Hells Canyon relicensing at December 31, 2010?
23 A.The total amount the Company had accrued in
24 CWIP was $130.2 million related to Hells Canyon
25
KEEN, DI 36
Idaho Power Company
1 relicensing. Included in this amount was $50.6 million in
2 AFUDC.
3 Q.Was recovery previously granted for some of
4 the AFUDC that is accruing on the Hells Canyon proj ect?
5 A.Yes. Per Commission Order No. 30722, the
6 Company is currently authorized to recover, in the Idaho
7 jurisdiction, $ 6.5 million annually, on a pre-tax basis, to
8 cover the impacts of AFUDC. On an after tax basis, the
9 amount is $10.6 million. Through December 31, 2010, Idaho
10 Power has accrued/received $13.3 million in pre-tax dollars
11 and $8.0 million in taxes for a total of $21.2 million.
12 The roughly $21 million of accrual has been accumulated in
13 a regulatory liability account and accrues a carrying
14 charge to the benefit of customers. The regulatory
15 liability account will eventually be used to offset AFUDC
16 in the CWIP account upon closing to plant in service.
17 Q.What will occur when the Company receives a
18 new license for the Hells Canyon facilities?
19 A.The amounts in CWIP, net of any accrued
20 balance in the regulatory liability account for amounts
21 received relative to AFUDC, will be transferred to plant in
22 service and the accumulation of AFUDC will cease. The
23 resul t will be an increase in rate base with earnings of
24 the Company declining until this additional amount is
25 included in rate base and reflected in rates since there
KEEN, DI 37
Idaho Power Company
1 will be no ongoing AFUDC. Because this is a relicense of
2 an existing hydro facility, there will be no increase (and
3 potentially a decrease due to operational changes) in the
4 generation of power and thus no increase in sales revenues.
5 The investment community sees this as a risk that confronts
6 the Company which can be summarized as follows: upon
7 receipt of a relicense, (1) the Company's earnings will go
8 down (no continuing AFUDC), (2) the Company's rate base
9 will go up (transfer from CWIP), and (3) no additional
10 sales revenues (same plant but new license) will result.
11 If the completion of relicensing is not aligned perfectly
12 with the allowance of new effective rates that recognize
13 the transfer of previously deferred relicensing costs into
14 rate base, the Company will be financially harmed. For the
15 period of time the new rate base is under review by the
16 Commission, the Company will earn no return on roughly $100
17 million of investment. This potential regulatory lag
18 combined with any additional potential for some
19 disallowance is a significant risk factor based upon the
20 size of the investment.
21 Q.Why did you not ask for the additional amounts
22 of AFUDC in this case, or simply ask to have the entire
23 amount considered as rate base?
24 A.As explained earlier in my testimony, the
25 Company is very cognizant of the economic conditions in its
KEEN, DI 38
Idaho Power Company
1 service terri tory, and in this filing, Mr. Anderson
2 directed Mr. Gregory W. Said to look for opportunities to
3 lessen the immediate rate impact on Idaho Power's
4 customers. In light of that, an additional AFUDC component
5 was considered in preparation for this rate filing but
6 inclusion would have increased Idaho Power's request for
7 additional rates by approximately $4 million while
8 providing no additional support for the income statement.
9 Gi ven this item had negative customer impacts and only
10 provided cash benefits to Idaho Power, it was selected as
11 an item that could be deferred at this time. The Company
12 proposes that the previously authorized collection relative
13 to AFUDC continue.
14 5.Risk Associated with Purchase of QF Energy.
15 Q.Does the regulatory treatment of the Company's
16 energy purchases from QFs pursuant to the Public Utility
17 Regulatory Policies Act of 1978 ("PURPA") increase the
18 financial risk to Idaho Power?
19 A.Yes. It is important to note that in a very
20 short time frame, the Company has experienced unprecedented
21 growth in the total amount of generation and financial
22 commitments as the result of a high number of agreements it
23 has entered into with PURPA projects, many of which are
24 wind generators. The regulatory treatment of QF
25 expenditures provides for a one-for-one recovery of dollars
KEEN, DI 39
Idaho Power Company
1 expended, but does not provide for any return to compensate
2 the Company for this acti vi ty. The Company is, in effect,
3 buying and selling energy pursuant to a legal mandate
4 wi thout any compensation for providing this service.
