20071210English direct.pdf

BEFORE THE
ZOíJ7 DEC 10 PM 3: 35
IDAHO PUBLIC UTILITIES COMMISSI9NI' IJ2/üiO)'UqUCur'LlliESvOMMlssl.("¡i.v.
IN THE MATTER OF THE APPLlCA10N )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-07-8
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE )
IN THE STATE OF IDAHO. )
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DIRECT TESTIMONY OF DONN ENGLISH
IDAHO PUBLIC UTILITIES COMMISSION
DECEMBER 10, 2007
1 Q.Please state your name and business address for
2 the record.
3 A.My name is Donn English. My business address
4 is 472 W. Washington, Boise, Idaho 83702.
5 Q.By whom are you employed and in what capacity?
6 A.I am employed by the Idaho Public Utilities
7 Commission as a senior auditor in the Utilities Division.
8 Q.What is your educational and experience
9 background?
10 A.I graduated from Boise State University in 1998
11 with a BBA degree in Accounting. Following my graduation I
12 accepted a position as a Trust Accountant with a pension
13 administration, actuarial and consulting firm in Boise. As
14 a Trust Accountant, my primary duties were to audit the
15 day-to-day financial transactions of numerous qualified
16 retirement plans. In 1999 I was promoted to Pension
17 Administrator. As a Pension Administrator, my
18 responsibilities included calculating pension and profit
19 sharing contributions, performing required non-
20 discrimination testing and filing the annual returns (Form
21 5500 and attachments). In May of 2001, I became a
22 designated member of the American Society of Pension
23 Professionals and Actuaries (ASPPA). I was the first
24 person in Idaho to receive the Qualified 401 (k)
25 Administrator certification and I am one of approximately
CASE NO. IPC-E-7-812/10/07 ENGLISH, D. (Di)
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1 ten people in Idaho who have earned the Qualified Pension
2 Administrator certification. In 2001 I was promoted to a
3 Pension Consultant, a position I held until 2003 when I
4 joined the Commission Staff.
5 wi th the American Society of Pension
6 Professionals and Actuaries, I served on the Education and
7 Examination Committee for two years. On this committee I
8 was responsible for writing and reviewing exam questions
9 and study materials for the PA-1 and PA-2 exams
10 (Introduction to Pension Administration Courses), DC-1, DC-
11 2 and DC-3 exams (Administrative Issues of Defined
12 Contribution Plans - Basic Concepts, Compliance Concepts
13 and Advanced Concepts) and the DB exam (Administrative
14 Issues of Defined Benefit Plans). I have also regularly
15 attended conferences and training seminars throughout the
16 country on numerous pension issues.
17 While with the Commission, I have audited a
18 number of utili ties including electric, water and gas
19 companies and provided comments and testimony in several
20 cases that dealt with general rates, accounting issues,
21 pension issues and other regulatory issues. In 2004 I
22 attended the 46th Annual Regulatory Studies Program at the
23 Institute of Public Utilities at Michigan State University
24 sponsored by the National Association of Regulatory Utility
25 Commissioners (NARUC). Since then I have regularly
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1 at tended NARUC conferences and meetings, primarily the
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2 meetings of the Subcommittee of Accounting and Finance.
Q.What is the purpose of your testimony in this
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4 proceeding?
A.The purpose of my testimony in this case is to
6 present the summary exhibit that reflects all the Staff
7 witnesses' recommendations and quantifies Staff's
8 recommended revenue requirement. i will discuss specific
9 adjustments made to Operations and Maintenance (O&M)
10 Expenses and rate base. I also present the exhibit with
11 Staff's recommended capital structure and cost of capital,
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12 while discussing the limited risk profile of Idaho Power.
Q.Are you sponsoring any exhibits with your
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14 testimony?
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A.Yes, I am sponsoring Exhibit Nos. 112-115.
What is Staff's recommended annual revenueQ.
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17 requirement for Idaho Power?
A.Staff recommends a revenue requirement of
19 $635,272,968 for the Idaho jurisdiction, which is an
20 increase of $17,452,700 or approximately 2.82% over current
21 revenues. Exhibit No. 112 illustrates the calculation of
22 Staff's revenue requirement on both a system basis and an
23 Idaho jurisdictional basis and compares Staff's revenue
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24 requirement to that requested by Idaho Power.
Q.What was the return on equity and overall rate
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1 of return used to calculate the revenue requirement?
2 A.Staff uses a return on equity of 10.25% and an
3 overall rate of return of 7.864%. i will discuss the
4 capital structure, cost of debt and factors that reduce
5 risk for Idaho Power later in my testimony. Staff witness
6 Terri Carlock will justify using a return on equity of
7 10.25%.
8 Test Year
9 Q.What was the test year used to calculate the
10 revenue requirement?
11 A.Staff audited the 12-month period of July 1,
12 2006 through June 30, 2007, and used the actual expenses
13 incurred during that test period as a starting point to
14 calculate the appropriate revenue requirement. Staff then
15 made additional adjustments for known and measurable
16 expenses to be incurred after the June 30, 2007 cutoff
17 date. Staff utilized the most recent historic test year to
18 address the Company's concern regarding regulatory lag,
19 while also providing Staff with the opportunity to audit
20 actual expenditures. The June 2007 information became
21 available to Staff at the end of August, allowing Staff
22 enough time to perform an audit and incorporate the results
23 into our prefiled direct testimony.
