20080416Said Direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPAN FOR
AUTHORITY TO IMPLEMENT POWER
COST ADJUSTMENT (PCA) RATES FOR
ELECTRIC SERVICE FROM MAY 16,
2008 THROUGH MAY 15, 2009
CASE NO. IPC-E-08-07
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
GREGORY W. SAID
1 Q.Please state your name and business address.
2 A.My name is Gregory W. Said 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 as the
7 Manager of Revenue Requirement in the Pricing and Regulatory
8 Services Department.
9 Q.Please describe your educational background.
10 A.In May of 1975, I received a Bachelor of
11 Science Degree in Mathematics with honors from Boise State
12 University. In 2003, I attended the Public Utility
13 Executives Course at the University of idaho.
14 Q.Please describe your work experience with
15 Idaho Power Company.
16 A.I became employed by Idaho Power Company in
17 1980 as an analyst in the Resource Planning Department. In
18 1985, the Company applied for a general revenue requirement
19 increase. I was the Company wi tness addressing power supply
20 expenses.
21 In August of 1989, after nine years in the
22 Resource Planning Department, I was offered and I accepted a
23 position in the Company's Rate Department. With the
24 Company's application for a temporary rate increase in 1992,
25 my responsibilities as a witness were expanded. While I
SAID, DI 1
Idaho Power Company
1 continued to be the Company witness concerning power supply
2 expenses, I also sponsored the Company's rate computations
3 and proposed tariff schedules in that case.
4 Because of my combined Resource Planning and
5 Rate Department experience, I was asked to design a Power
6 Cost Adjustment (PCA) which would impact customers' rates
7 based upon changes in the Company's net power supply
8 expenses. I presented my recommendations to the idaho Public
9 Utilities Commission (IPUC) in 1992 at which time the IPUC
10 established the PCA as an annual adjustment to the Company's
11 rates. i sponsored the Company's annual PCA adjustment in
12 each of the years 1996 through 2004. i supervised the
13 preparation of PCA testimony presented by Ms. Schwendiman in
14 years 2005 through this year.
15 Q.Are you the same Gregory Said that presented
16 power supply and PCA testimony in the Company i s last general
17 revenue requirement case, IPUC Case No. IPC-E-07-08 ("07-08
18 case" ) ?
19 A.Yes. In my testimony in the 07-08 case, i
20 discussed changes in loads and resources since the Company's
21 last general revenue requirement case, IPC-E-OS-28, and the
22 impact of those changes on the Company's power supply
23 expenses. In the 07-08 case I sponsored the exhibits that
24 provided the basis for determining the Company's normalized
25 net power supply expenses for ratemaking purposes. i also
SAID, DI 2
Idaho Power Company
1 discussed how the new normalized power supply expenses will
2 impact future PCA computations until the Company's next
3 general revenue requirement case.
4 Q.Why are you providing testimony in addition
5 to the testimony Ms. Schwendiman is presenting in this
6 proceeding?
7 A.Ms. Schwendiman' s testimony provides the PCA
8 computations required to determine PCA rates for the June 1,
9 2008 through May 31, 2009 time period consistent with
10 standard Commission-approved methodology. However, in this
11 case, the Company is requesting a one-year deviation from
12 standard Commission-approved methodology. My testimony
13 describes the Company's request for the one-year deviation
14 and the reasons that the Company is making the request for
15 the one-year deviation.In addi tion to the standard PCA
16 computations, I instructed Ms. Schwendiman to compute the
17 PCA based upon this deviation in methodology. Ms.
18 Schwendiman' s testimony provides the PCA computations
19 required to determine a PCA rate using both standard
20 computations and the Company's proposed alternative.
21 Q.With the Commission's approval of the 2007
22 test year settlement stipulation in the 07-08 case, what is
23 the normalized level of net power supply expenses currently
24 reflected in the Company's base rates?
25 A.As per the settlement stipulation, a
SAID, DI 3
idaho Power Company
1 normalized net power supply expense level of $41.0 million
2 and a normalized PURPA project expense level of $93.1
3 million are currently reflected in the Company's base rates.
4 Q.How are deviations from normalized PURPA
5 expenses and normalized net power supply expenses reflected
6 in PCA computational methodology?
