20031021Gale Direct.pdf

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
13
TO ELECTRIC CUSTOMERS IN THE STATE)
OF IDAHO )
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IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
JOHN R. GALE
CASE NO. IPC-E-03-
1
2
Q.
A.
Please state your name and business address.
My name is John R. Gale and my business
3 address is 1221 West Idaho Street, Boise, Idaho.
4 Q. By whom are you employed and in what
5 capacity?
6 A. I am employed by Idaho Power Company (Idaho
7 Power or the Company) as the Vice President of Regulatory
8 Affairs.
9
10
Q.
A.
Please describe your work experience.
In October 1983, I accepted a position as
11 Rate Analyst with Idaho Power Company. In March 1990, I
12 was assigned to the Company's Meridian District Office for
13 one year where I held the position of Meridian Manager. In
14 March 1991, I was promoted to Manager of Rates. In July
15 1997, I was named General Manager of Pricing and Regulatory
16 Services. In March of 2001, I was promoted to Vice
17 President of Regulatory Affairs. As Vice President of
18 Regulatory Affairs, I am responsible for the overall
19 coordination and direction of the Pricing & Regulatory
20 Department, including development of jurisdictional revenue
21 requirements and class cost-of-service studies, preparation
22 of rate design analyses, and administration of tariffs and
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Idaho Power Company
1 customer contracts. In my current position, I am
2 responsible for policy matters related to the economic
3 regulation of Idaho Power Company.
4 Q. What role did you play in the preparation of
5 the general rate case?
6 A. My role in the preparation of the general
7 rate case was to oversee, manage, and coordinate the filing
8 and to make the policy decisions related to regulatory
9 matters.
10 Q. What was your interaction with the other
11 Company witnesses?
12 A. I discussed the content and preparation of
13 the witnesses' testimony and exhibits. I was assisted in
14 this effort by Ms. Maggie Brilz and Mr. Greg Said, along
15 with the Company's regulatory attorneys directed by Mr.
16 Barton Kline.
17 Q. Please provide an overview of the Company's
18 general rate case filing.
19 A. The Company leads with Mr. LaMont Keen, our
20 President and COO. Mr. Keen speaks to the Company's
21 financial condition and its management performance in
22 recent years. Mr. Keen is our primary policy witness. Our
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Idaho Power Company
1 next witness is Mr. William Avera, who has been retained by
2 the Company as our return on equity (ROE) expert. Mr.
3 Avera also performed this function for Idaho Power in our
4 last general rate case. Mr. Avera's recommended ROE range
5 becomes an input to Mr. Dennis Gribble's considerations.
6 Mr. Gribble selects an ROE point estimate and includes that
7 with the test year capital structure to derive the proposed
8 overall rate of return.
9 Ms. Lori Smith then testifies to the financial
10 inputs, both actual and estimated, that become our initial
11 starting point for the system data for the 2003 test year.
12 Ms. Smith includes system adjustments for deductions to
13 certain expenses not allowed in rates, annualizing
14 adjustments to expenses and rate base, known and measurable
15 adjustments to expenses and rate base, and other
16 adjustments to revenues, expenses and rate base related
17 primarily to past Idaho Public Utilities Commission (IPUC
18 or the Commission) orders. Mr. Obenchain takes Ms. Smith's
19 data, Mr. Gribble's return recommendation, Mr. Said's
20 normalized net power supply expenses, along with other
21 selected inputs and prepares the jurisdictional separation
22 study (JSS). The JSS, as its name states, separates system
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Idaho Power Company
1 values for rate base, revenues, and expenses for each state
2 and federal jurisdiction by an assignment and allocation
3 process. One result of the JSS is the Idaho retail
4 jurisdictional revenue requirement.