24 Q.Idaho Power proposed using a forecasted test
25 year to calculate revenue requirement. Why did Staff
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1 produce a different test year?
A.While it would have been much easier to accept
3 the Company's forecasts, Staff believes an historical test
4 year is more appropriate and the Commission has explicitly
5 stated its preference for an historical test year. In
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Order No. 29838 issued on August 3, 2005, the Commission
wrote:
To facilitate an adequate review, Company data should
be provided in time to incorporate the information in
the prefiled testimony of Staff and other parties.
This will facilitate the hearing and decision
processes by having similar time periods and
information for Staff and intervenor prefiled
testimony, the Company's rebuttal, and at the
hearing. Using recent, actual data for the hearing
will reduce if not elimnate the need to argue over
forecasts. (Emphasis added)
In Idaho Power's 2003 general rate case,
IPC-E-03-13, the Commission also Ordered the use of actual
data to replace the forecasts filed in the Company's case.
Even as recently as June 19, 2007, the Commission stated in
Order No. 30342, "our policy when setting utility rates is
to utilize an historic test year that can be verified by
audi t of actual numbers prior to placing new rates into
effect. "
The Company's decision to use a forecasted test
year and file a general rate case based on budgets created
difficulties for Staff in determining the prudency of
25 expenses to be recovered in customer rates. Staff was
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1 unable to review any invoices, unable to determine what the
2 Company was going to spend money on, and unable to compare
3 actual expenditures to the forecasts provided by the
4 Company. Idaho Power filed its case and exhibits using
5 FERC account numbers, however the budgets were created at
6 the cost center level and then allocated to the FERC
7 accounts. Because of this allocation, Staff was unable to
8 compare the Company's forecasts to historical levels of
9 expense with any confidence as any deviations could simply
10 be blamed on the allocation method.
11 Given the need to set rates based on obj ecti ve
12 and verifiable numbers, along with the Commission's
13 previous orders addressing forecasts, I was charged with
14 the difficult task of reconstructing the Company's case
15 using actual data for a recent 12 -month period. During the
16 audit in this case, Staff access to the Company's records
17 and files in a timely manner was limited, making the
18 construction of an historical test year extremely
19 challenging. However, Staff believes the task was
20 necessary to comply with previous Commission Orders and for
21 Staff to present a just, fair and reasonable revenue
22 requirement.
23 Q.Are there any other problems with forecasted
24 test years?
25 A.Other than the need to set rates on actual,
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1 verifiable numbers, the flaw with the use of a forecasted
2 test year is that it is impossible to know if a forecast is
3 accurate until the forecast period has passed. What is
4 important in establishing accurate rates is the
5 relationship between revenues and costs. As long as a
6 recent and consistent historical test year is used, the
7 revenue/ cost relationship will generally be representative
8 of current conditions and the revertue requirement will be
9 accurate for the period when rates are in effect. In the
10 case of Idaho Power, the rates may only be in effect for
11 approximately one year, which eliminates much of the
12 justification for a future test year.
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13 Sumary of Adjustments - Rate Base
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Q.Please explain Exhibit No. 112.
A.As previously mentioned Exhibit No. 112
16 illustrates my calculation of the revenue requirement and
17 rate increase and compares Staff's case to the case filed
18 by Idaho Power. Staff's revenue requirement is based on a
19 rate base of $1,807,849,061 and total operating expenses of
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20 $669,364,817 for the Idaho jurisdiction.
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Q.Please explain Exhibit No. 113.
A.Exhibit No. 113 summarizes the adjustments made
23 to the historical test year to obtain the final numbers
24 included in Staff's revenue requirement. Lines 1-16
25 outline the proposed rate base on which the Company should
CASE NO. IPC-E-7-812/10/07 ENGLISH, D. (Di)
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1 earn a return. Column 1 represents Staff's calculated 13-
2 month average rate base. Column 2, line 12 shows the
3 removal of plant held for future use from rate base. Line
4 13 adjusts working capital for fuel stock and to remove
5 pre-paid assets from rate base and line 15 shows the
6 removal of unused plant at the Bridger Coal Mine pursuant
7 to Commission Order No. 29505. Column 3 illustrates the
8 additional rate base added to the test year for plant that
9 is currently in use but was not online as of June 30, 2007,
10 along with the annualization of certain plant that was
11 placed in service during the year. Staff witness Kathy
12 Stockton is the primary rate base witness and these
13 adj ustments are discussed in greater detail in her
14 testimony. Column 4 illustrates the removal of capitalized
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15 pension expense from rate base.
Q.Please explain the adjustment for capitalized
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17 pension expense.