5 Simplistically, this regulatory treatment is similar to
6 requiring a person operating a business to buy a product at
7 the same price it must be sold. The mere dollar-for-dollar
8 recovery of QF expenditures, with no return for the use of
9 the Company's general and administrative resources, balance
10 sheet, and liquidity in managing QF programs, is viewed as
11 a significant risk by the rating agencies. The rating
12 agencies are not making a judgment related to the
13 appropriateness of QF energy purchase programs, but merely
14 pointing out the cost of the financial risk (s) arising from
15 a QF transaction, and that this risk should be reflected in
16 a higher return on equity to credit the Company for its QF
17 contracts.
18 Q.Do the rating agencies recognize the financial
19 costs of QF-related transactions?
20 A.Yes. Like other electric utilities, when the
21 Company adds to its rate base, it must use some portion of
22 shareholder equity to fund the investment. The Company
23 must maintain its proportion of equity to debt above a
24 certain level as it continues this investment process. If
25 it does not, the debt level increases and the Company will
KEEN, DI 40
Idaho Power Company
1 face the threat of a ratings downgrade. Conversely, when
2 the Company enters into a QF contract for purchased power,
3 an obligation not reflected in its financial statements, an
4 increase in equity is needed to maintain credit quality.
5 Unless an equity component is provided to offset the debt-
6 like obligation of long-term QF purchase power contracts,
7 the Company faces off-balance sheet financial risk. For
8 financial commitments that do not appear on the balance
9 sheet, analysts at S&P impute the debt and interest
10 equivalents on the financial statements of the Company to
11 achieve a more accurate picture of the risk associated with
12 the investment and the Company's related commitment. The
13 added equity needed to offset this imputed debt and
14 interest represents the effect that long-term purchased
15 power commitments have on the cost of capital. Any
16 increase in the long-term obligation of a utility related
17 to its capacity and energy resources will have to be backed
18 by an appropriate amount of equity in the eyes of the
19 ratings agencies.
20 In reviewing its evaluation of the credit
21 implications of QF-related expenditures, in May of 2003, as
22 stated below, S&P noted that such agreements are "debt-like
23 in nature" and that the increased financial risk must be
24 considered in evaluating a utility's credit risks.
25
KEEN, DI 41
Idaho Power Company
1
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3
4
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6
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8
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41 Q.
42 material?
43 A.
Standard & Poor's Ratings Services
views electric utility purchased-
power agreements (PPA) as debt-likein nature, and has historicallycapi talized these obligations on asliding scale known as a 'riskspectrum. ' Standard & Poor's
applies a 0 percent to 100 percent
'risk factor' to the net present
value (NPV) of the PPA capacity
payments, and designates this amount
as the debt equivalent.
* * *
Standard & Poor's evaluates the
benefi ts and risks of purchased
power by adjusting a purchasingutili ty' s reported financial
statements to allow for moremeaningful comparisons wi th
utilities that build generation.
Utilities that build typically
finance construction with a mix ofdebt and equity. A utility that
leases a power plant has entered
into a debt transaction for that
facili ty; a capital 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 , utilities are
typically not financially
compensated for the risks theyassume in purchasing power, as
purchased power is usually recovered
dollar-for-dollar as an operating
expense.
Are QF-related expenditures really that
Yes. As of the end of 2010, Idaho Power had
44 126 signed cogeneration/small power production ("CSPP")-
KEEN, DI 42
Idaho Power Company
1 related contracts with QFs representing 1,188 megawatts
2 ("MW") of capacity. Ninety-one QF projects with a
3 nameplate capacity of 491 MW were on-line at the end of
4 2010. In 2010, the Company made payments of approximately
5 $55 million to QF proj ects. For the 2011 PCA forecast year
6 (June 1, 2011, through May 31, 2012), the Company
7 anticipates payment of approximately $91 million to QF
8 projects. See Case No. IPC-E-11-06. The Company is
9 currently obligated to pay approximately $3.9 billion over
10 the next 20 years to QF developers. See Case No. GNR-E-10-
11 4, Comments of Idaho Power Company. These substantial and
12 increasing liabilities to QF proj ect developers create a
13 material risk factor for Idaho Power without any
14 corresponding potential risk mitigation or reward.