5 As stated before, Mr. Said provides the normalized
6 net power supply expenses for the test year. Mr. Said also
7 addresses the requisite changes needed to the Company's
8 Power Cost Adjustment as a result of changing the
9 normalized net power supply expenses in Idaho Power's Base
10 Rates.
11 Ms. Brilz takes the Idaho retail jurisdictional
12 output from Mr. Obenchain and further separates costs by
13 customer class and special contract through a class cost of
14 service (CCOS) study. Additionally, Ms. Brilz proposes
15 price changes to the customer classes that are consistent
16 with the Company's ratemaking objectives and recover the
17 Company's Idaho revenue requirement. Ms. Theresa Drake
18 addresses additional changes to Idaho Power's tariffs and
19 non-recurring charges.
20 Ms. Susan Fullen provides information regarding a
21 variety of Idaho Power's customer-related activities,
22 including the results of recent customer satisfaction
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Idaho Power Company
1 surveys. Finally, I finish the direct case addressing
2 regulatory policy issues.
3 Q. What was Idaho Power Company's executive
4 management involvement with the preparation of the general
5 rate case?
6 A. Idaho Power's Office of the Chief Operating
7 Officer, consisting of the Company's President, Senior Vice
8 President of Delivery, Vice President of Power Supply, Vice
9 President of Corporate Services, and myself along with the
10 Chief Financial Officer, served as the oversight group.
11 Q. What are the policy issues related to the
12 preparation of the test year financial information?
13 A. The policy decisions related to the
14 preparation of the general rate case include the selection
15 of the test year, the decision to use a split year, the
16 treatment of annualizing adjustments, and the treatment of
17 known and measurable adjustments.
18
19
Q.
A.
What is the Company's test year?
The Company's test year is the 12 months
20 ending December 31, 2003.
21
22
Q.
A.
Why did you choose 2003 as the test year?
Using a test year of 2003 provides the most
GALE, DI 5
Idaho Power Company
1 recent information available as to the Company's expenses
2 and investments. The year captures increased levels of
3 capital and O&M spending that are needed to fund our
4 utility infrastructure. The year also provides a clear
5 break with our past affiliate transactions with IDACORP
6 Energy (IE).
7 Q. Why did the Company choose to file with a
8 split test year that used both actual and estimated data?
9 A. The split test year using six months actual
10 and six months estimated data offers rate recovery closer
11 to the time that costs are incurred, allows the timing of
12 general rate changes to be coordinated with and potentially
13 mitigated by PCA changes, and provides the Commission an
14 opportunity to see actual information for the whole year
15 before issuing its final order.
16 Q. What was the basis for making annualizing
17 adjustments to rate base for 2003?
18 A. The annualizing adjustments to rate base for
19 2003 are related to electric plant in service items closing
20 to book during the last half of 2003. These items and
21 their related impacts (such as depreciation and property
22 tax) were treated as if they were in place for a full
GALE, DI 6
Idaho Power Company
1 twelve months.
2 Q. Please describe the annualizing adjustment
3 to the 2003 operating expense related to payroll.
4 A. The annualizing adjustment to the 2003
5 operating expense related to payroll, changes the payroll
6 expense to an amount reflective of what it would have been
7 had the year-end payroll expense been in existence for the
8 full year in 2003.
9 Q. What was the Company's basis for including
10 known and measurable additions to its rate base?
11 A. The Company included only assets of a
12 material size that were planned to close to the books
13 before June 1, 2004. These assets are major projects
14 related to transmission and transmission substation. The
15 Company chose June 1, 2004 as the cutoff for known and
16 measurable plant adjustments because that is the date that
17 the proposed rates are expected to become effective if the
18 Commission uses the full time to issue its order.
19 Q. Please describe the rationale for including
20 a known and measurable adjustment to operating expense for
21 employee incentives.
22 A. Since the last general rate case, Idaho
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Idaho Power Company
1 Power has made a material change in the manner in which it
2 compensates its employees. Starting in 1995, the Company
3 modified its existing "cash" compensation to include an
4 element of "pay at risk". The new plan continues to
5 provide a fixed base salary, but now includes the potential
6 for an incentive. Since the incentive can vary from year
7 to year according to Company and employee performance,
8 using the actual incentive amount as part of the test year
9 compensation can be misleading. Because the range of
10 potential outcomes is large, a normalized number is more
11 reflective of ongoing compensation than an actual amount.