A.Idaho Power routinely capitalizes a portion of
19 its benefits as overhead. My adjustment removes the
20 capitalized portion of the Company's Net Periodic Pension
21 Cost as calculated under the Statement of Financial
22 Accounting Standards No 87 (FAS 87) for the years 2003-
23 2007. The total amount I remove from rate base is
24 $5,833,205, which is the $6,243,382 that has been
25 capitalized since 2003 net the $410,177 of accumulated
CASE NO. IPC-E-7-812/10/07 ENGLISH, D. (Di)
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1 depreciation on that amount. I also remove an additional
2 $162,316 from depreciation expense associated with the
3 capitalized FAS 87 pension expense.
4 Q.Please explain the FAS 87 pension expense.
5 A.The FAS 87 pension expense is an accrual of
6 pension expense that the Company is required to record on
7 its books for annual reporting purposes. It has no bearing
8 on the amount of money the Company is required to
9 contribute to the pension plan.
10 Q.Has the Commission excluded FAS 87 pension
11 expense from rates?
12 A.Yes. In the 2003 rate case, Idaho Power
13 proposed to collect millions of dollars in pension expense,
14 claiming increasing pension expense as a driver for the
15 rate increase, although not having invested a single dollar
16 into the pension plan since 1995. In Order No. 29505, the
17 Commission disallowed recovery of FAS 87 pension expense
18 and accepted Staff's adjustment that reconciled the cash
19 contributions from the pension accruals. Ultimately, Idaho
20 Power did not recover any pension expense because it has
21 not been funding the pension plan for several years. In
22 Case No. AVU-E-04-1 and again in Case No. UWI-W-04-4, the
23 Commission used the actual cash contributions required
24 under the Employee Retirement Income Securities Act
25 (ERISA). Because the situation surrounding the pension
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1 plan has not changed since the 2003 case, and Idaho Power
2 is not currently contributing to the plan, it is not
3 appropriate for ratepayers to pay a return to Idaho Power
4 for the capitalized portion of this journal entry. This
5 adjustment is consistent with the Commission's Orders on
6 the matter.
7 Q.Why was capitalized pension expense not
8 mentioned in Order No. 29S0S?
9 A.I believe it was the Commission's intent to
10 remove all of FAS 87 pension expense from rates. Staff
11 recommended and the Commission agreed to set the amount of
12 pension expense to be recovered at $0.00, the actual amount
13 funded. After the Commission's Order was issued, the
14 Company notified the Commission that not all of the PAS 87
15 pension expense was booked into account 926, Employee
16 Pensions and Benefits. Because the entire amount was not
17 booked into that account, Idaho Power could not remove more
18 than that which it had booked. Staff was unaware of the
19 Company's practice of capitalizing a portion of the FAS 87
20 pension expense and therefore concurred with the Company.
21 The Commission reduced the amount of Staff's adjustment,
22 but ultimately, the amount to be recovered for pension
23 expense was still $0.00.
24 The additional amount that was not expensed to
25 Account 926 was capitalized, and the Company has been
CASE NO. IPC-E-7-812/10/07 ENGLISH, D. (Di) 10
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1 receiving a return from ratepayers on this capitalized
2 amount ever since. The Company has also continued to
3 capitalize a portion of its FAS 87 pension expense every
4 year since the 2003 case. Again, I stress that it is not
5 appropriate for the Company to be receiving a return on
6 this capitalized portion of pension expense when it has not
7 funded the pension plan in over 12 years.
8 Sumary of Adjustments - O&M Expenses
9 Q.What adj ustments were made to the test year O&M
10 expenses?
11 A.The first adjustments made were the standard
12 Commission adjustments arising from previous orders. These
13 adjustments consist of the removal of FAS 87 pension
14 expense and general advertising expense from rates
15 consistent with prior orders. Also removed from rates is a
16 portion of all social club memberships, contributions and
17 dues along with management expenses that should be
18 allocated to IDACORP. Both Staff and the Company agree
19 with these adjustments, however the amounts may differ due
20 to differences in the test year. The sum total of these
21 adjustments is reflected on Exhibit No. 113, line 20,
22 Column 2.
23 Staff accepts the Company's adjustment removing
24 memberships, dues, contributions and management expenses as
25 shown in Company witness Lori Smith's Exhibit No. 17 even
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1 though the adjustment was based on forecasts. Because the
2 amounts in these adjustments are a cumulative total of
3 small dollar transactions, Staff believes the Company's
4 adjustment is reflective of the level of expenses incurred
5 in any given year. The burdensome nature of combing
6 through small dollar transactions such as these would limit
7 Staff's resources during the audit, and Staff believes it
S is acceptable to use the Company's adjustments for the
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9 purpose of setting rates.
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Q.What other adjustments are made to O&M Expense?
A.The next set of adjustments to O&M Expense are
12 the normalizing and annualizing adjustments. Staff witness
13 Rick Sterling discusses the normalizing of power supply
14 expenses and Aurora modeling in his testimony. I have
15 reflected his adjustments in Column 6.
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Q.Please discuss the annualizing adjustments.
A.Annualizing adjustments are made to insurance
1S expense and payroll expense. Staff witness Cecily Vaughn's
19 testimony discusses the annualizing of insurance, along
20 with adjustments for FERC administration fees and
21 miscellaneous expenses. I have reflected those adjustments
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22 in Column 5 of Exhibit No. 113.