15 Q.Is the Company proposing to be compensated for
16 QF energy it purchases in this docket?
17 A.No. In the past, proposals had been made to
18 allow Idaho Power a management fee connected with the costs
19 it incurs in managing its CSPP contracts. See, e.g., Order
20 No. 18190 at 21. While Idaho Power is not requesting any
21 type of management fee in this case, it is important that
22 the Commission acknowledge the risks posed by the Company's
23 PURPA contract obligations as part of determining an
24 appropriate ROE for the Company.
25
KEEN, DI 43
Idaho Power Company
1 6.Enhancements and Reliability.
2 Q.Please describe the risks relative to the
3 Company's ability to recover significant capital investment
4 required for its electrical requirements.
5 A.As the Company's generation and transmission
6 systems age and customer electrical requirements increase,
7 addi tional investment is required to maintain reliability
8 standards and the additional demand on its electrical
9 infrastructure. The Company's year-end 2010 Form 10-K
10 reports a construction budget of between $320 to $330
11 million in 2011 and between $450 million to $470 million of
12 new construction expenditures over the two-year period of
13 2012 through 2013. Construction investments of this
14 magnitude introduce two elements of risk. First, the
15 ability of the Company to attract the required capital and,
16 second, the recovery of these investments is on a deferred
17 basis and subj ect to the regulatory process.
18 Q.Has growth not slowed substantially with the
19 recent recession?
20 A.Growth has slowed but it has not hal ted. That
21 said, demands for new capital relating to maintaining a
22 safe, reliable system that satisfies federal and state
23 compliance, reliability, and security mandates remain
24 significant in size and a financial burden to the Company,
25 as described in greater detail in Mr. Anderson's testimony.
KEEN, DI 44
Idaho Power Company
1 The Company still bears significant risk meeting its
2 obligation to safely and reliably serve customers and
3 continues to feel the pressure to raise large amounts of
4 growth-related capital requirements. Additionally, efforts
5 at the national level to reshape energy policy may place
6 new upward pressure on spending. New federal energy
7 policies are constantly evolving and will most likely bring
8 addi tional spending requirements to meet renewable
9 portfolio standards and to comply with expected carbon
10 reducing efforts.
11 7.Company Size and Geoqraphic Concentration.
12 Q.Does IDACORP's size have an impact on
13 investor's perceived level of risk?
14 A.Yes, IDACORP' s relatively small market
15 capitalization compared to its peers is a factor that makes
16 IDACORP riskier than the average electric utility holding
17 company. IDACORP's $ 1.8 billion market capitalization is
18 much smaller than the $7.3 billion dollar average market
19 cap of the electric utilities used by Dr. Avera to estimate
20 the range of acceptable ROEs. i There is well-documented
21 evidence that investors in smaller companies expect higher
22 rates of return than larger companies, but also face higher
23 risk.2 Idaho Power does not have a corporate parent with a
i As of April 26, 2011, www.yahoo.com/finance.
2 See Chapter 7 "Firm Size and Return" of Ibbotson SEEI 2011 Classic
Yearbook.
KEEN, DI 45
Idaho Power Company
1 large balance sheet and strong credit ratings to rely on
2 during times of financial stress. Also, the Company faces
3 a concentrated regulatory risk compared to many of its
4 peers because 95 percent of its retail revenues come from
5 one jurisdiction. Both equity analysts and the credit
6 agencies consistently identify regulatory risk as one of
7 the chief risk factors for the Company. This lack of
8 diversification, combined with the relatively small size
9 would argue for a higher required return from investors
10 compared to Idaho Power's peers.
11 III. CAITAL STRUCTU
12 Q.Would you please describe Exhibit No. 12?
13 A.Exhibi t No. 12 details the calculation of
14 Idaho Power's capital structure for long-term debt, the
15 common equity balance resulting from the Company's
16 forecasted year-end 2011 capital structure prepared under
17 my direction and the resulting, recommended overall rate of
18 return.
19 Q.The capital structure presented on Exhibit No.
20 12 incorporates changes to the Company's financial
21 reporting of its capital structure. Could you please
22 discuss the rationale for the variance?
23 A.For financial reporting purposes, the American
24 Falls Bond Guarantee and the Milner Dam Note Guarantee are
25 included in the long-term debt portion of the capital
KEEN, DI 46
Idaho Power Company
1 structure. For ratemaking purposes, the interest costs
2 associated with both the American Falls and the Milner debt
3 securi ties are treated as operations and maintenance
4 expenses. Even with these exclusions, the capital
5 structure presented in my Exhibit No. 12 is reasonable in
6 light of industry and rating agency criteria.