12
13
Q.
A.
Why do you use the term "pay at risk"?
Before the incentive was introduced, the
14 Company targeted its base pay upon the 60th percentile of
15 the relevant labor market rate for the specific job
16 category. After the incentive was added to the
17 compensation package, the benchmark for the base pay was
18 reduced to the 50th percentile. The difference between the
19 two percentile levels became the pay at risk.
20 Q. What is the difference between the two
21 percentile levels worth in percentage terms?
22 A. Based upon our 2002 wage information, the
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Idaho Power Company
1 difference is approximately 7 percent. This figure can
2 vary slightly from one year to the next based on changes in
3 the market place, but in general the market changes are not
4 large enough to cause significant change.
5 Q. Why did you make a known and measurable
6 adjustment related to salary structure?
7 A. The known and measurable expense related to
8 salary structure adjusts payroll expense to account for an
9 employee general wage adjustment (GWA) at year-end 2003.
10 The adjustment for the GWA was 3 percent.
11 Q. What was the basis for the Company known and
12 measurable for pension costs?
13 A. There are three options which reflect the
14 cost of providing pension benefits to our employees: ( 1)
15 Pay As You Go, (2) Service Cost, and (3) Pension Expense.
16 The Pay As You Go reflects the actual benefits paid to
17 employees receiving pension benefits during the relevant
18 time period. The Service Cost benefit amount reflects the
19 cost to provide a new year of benefits to employees. The
20 Pension Expense method reflects the cost to provide the
21 benefits including the volatility of market movements that
22 impact the pension plan assets and the impact of interest
GALE, DI 9
Idaho Power Company
1 rate movements. Using the Service Cost method for
2 ratemaking purposes removes the market volatility and
3 interest rate volatility, while quantifying the annual cost
4 of providing a new year of benefits to employees. The test
5 year information was adjusted to reflect service costs for
6 2003, which the Company believes to be more representative
7 of our pension costs going forward.
8 Q. How have the Operating Revenues of the
9 Company been adjusted?
10 A. The Operating Revenues are primarily
11 adjusted through the normalizing adjustments to the
12 Company's net power supply expenses as a result of multiple
13 water conditions discussed by Mr. Said. Other known
14 changes to tariffs or contracts were also included either
15 in the test year revenues or adjustments to the test year.
16 Sales revenues for the test year 2003 were based on weather
17 normalized retail sales for the first six months and
18 estimated normalized sales for the later six months.
19 Q. What are the policy issues related to the
20 rate spread and rate design proposed by the Company?
21 A. The policy issues related to rate spread and
22 rate design are that rates should be primarily cost-based,
GALE, DI 10
Idaho Power Company
1 adjustments to the rate spread, an emphasis on fixed cost
2 recovery, and the introduction of time-of-use pricing (both
3 seasonal and diurnal).
4
5 rates?
6
Q.
A.
What is the Company's philosophy on setting
In the last several general rate cases, the
7 Company's primary approach to ratemaking has been to
8 reflect costs as accurately as possible in setting its
9 tariff rates. Accordingly, the Company's ratemaking
10 proposals usually advocate movement toward cost-of-service
11 results which assign costs to those customers that cause
12 the Company to incur the costs. The Company realizes that
13 there are other ratemaking objectives, such as ability to
14 pay, that the Commission may consider in making its
15 determination. However, the Company believes that the best
16 starting point for Commission deliberations is an economic
17 one. Nevertheless, some ratemaking situations cause such
18 abrupt change, the Company has proposed some limits to the
19 movement toward cost-of-service.
20 Q. How did you approach rate spread among the
21 customer classes and special contracts?