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Q.What adjustments are made to payroll expense?
A.The first adjustment I propose is to increase
25 the actual test year operating payroll. Idaho Power hires
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1 new employees throughout the year, so I have annualized
2 June's straight-time payroll to capture those new employees
3 and treat them as if they were employed for the entire
4 year. This adjustment provides an additional $3.3 million
5 to Idaho Power to reflect the actual payroll expenses that
6 will be incurred by the Company when rates go into effect.
7 Exhibit No. 114 reflects the calculation of this amount
S and is similar to Company witness Smith's Exhibit No. 18,
9 page 2. The difference between the two exhibits arises
10 from the starting point of the annualization. Consistent
11 with prior cases, I have used the actual, known amounts of
12 the final month of Staff's test year. Company witness
13 Smith annualizes the forecasted December 2007 straight-time
14 payroll. Based on the Commission's stated preference of
15 using actual data in place of forecasts, it would be
16 inappropriate to annualize a forecasted amount because the
17 opportunity for over statement and over collection is too
lS prevalent.
19 Q.Do you propose any other increases to the
20 Company's test year payroll?
21 A.Yes. Pursuant to the stipulation filed in
22 IPC-E-OS-S, the Company's last general rate case, I have
23 increased the Company's payroll by approximately $5.7
24 million for the target level of incentive payments. This
25 calculation is also included on Exhibit No. 114. Section
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1 6 (e) of the Stipulation states:
2 The Parties agree conceptually that it is
reasonable to include an employee pay-at-risk
3 or employee incentive component in test year
revenue requirement so long as such incentive4 component is based on goals that benefit
customers and the amounts payable for achieving
5 the goals are limited to reasonable "target" or
medium goals. Senior managemsnt pay-at-risk is
6 appropriately excluded from the test year revenue
requirement.
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8 To abide by the Stipulation Agreement as adopted by the
9 Commission, I have adjusted the Company's payroll upward to
10 reflect these bonuses.
11 It is worth noting that the target level of
12 incentive payments in the 2005 rate case was 3.5%, while
13 the target level of the bonuses in 2007 is 4%. If the
14 Company intends to continually increase its target levels
15 for incentive payments, then it will become more difficult
16 for Staff to support inclusion of higher amounts in rates.
17 Q.Do you propose an adjustment to your test year
18 payroll for the Company's annual Salary Structure
19 Adjustment?
20 A.No I do not for three different reasons.
21 First, the Salary Structure Adjustment (SSA) proposed by
22 the Company is based on increasing the estimated 200S
23 payroll by an estimated 3%. The Company's proposal
24 violates long-standing ratemaking treatment that post test
25 year adjustments be known and measurable. The amount of
CASE NO. IPC-E-7-S12/10/07 ENGLISH, D. (Di) 14
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1 the adjustment, if any, is neither known nor measurable, as
2 the Company has in the past foregone any employee raises in
3 times of financial restraint. In Order No. 29505,
4 following the Company's 2003 rate case, the Commission
5 states:
6 The Company acknowledged that current financialconditions do, and we believe they ought to,
7 dictate a tightening of the Company's belt so to
speak with regard to salaries. Because of thisS and the fact that the SSA adjustment is neither
known nor measurable at this time, the Commission9 accordingly will remove $2,241,595 from
test year expenses for the SSA.
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11 Second, I believe the Commission ought to be
12 cognizant of public perception pertaining to Idaho Power
13 giving employee raises at a time when they are asking to
14 increase the rates it charges for electricity. If Idaho
15 Power believes that today's financial environment mandates
16 the need for increasing rates, it should consider
17 internally cutting costs rather than continually increasing
lS rates. Last, the Company will experience salary savings
19 through attrition. As employees leave the Company, their
20 replacements will presumably be paid less. The Company
21 should use the salary savings from attrition to offer
22 employee salary increases rather than having its customers
23 shoulder the entire burden. For those reasons, I have not
24 increased the test year operating payroll for the SSA.
25 Q.Are there any other adjustments to O&M Expense?
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1 A.Yes, I have removed approximately $20S,OOO in
2 legal expenses incurred by Idaho Power from the test year.
3 These expenses are extraordinary and not reflective of the
4 ongoing acti vi ties of Idaho Power. My adj ustment leaves
5 approximately 9S% of all legal fees expensed in the test
6 year. When you also take into consideration all of the
7 legal fees the Company capitalized, the adjustment is a
S fraction of 1% of all legal fees incurred by the Company.
9 Q.What types of issues did you consider when you
10 audited the legal fees?
11 A.I reviewed every invoice for legal services
12 during the test year, and my adjustment will only remove
13 the fees for issues that will likely not occur again in the
14 future. Issues that pertained to things such as water
15 rights, employee personnel matters and workmen's
16 compensation issues were left in the test year because they
17 are reflective of the ongoing level of legal expenses the
lS Company can expect to incur during a given year. I removed
19 $SS,OS7 in legal services pertaining to the merger of
20 PacifiCorp and Mid-American Holding Company. A merger of
21 this magnitude will not likely occur every year, and it
22 would be inappropriate for the Company to recover this
23 amount annually.