7 Q.What is the Company's proposed cost of debt?
8 A.As shown on Exhibit No. 13, which details the
9 calculation of the cost of debt used in the estimated year-
10 end 2011 capital structure, the Company's proposed cost of
11 debt is 5.728 percent.
12 Q.Has the Company made any changes to its method
13 for calculating its cost of debt?
14 A.Yes. Idaho Power determined that in previous
15 filings its debt calculation method did not fully account
16 for the actual cost of debt. Specifically, previous debt
17 calculations failed to fully consider the effect of
18 discounts, premiums, and expense of issue on the annual
19 cost of each bond. The Company studied different methods
20 to calculate the cost of debt, including methods used by
21 other utili ties that had filed cases in Idaho. The Company
22 used the bond yield to maturity method in its Oregon filing
23 in 2009, as well as in Idaho. See OPUC Case No. UE 213 This
24 method has also been used by Rocky Mountain Power and
25 Avista in their filings before the Commission, and it was
KEEN, DI 47
Idaho Power Company
1 not contested in either case. See PAC-E-10-07 and AVA-E-
2 10-01
3 Q.Please explain the new cost of debt
4 calculation on Exhibit No. 13?
5 A.The calculation takes the settlement date,
6 maturity date, coupon rate and net proceeds at the issuance
7 date for each debt issue to produce a bond yield to
8 maturity. The bond yield was then multiplied by the
9 principal amount outstanding for each debt issue, resulting
10 in an annualized cost of each debt issue in column 12. The
11 total in column 12 for all the debt issues produces a total
12 annual effective cost of debt in line 25. This total was
13 di vided by the total net proceeds in column 10 to produce
14 the weighted average cost for all long-term debt in column
15 11, line 25. This method is a more accurate calculation
16 because the expense of issue associated with a bond is
17 essentially pre-paid interest and the net proceeds, not the
18 principal amount of the bond, are all that is available to
19 be invested in property, plant, and equipment (rate base) .
20 Q.Does the Company utilize variable rate
21 securities in its long-term capitalization?
22 A.Yes. The Company currently utilizes one
23 variable rate security in its long-term capitalization.
24 The Port of Morrow (Boardman) Pollution Control Revenue
25
KEEN, DI 48
Idaho Power Company
1 Bonds Variable Rate Series 2000 ($4.36 million) is listed
2 on line 21 of Exhibit No. 13.
3 Q.Would you please describe the variable rate
4 nature of this pollution control bond?
5 A.This variable rate pollution control bond,
6 although considered a long-term security, has features that
7 allow the Company to take advantage of rates applicable to
8 short-term securities. The interest rate is determined the
9 first day of a weekly period by a Remarketing Agent. The
10 Remarketing Agent examines tax-exempt obligations
11 comparable to the Boardman Variable Bonds known to have
12 been priced or traded under the then-prevailing market
13 condi tions and finds the lowest rate which would enable
14 sale of the Boardman Variable Rate Bonds.
15 Q.How did you determine what rate to use for the
16 Boardman Variable Rate Bond?
17 A.I used actual rates for January through March
18 and forecasted the remaining monthly rates for 2011. For
19 the forecast I combined monthly rates from the Securities
20 Industry and Financial Markets Association ("SIFMA")
21 forward curve, a commonly used and accepted industry
22 metric, with the observed spread between the Boardman
23 Variable Rate Bond and the SIFMA rate. The spread I used
24 was 1.25 percent over the SIFMA rate - this was the average
25 spread from mid-April through December of 2010. Prior to
KEEN, DI 49
Idaho Power Company
1 this time, the spread was significantly higher. The
2 average rate for the year, when combining the actual and
3 forecasted rates, is 1.55 percent, which is actually lower
4 than the average rate observed for this bond in 2010.
5 Q.Please comment on the structure and rates for
6 the Humboldt and Sweetwater County bonds and how they
7 differ from the last rate case.