22 A. Rate spread is a term that refers to the
GALE, DI 11
Idaho Power Company
1 division of the jurisdictional revenue requirement into
2 individual revenue requirements for each customer class and
3 special contract. Each special contract is essentially a
4 rate class of one customer. The CCOS results are one means
5 of performing rate spread. Please refer to Exhibit No. 61,
6 a four-page exhibit that steps through the revenue
7 requirement allocation process from the CCOS results to the
8 Company's ultimate proposal for each customer class and
9 special contract. Page 1 of Exhibit No. 61 is the
10 proformed normalized test year sales and revenues. Page 2
11 indicates the adjustments in terms of percentages and
12 dollars that would be made to each customer class to obtain
13 the results indicated by the CCOS. A pure CCOS rate spread
14 would mean a 67.1 percent increase to the irrigation
15 customer class. Page 3 constrains the changes to the
16 revenue allocations in order to mitigate the magnitude of
17 the rate increase to the irrigation customer class. A 25
18 percent limit is placed on the increase to irrigation,
19 while the small unmetered classes are held at zero instead
20 of the decreases indicated by the CCOS. Page 4 spreads the
21 revenue shortfall created by the mitigation back to the
22 other customer classes, so that the total Idaho
GALE, DI 12
Idaho Power Company
1 jurisdictional target revenue can be obtained.
2 Q. Has the Company's cost-based approach
3 influenced other rate design proposals?
4 A. Yes, the cost-based approach has led to rate
5 design proposals that better align fixed costs with fixed
6 prices and variable costs with variable prices. Ideally an
7 energy rate that corresponds to our energy costs would help
8 address a number of rate-related issues, including net
9 metering and customer conservation decisions. The emphasis
10 on moving fixed and variable prices to be more reflective
11 of fixed and variable costs led to the Company's proposals
12 to increase the monthly service charge for residential and
13 small general service customers. Since these customers are
14 not demand metered, the service charge is the only fixed
15 rate component available to adjust and thus becomes more
16 important as a tool for fixed cost recovery. The increases
17 to the service charges are a moderate step toward better
18 alignment of costs and prices. However, as described by
19 Ms. Brilz, there is still a long way to go.
20 Q. Did the Company's cost-based approach
21 influence any other ratemaking proposals?
22 A. Yes, the cost-based approach also influenced
GALE, DI 13
Idaho Power Company
1 our decision to propose seasonal and time-of-use rates for
2 certain customer groups. Both types of time-based rates
3 allow for the incorporation of time-based cost differences
4 into the Company's pricing.
5 Q. Should the Company's seasonal rate proposals
6 be adopted, is there a related issue concerning the
7 Company's Power Cost Adjustment (PCA)?
8 A. Yes, because the summer season is proposed
9 to begin on June 1 and the current PCA is scheduled to
10 change on May 16, the Company believes it would be best to
11 consolidate the two rate change dates into one. As Mr.
12 Said states in his testimony, we are proposing to move the
13 start date for each year's PCA to June 1. In addition, the
14 change would give the Commission the benefit in the future
15 of an extra two weeks to process the annual PCA
16 application.
17 Q. How has depreciation expense been treated in
18 the rate filing?
19 A. The depreciation expense in the Company's
20 general rate request includes the depreciation rates
21 contained in the Company's application filed with this
22 Commission on May 6, 2003 in Case No. IPC-E-03-07. Since
GALE, DI 14
Idaho Power Company
1 that time, a stipulation has been reached among the parties
2 regarding that case and filed with the IPUC on October 9,
3 2003. (Should the IPUC approve that stipulation, the
4 overall requested revenue requirement would adjust downward
5 to incorporate the final action).
6 Q. Have the Company and Commission Staff
7 attempted to settle other rate issues recently that may
8 have an impact on the general rate case?
9 A. Yes. The Company, the Commission Staff, and
10 the Industrial Customer of Idaho Power have reached verbal
11 agreement regarding the final settlement of issues in Case
12 No. IPC-E-01-16, a case pertaining to the relationship
13 between IE and Idaho Power, including appropriate
14 compensation to be paid by IE to Idaho Power for the use of
15 Idaho Power's transmission and capacity resources. If
16 approved, the settlement of Case No. IPC-E-01-16 will bring
17 past issues between Idaho Power and IE to closure.
18 Q. Are you generally familiar with the
19 Company's recent management efforts in the areas of
20 stewardship of the system, customer service, demand-side
21 management, and financing activity?