24 I have also removed $55,463 in legal fees
25 related to the delisting of the Idaho Springsnail from the
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1 Endangered Species Act. These expenses may be viewed as
2 political lobbying by Idaho Power, but I have adjusted them
3 because the Idaho Springsnail is now delisted, and the
4 level of legal expenses related to the issue are not
5 reflective of the ongoing legal expenses that Idaho Power
6 is expected to incur.
7 The final category of legal expenses I have
S removed from the test year is related to the dissemination
9 of Company hard drives that contained Company proprietary
10 information and confidential employee information. These
11 hard drives were sold to the public on eBay without first
12 being scrubbed to remove data stored on the drives. In
13 Staff's test year, the Company incurred $95,248 in legal
14 expenses pertaining to the dissemination and retrieval of
15 those hard drives. Staff expects that this was a one-time
16 issue.
17 Q.Has the Commission removed extraordinary legal
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lS expenses in past cases?
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A.Yes. In Order No. 29602, the Commission found
that:
...removing non-recurring, extraordinary legal
expenses to be reasonable and appropriate.
Avista contends that some extraordinary expenses
always come up and should not be a reason for
excluding the level of expense requested. Our
view is that the level of legal expenses incurred
by the Company is somewhat wi thin its control.
Further, we note that the regulatory accounting
system does not per.i t inclusion of unusual
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expenses in a test year for ratemaking purposes.
(Emphasis added).
Also, in Order No. 29505 culminating the
Company's 2003 rate case, the Commission accepted Staff's
recommendation to remove legal expenses related to
potential refunds from the 2000-2001 energy crises and
stated:
We believe the Company acted prudently to ensure that
its ratepayers would be able to receive any potential
refunds that may have resulted in these cases. That
said, there is no reason to believe the entire amount
of defending against these cases should be included
in the test year as if the same amount will be
incurred each year into the future.
In Order No. 29838, the Commission clearly stated "a
company is not allowed to include for recovery in rates
expenses that are for extraordinary, non-recurring events"
as support for removing specific legal fees from United
16 Water's test year. My treatment of the legal expenses in
17 this case is consistent with all prior Commission Orders on
18 the matter.
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19 Capital Structure and Cost of Capital
Q.Please explain the capital structure and cost
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21 of capital of Idaho Power.
A.Capi tal structure refers to the way a
23 corporation is financed by debt, common equity and
24 preferred stock or other forms of securities. The capital
25 structure of Idaho Power consists of approximately 51% debt
CASE NO. IPC-E-7-812/10/07 ENGLISH, D. (Di) 18
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1 and 49% common equity. This capital structure is similar
2 to that of PacifiCorp and Avista Utilities, both large
3 electric utilities serving Idaho residents. It is also
4 similar to structures approved in prior Idaho Power general
5 rate cases. For this case, Staff uses the actual capital
6 structure of Idaho Power at June 30, 2007, with some
7 adjustments to be consistent with prior Commission Orders.
8 The cost of capital for Idaho Power is the
9 weighted sum of the cost of common equity and the cost of
10 debt. Staff uses an overall cost of capital of 7.864% to
11 calculate the Company's revenue requirement. This amount
12 is based on a cost of debt of 5.612%, and a return on
13 equity of 10.25% as mentioned previously. Exhibit No. 115
14 illustrates the calculation of the capital structure and
15 the overall cost of capital.
16 Q.Please explain any differences between the
17 capital structure used by Staff and the capital structure
18 proposed by the Company.
19 A.Staff uses the known capital structure and cost
20 of capital at June 30, 2007, the end of the Staff test
21 year. Using the actual capital structure is consistent
22 with prior Commission Orders, including the last two Idaho
23 Power rates cases heard before the Commission. Idaho Power
24 proposes to use the forecasted capital structure on
25 December 31, 2007.
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1 Q.Please explain the differences in the cost of
2 capital used by Staff and the cost of capital proposed by
3 the Company.
4 A. The primary difference is in the cost of
5 equity. Idaho Power proposes a cost of equity of 11.5%,
6 while Staff uses a more moderate cost of equity of 10.25%.
7 This is discussed later in my testimony and in Staff
8 witness Terri Carlock's testimony. There is also a
9 difference in the embedded cost of debt proposed by the
10 Company and that used by Staff. Staff uses an embedded
11 cost of debt of 5.612%, which is the actual cost of debt as
12 of June 30, 2007, with pro-formed adjustments for two bond
13 issuances that occurred during 2007. Staff also made
14 adjustments to the variable interest rates on the pollution
15 control revenue bonds to be consistent with Commission
16 Order No. 29505. The Company proposes to use the
17 forecasted cost of debt on December 31, 2007.
18 Q.Please explain the variable rate bonds you
19 mentioned.