S A.In the last rate case, the Sweetwater and
9 Humboldt County bonds were in an auction rate mode that
10 reset periodically (every seven days for Sweetwater and
11 every 35 days for Humboldt). The mode had produced short-
12 term rates for the long-dated securities even lower than
13 the Boardman Variable Rate Bonds, and these benefits have
14 been passed on to customers through a lower overall cost of
15 capital structure since 2003. However, in February of
16 200S, the entire auction rate market began to deteriorate
17 rapidly based on overall credit worries in the market,
lS specifically around the mono-line insurers which guarantee
19 a large portion of the debt in this market. Both the
20 Sweetwater and Humboldt bonds began to experience much
21 higher reset rates through the auction process (e. g.,
22 between 7 and 10 percent for Sweetwater). The Company
23 arranged for a short-term loan and used the proceeds to
24 purchase these bonds and hold them in Idaho Power's name.
25 In August of 2009, the Company remarketed these bonds into
KEEN, DI 50
Idaho Power Company
1 long fixed rate modes, which are reflected on the Exhibit
2 No. 13
3 Q.Have there been any other significant
4 refinancing in recent years?
5 A.Yes. In 2010, Idaho Power made a somewhat
6 unusual decision to pre fund an obligation for first
7 mortgage bonds that were due in 2011, slightly more than
8 six months early. The pre funding decision required the
9 Company to incur negative carrying costs relative to the
10 investment opportunities that were available. This
11 decision secured some of the lowest long-term financing
12 rates that Idaho Power has ever enjoyed; $100 million at a
13 3.4 percent coupon for ten years and $100 million at a 4.85
14 percent coupon for thirty years. The rates achieved were
15 record setting in the time frame they occurred and will be
16 beneficial to the customer for many years to come as the
17 proceeds of this financing were used to pre fund near-term
18 construction costs and repay $120 million of outstanding
19 mortgage bonds due on March 2, 2011, that carried a coupon
20 of 6.6 percent. While not listed as a risk factor,
21 opportunities to retire existing bonds with less costly
22 financing will be more difficult in the near term. The
23 next two tranches of first mortgage bonds due for
24 redemption in 2012 and 2013 carry coupons below 5 percent.
25
KEEN, DI 51
Idaho Power Company
1 iV. OVERAL COST OF CAITAL
2 Q.What is the overall cost of capital for Idaho
3 Power?
4 A.As shown on Exhibit No. 12, using the
5 Company's projected year-end 2011 capital structure, the
6 Company's cost of debt as presented in my testimony, and
7 incorporating the recommended 10.5 percent cost of equity,
8 the resultant overall cost of capital for Idaho Power is
9 8.17 percent. This is an appropriate rate of return to be
10 utilized by the Commission when deriving the Company's
11 revenue requirement.
12 Q.Does this conclude your direct testimony in
13 this case?
14 A.Yes, it does.
15
16
17
18
19
20
21
22
23
24
25
KEEN, DI 52
Idaho Power Company
BEFORE THE ,
RECEIVED
zon JUN -I PH 2:43
f () l\f'~¡ 0,
IDAHO PUBLIC UTiliTIES COMMISSldt!/iIES
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
KEEN, 01
TESTIMONY
EXHIBIT NO. 11
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BEFORE THE
RECElVED
20fl JUN -I PM 2; 43
Itì/Lchl(J
IDAHO PUBLIC UTILITIES COMMISsfONlES
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
KEEN, 01
TESTIMONY
EXHIBIT NO. 12
(1 )
Line
No
1 Long-term Debt
2 Preferred Stock
3 Common Equity
4 Total Capitalization
Note:
* Requested Rate of Return
IDAHO POWER COMPANY
PRO FORMA COST OF CAPITAL
SUMMARIZED
December 31,2011 Capitalization
(2)(3)(4)(5)
Capitalization Structure Embedded Weighted
Amount Percent Cost Cost
1,465,460,000 48.824%5.728%2.797%
0 0.000%0.000%0.000%
1,536,028,822 51.176%10.500% *5.373%
$3,001,488,822 100.000%8.170%
Exhibit No. 12
Case No. IPC-E-11-08
S. Keen, IPC
Page 1 of 1
RECErVEO
BEFORE THE 2011 JWI -I PM 2: 43
¡ ¡¡H I'RNLC'
IDAHO PUBLIC UTILITIES COMMISS1()IN:':!
CASE NO. IPC-E-11-08
IDAHO POWER COMPANY
KEEN, 01
TESTIMONY
EXHIBIT NO. 13
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Case No. IPC-E-11-08
S. Keen, IPC
Page 1 of 1