22 A. Yes. As described in detail by Ms. Fullen,
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Idaho Power Company
1 the Company has implemented a new business model that
2 better serves customers. That model includes changes that
3 improved outage management and communication systems,
4 improved customer service systems throughout the Company's
5 service territory, demonstrated performance of our metering
6 and billing systems, renewed focus on demand-side
7 management programs, and improved customer satisfaction
8 results.
9 On the financial side of the business, the Company
10 has utilized available opportunities to refund various
11 issues of both long-term debt and preferred stock on a
12
13
cost-effective basis.
lower embedded costs.
This has resulted in significantly
At the time of the Company's last
14 Idaho general rate case, the Company's overall cost of debt
15 capital was 8.024 percent. The Company's current cost of
16 debt capital is 5.983 percent. Mr. Gribble speaks to the
17 financing efforts in his testimony.
18 And despite all the stresses on the system both
19 internal (heightened emphasis on reliability, increased
20 demand for infrastructure investments, increasing
21 relicensing costs, poor cash flow, and negative earnings
22 implications) as well as external (major drought, out of
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Idaho Power Company
1 step inflation in energy markets, market chaos, and the
2 eventual exodus of credit worthy counterparties and
3 investment dollars), in the end, Idaho Power has honored
4 its obligation to serve our customers and keep the lights
5 on at a reasonable price. Mr. Keen's testimony describes
6 these activities and results in greater detail.
7 Q. Are there other instances of Company
8 management decisions that have been helpful to its
9 customers?
10 A. Yes. I would like to highlight two other
11 areas in which the Company has made great strides. The
12 first is our Green Power Program and the second is Idaho
13 Power's development of a comprehensive risk management
14 policy over the last two years.
15 Because of Idaho Power's hydroelectric resources,
16 our customers get most of their electricity from a resource
17 that's virtually emission-free. With the establishment of
18 our Green Power Program, customers have yet another
19 emission- free alternative -- wind power. The Green Power
20 Program is a voluntary program that allows Idaho Power
21 customers to add any dollar amount they choose to their
22 power bills to purchase resources from the Stateline Wind
GALE, DI 17
Idaho Power Company
1 Project. The Company has sponsored multiple campaigns
2 aimed at generating awareness and encouraging customers to
3 enroll in the program. Enrollment in the two-year-old
4 program has grown nearly 20 percent since the last campaign
5 bringing the number of participating subscribers to almost
6 2000.
7 The second area of Company business that I would
8 like to highlight is risk management. It became clear to
9 the Company's Risk Management Committee (RMC) during the
10 2000-2001 Energy Crisis that our risk management techniques
11 for dealing with the market and the associated drought
12 worked well in most cases but not in all. Learning from
13 this experience, the Company acquired new energy, made
14 investment to increase capacity and reliability throughout
15 the system, adopted more conservative financial policies,
16 and developed and implemented a state-of-the-art risk
17 management policy. This collaborative risk management
18 strategy protects against adverse movements in net power
19 supply costs and manages the cost of energy supply with
20 respect for the risk tolerance of stakeholders. Together,
21 these strategies will lead to more stable rates.
22 Q. Do you believe it is in the public interest
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Idaho Power Company
1 for the Commission to recognize these management efforts in
2 setting Idaho Power rates?
3 A. Yes. Traditionally, this is done by the
4 Commission adding basis points to the authorized rate of
5 return.
6 Q. In its general rate application, is the
7 Company requesting additional basis points in its
8 authorized rate of return on equity to recognize good
9 management performance?
10
11
A.
Q.
No.
How would the Company like to be recognized
12 by the IPUC for its management performance?
13 A. The Company would like to be recognized
14 through timely and positive consideration of our rate
15 relief request.
16 Q. Is it your opinion that the granting of the
17 rate relief proposed by the Company is in the public
18 interest?
19
20
21
A.
Q.
A.
Yes.
Does this conclude your testimony?
Yes.
GALE, DI 19
Idaho Power Company