20 A.The Company currently uses three variable rate
21 pollution control revenue bonds in its long-term debt
22 calculation. These bonds are shown on Company witness
23 Steven Keen's Exhibit No. 11 and discussed in his testimony
24 on page 28. Mr. Keen has calculated a proxy interest rate
25 to use on the variable rate debt by calculating the average
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1 spread of the specific debt over the Securities Industry
2 and Financial Markets Municipal Swap Index and applying
3 that spread to the average forecasted index rate for 2007.
4 Q.Is this consistent with how the interest on
5 variable rate debts has been computed in the past.
6 A.No. Though the 2005 Idaho Power rate case
7 resulted in a settlement without all issues being presented
S to the Commission, the interest on the variable rate debt
9 was contested in the Company's 2003 general rate case. In
10 that case, the Company used a 10-year average to compute
11 the interest on variable rate debt. Staff argued that a
12 10-year average did not reflect the current interest rate
13 environment at the time, resulting in interest rates that
14 were grossly overstated. On rebuttal, Idaho Power stated
15 "the Company could support a five-year average methodology
16 so long as that methodology is applied consistently in
17 future rate cases". The Company also noted in its rebuttal
lS that the Commission accepted a five-year historical average
19 for the Company's auction of its preferred stock in the
20 1994 general rate case.
21 On page 36 of Order No. 29505, the Commission
22 found that use of the five-year historical average was the
23 most appropriate measure of the variable rate for the
24 bonds. Consistent with the prior Commission Order, and
25 because of the Company's request in that case for a
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1 consistent methodology, Staff uses the five-year daily
2 average of the variable interest rates to compute the cost
3 of debt on the pollution control bonds. The embedded cost
4 of the bonds using the five-year daily average is 3.373%
5 compared to the 3.708% forecasted by the Company.
6 Q.Are there any other differences in the embedded
7 cost of debt?
S A.Yes. At the time the Company filed its case,
9 it was preparing a bond issuance to redeem outstanding
10 commercial paper and to raise funds for ongoing capital
11 expenditures. Company witness Steven Keen's Exhibit
12 No. 11, line 10 indicates a forecasted bond issuance of
13 $153 million at a coupon rate of 5.9%. The actual bond
14 issuance was $140 million at a coupon rate of 6.3%. I have
15 reflected this change on page 2 of Exhibit No. 115, line
16 10, which illustrates the calculation of the weighted
17 embedded cost of debt.
18 The Company also issued an additional $100
19 million in securities backed by First Mortgage Bonds on
20 October 18, 2007, at a coupon rate of 6.25%. The proceeds
21 from the bond sale were to be used to payoff $SO million
22 of 7. 3S% debt maturing in December of this year. Line II
23 on page 2 of my Exhibit No. 115 illustrates the inclusion
24 of this known and measurable post test year financing in
25 the weighted cost of debt.
CASE NO. IPC-E-7-S12/10/07 ENGLISH, D. (Di) 22
STAFF
1 Q.Please discuss the common equity portion of the
2 cost of capital.
3 A.The cost of common equity is the return that
4 investors expect to receive. Equity investors expect a
5 return on their capital that is commensurate with the risks
6 they take and consistent with returns that might be
7 available from other similar investments. This profit or
S return on equity is paid to shareholders as dividends, or
9 retained by the Company to grow the equity investment and
10 future returns. Unlike the cost of debt, the cost of
11 equity is not directly observable in advance and therefore,
12 it must be calculated or inferred from capital market data
13 and trading activity. Staff uses a return on equity of
14 10.25% to calculate the Company's overall weighted cost of
15 capital.
16 Q.How did Staff arrive at the 10.25% return on
17 equity?
lS A.Staff witness Terri Carlock discusses the
19 return on equity in detail in her testimony. My input on
20 the return on equity relates to the risks faced by Idaho
21 Power when compared to the other electric utilities
22 operating in Idaho.
23 Q.What is the authorized return on equity for
24 other electric utili ties operating in Idaho?
25 A.In Order No. 29602 the Commission authorized a
CASE NO. IPC-E-7-S12/10/07 ENGLISH, D. (Di) 23
STAFF
1 return on common equity for Avista Utilities of 10.4% for
2 Idaho. Avista recently settled a general rate case in
3 Washington and was awarded a 10.2% return on equity in that
4 state. Staff has filed testimony in PacifiCorp i s current
5 case (PAC-E-07-S) recommending a 10.25% return. The
6 stipulation signed by all parties to that case adopted the
7 10.25% return on equity. Idaho Power was also awarded an
S authorized return on equity of 10.25 percent in its last
9 contested rate case, Case No. IPC-E-03-13. In the 2005
10 rate case settlement, the return on equity was not
11 explicitly stated, although the overall return on capital
12 was agreed upon in a negotiated settlement of all issues.
13 Given the return on equity granted to other utilities
14 serving Idaho, Idaho Power's proposed ROE of 11.5% is
15 excessive. Staff's recommended 10.25% is in line with
16 other utilities.
17 Q.The Company maintains that it needs a return on
lS common equity of at least 11.5% given the various risk
19 factors present by the Company. Would you please comment
20 on these assertions?
21 A.Yes. Risk is the uncertainty or
22 unpredictability of the future results of a company. The
23 greater the range within which future results are likely to
24 fall, the greater the risk associated with an investment
25 in, or extension of credit to the company. Generally
CASE NO. IPC-E-7-S12/10/07 ENGLISH, D. (Di) 24
STAFF
1 speaking, the more risk a company is exposed to, the higher
2 the rate of return that is expected by investors. Idaho
3 Power, as with all regulated utilities, is substantially
4 less risky than its counterparts in non-regulated arenas.
5 In the monopolistic environment in which regulated
6 utilities operate, the uncertainty of demand, financial
7 risks associated with non-payment from customers, and
8 strategic risks associated with competitors are minimal.
9 Maj or risks that utili ties are exposed to
10 include weather and the regulatory environment in which
11 they operate. An abnormally warm winter can be harmful to
12 a gas utility because customers will not be using as much
13 gas to heat their homes. Abnormally dry winters would be
14 harmful to electric utilities dependent on hyòro-
15 generation, like Idaho Power, because less water would be
16 available to generate the electricity needed to meet its
17 demand. Regulatory risk is the risk .of being denied
18 recovery of incurred costs.
19 Risks related to changes in weather have been
20 mitigated by the annual Power Cost Adjustment (PCA), which
21 allows Idaho Power to adjust rates each year to reconcile
22 power supply costs with those costs that are embedded in
23 base rates. On June 1 of this year, Idaho Power was
24 allowed to increase rates 14.5% to mitigate the effects of
25 weather, the continued drought and poor water conditions.
CASE NO. IPC-E-7-812/10/07 ENGLISH, D. (Di) 25
STAFF
1 These types of power cost recovery mechanisms are viewed
2 favorably by the financial industries and widely
3 acknowledged to reduce risk faced by utilities.
4 Q.What areas tend to reduce risk for Idaho Power
5 as compared to Avista and PacifiCorp?
6 A.Idaho Power's service territory is
7 predominately within the state of Idaho, while both
S PacifiCorp and Avista provide electric service in multiple
9 states. Both PacifiCorp and Avista have the increased
10 regulatory risk of dealing with multiple state
11 jurisdictions, facing different regulatory treatment, in
12 order to recover incurred expenses.
13 Idaho Power is also exposed to less regulatory
14 risk because it is the only utility within the state of
15 Idaho with a fixed cost recovery mechanism that reviews the
16 recovery of its fixed costs independent of the volume of
17 kilowatts sold. When rates are based on units sold, as
lS with Avista and PacifiCorp, these utilities can lose
19 revenue if the quantity of kilowatts sold decreases for any
20 variety of reasons. However, Idaho Power's revenue has
21 been decoupled from sales and its rates will be adjusted
22 annually to allow fixed cost recovery. This Fixed Cost
23 Recovery Mechanism removes a substantial amount of risk for
24 Idaho Power and its rate of return should properly reflect
25 the additional revenue stability provided by the Fixed Cost
CASE NO. IPC-E-7-S12/10/07 ENGLISH, D. (Di) 26
STAFF
1 Recovery Mechanism.
2 Q.Is there anything else you would like to add
3 before concluding your testimony?
4 A.Yes. I believe it is important to note that
5 all of Staff's adj ustments in this case, including using
6 the 13-month average for rate base, the actual known
7 Operating & Maintenance Expenses, and the removal of non-
S recurring expenses, are consistent with prior Commission
9 Orders. In this case, Staff has not proposed a single
10 adjustment category that has not been addressed by this
11 Commission previously. Our intent was to maintain as much
12 consistency as possible between rates cases and utilities.
13 This approach should facilitate the entire ratemaking
14 process. When there is consistency between rate cases and
15 utilities, a utility can then file its Application to
16 increase rates with adjustments that will be less
17 contentious. I believe this to be the proper policy and,
lS methodology for setting rates.
19 Q.Does this conclude your direct testimony in
20 this proceeding?
21 A.Yes, it does.
22
23
24
25
CASE NO. IPC-E-7-S12/10/07 ENGLISH, D. (Di) 27
STAFF
Idaho Power Company
Summary of Revenue Requirrement
IPC-E-07 -DS
(1) (2)
IDAHO POWER System IdahoRATE BASE
Electric Plant in Service:
1 Intangible Plant
2 Production Plant
3 Transmission Plant
4 Distribution Plant
5 General Plant
6 Total Electric Plant in Service
7 Less: Accumulated Depreciation
8 Less: Amortization of Other Plant
9 Net Electric Plant in Service
10 Less: Customer Adv for Construction
11 Less: Accum Deferred Income Taxes
12 Add: Plant Held for Future Use
13 Add: Working Capital
14 Add: Conservation - Other Deferred Programs
15 Add: Subsidiary Rate Base
16 TOTAL COMBINED RATE BASE
71,402,470
1,627,364,155
673,452,905
1,129,351,498
222,710,802
3,724,281,830
(1,545,958,752)
(39,240,525)
2,139,082,553
(29,852,876)
(206,314,418)
738,557
55,761,848
9,611,655
67,989,358
2,037,016,677
66,657,978
1,545,527,696
574,363,386
1,058,133,361
206,339,822
3,451,022,243
(1,437,090,522)
(36,633,103)
1,977 ,298,618
(29,809,228)
(191,148,701)
685,078
51,879,427
9,381,070
64,384,654
1,882,670,920
(3)
IPUC STAFFSystem Idaho
(4)
73,296,188
1,611,715,093
636,816,203
1,094,704,637
226,194,929
3,642,727,049
(1,537,887,342)
(39,701,582)
2,065,138,126
(26,331,284)
(213,871,282)
738,557
53,443,898
13,155,568
61,527,248
1,953,800,831
68,442,694
1,530,665,590
542,746,596
1,025,844,679
209,687,919
3,377,387,478
(1,429,190,313)
(37,072,641 )
1,911,124,524
(26,292,785)
(198,263,614)
684,954
49,670,137
12,660,688
58,265,157
1,807,849,061
IDAHO POWER IPUC STAFF
NET INCOME System Idaho System Idaho
Operating Revenues:
17 Sales Revenues 797,776,922 759,542,768 797,398,514 759,206,815
18 Other Operating Revenues 44,635,107 36,668,577 44,701,250 36,730,170
19 Total Operating Revenues 842,412,029 796,211,345 842,099,764 795,936,985
Operating Expenses:
21 Operation & Maintenance Expenses 554,783,494 521,551,516 542,571,627 509,075,952
22 Depreciation Expenses 97,955,528 90,930,388 94,176,744 87,473,390
23 Amortization of Limited Term Plant 8,503,692 7,938,646 8,935,263 8,343,592
24 Taxes Other Than Income 20,289,760 18,345,826 20,289,760 18,345,463
Regulatory Debits/Credits
25 Provision For Deferred Income Taxes (10,788,422)(10,951,869)(10,788,422)(10,926,376)
26 Investment Tax Credit Adjustment 1,509,120 1,531,983 1,509,120 1,528,417
27 Federal Income Taxes 46,055,852 46,753,611 51,056,045 51,708,911
28 State Income Taxes 2,806,745 2,849,268 3,767,295 3,815,468
29 Total Operating Expenses 721,115,769 678,949,369 711,517,431 669,364,817
30 Operating Income 121,296,260 117,261,976 130,582,333 126,572,168
31 Add: IERCO Operating Income 5,248,215 4,969,962 5,248,215 4,969,961
32 Consolidated Operating Income 126,54,475 122,231,938 135,830,548 131,542,130
33 Rate of Return as filed 6.21%6.49%6.95%7.28%
34 Proposed Rate of Return 8.5610%8.5610%7.8641%7.8641%
35 Earnings Deficiency 47,844,523 38,943,519 17,818,303 10,628,928
36 Net-to-Gross Tax Multiplier 1.642 1.642 1.642 1.642
37 Revenue Deficiency 78,560,706 63,945,259 29,257,654 17,452,700
38 Firm Jurisdictional Revenue 653,153,352 617,820,268 653,153,352 617,820,268
39 REVENUE REQUIREMENT 731,714,058 681,765,527 682,411,006 635,272,968
4.48%1 2.82%140Percentage Increase Required 12.03%10.35%
.J
Exhibit No. 112
Case No. IPC-E-07-8
D. English, Staff
12/10107
1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16
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Idaho Power Company
Adjustments to Test Year Payroll
Line
No.
1) Operating Payroll (Various accts)
1
2
3
4
5
6
7
8
ST Payroll 2007 June
Annualized (Divided by 2 pay periods, times 26)
Less 2007 Total
Gross adjustmentAdd payroll tax (Q 8.00%
Total adjustment including payroll tax
Operating percent
Adjustment to Operating Expense
2) Incentive Expense (Various accts)
9 2007 Straight-time Payroll
10 Plus 2007 Overtime Budget
11 Less: 2007 Offcer Payroll
12 Total Payroll Excl Officers
13 Normalized Incentive Rate
14 Normalized Incentive
15 Payroll Tax on Normalized Incentive (Q
16 Normalized Incentive Including Payroll Tax
19 Times incentive operating percent
Adjustment to Operating
20 Expense for Incentive
(1 )
Amount
$14,981,512
129,839,765
125,246,935
4,592,829
367,426
4,960,255
66.29%
$ 3,288,076
$129,839,765
6,549,699
3,187,175
133,202,289
4.00%
5,328,092
8.00%426,247
5,754,339
97.01%
$5,582,071
Exhibit No. 114
Case No. IPC-E-07-8
D. English, Staff
12/10107
IDAHO POWER COMPANY
COMPOSITE COST OF CAPITAL
June 30, 2007 Capitalization
(1 )(2)(3)(4)(5)
Line Capitalization Structure Embedded Weighted
No Amount Percent Cost Cost
1 Long-term Debt 1,115,460,000 51.437%5.612%2.886%
2 Common Equity 1,053,119,486 48.563%10.250%4.978%
3 Total Capitalization $2,168,579,486 100.000%7.864%
Exhibit NO.1 15
Case No. IPC-E-07-8
D. English, Staff
12/10107 Page 1 of2
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