7 A. As actual PURPA and power supply expenses are
8 incurred, 100 percent of the deviation in actual PURPA
9 expenses from base levels and 90 percent of the deviation in
10 net power supply expenses from the forecast level are
11 recorded in the deferral account.
12 For purposes of the Company's April 2008
13 through March 2009 forecast of PCA expenses, PURPA expenses
14 are assumed to be at the normalized level, $93.1 million,
15 with no anticipated deviation. In the forecast, net power
16 supply expenses are determined by the regression formula
17 described in Ms. Schwendiman' s testimony. The forecast
18 component of the PCA rate reflects 100 percent, or zero
19 change, in PURPA expenses from base and 90 percent of the
20 $18.7 million change in forecast net power supply expenses
21 below base net power supply expenses.
22 Q.Have all of the new PURPA wind proj ects that
23 were included in the test year determination of power supply
24 expenses in the 07-08 case come on-line as anticipated?
25 A.No. Apparently a numer of wind projects
SAID, DI 4
idaho Power Company
1 initially signed contracts to be on-line by the end of 2007
2 in order to receive tax credit benefits that required an on-
3 line date prior to December 31, 2007. Once the tax credit
4 benefits were extended, the wind proj ects sought to have
5 their contracts amended to allow for later on-line dates.
6 As a result, 62 average megawatts of energy that the Company
7 had envisioned receiving in 2008 from new PURPA projects,
8 will not be available and the Company will be forced to
9 replace this amount of energy with purchases from the
10 market.
11 Q.How will these reduced PURPA purchases and
12 increased market purchases be reflected in the PCA?
13 A.One hundred percent of the benefits of
14 reduced PURPA purchases will flow through the PCA to the
15 benefit of customers while only 90 percent of the increased
16 market purchases will flow through the PCA to customers.
17 The Company estimates that PURPA expenses will be decreased
18 by nearly $30 million dollars and that replacement energy
19 from the market will exceed $40 million. The Company will
20 not be able to recover $1 million for every $10 million of
21 additional purchased power expense.
22 Q.What does the Company propose as a solution
23 to this problem?
24 A.The Company is requesting that for a one year
25 period of time, all deviations in net power supply and
SAID, DI 5
Idaho Power Company
1 PURPA expenses from levels included in base rates be tracked
2 at 100 percent for both forecast and true-up purposes.
3 Q.Is there precedent for such an interim
4 approach to one PCA item?
5 A.Yes. In Order No. 30508 the Commission
6 approved the settlement of rate case and PCA issues that
7 included a one year interim resolution regarding the load
8 growth adjustment rate (LGAR) contained in the PCA true-up.
9 In the Stipulation, the parties expressed their desire to
10 undertake further good faith discussions prior to next
11 year's PCA filing to address shortcomings of the LGAR
12 methodology. In Order No. 30508, the Commission expressed
13 its support for the parties' pursuit of good faith
14 discussions on this PCA issue. The Company believes that
15 the PCA sharing percentage is another potential PCA issue
16 that should be addressed in a workshop environment.
17 Q.Are there other reasons why Idaho Power
18 believes a one year deviation from the standard 90%-10%
19 sharing of PCA costs and benefits should be approved?
20 A.Yes. At the time of this annual filing of
21 the PCA, the Company has already committed to a number of
22 purchase and sales hedging transactions in accordance with
23 its Commission-approved Risk Management Guidelines. Hedging
24 activity is not reflected in base rates and as is the case
25 with PURPA purchases, compliance with the risk management
SAID, DI 6
Idaho Power Company
1 policy is not subject to discretionary action, but is rather
2 prescriptive in nature. At this time, the Company has a net
3 hedging purchase position of nearly $51 million. Only 90
4 percent of this known amount will naturally flow through the
5 PCA true-up mechanism.
6 Q.Does the prescriptive nature of the Company's
7 hedging procedures have any implication for the 90%-10%
8 sharing provision in the PCA?
9 A.Yes. As a result of the settlement of Case
10 No. IPC-E-01-16, the Company's hedging for both overall
11 system risk (in dollars) and volumetric risk (in MWh' s) has
12 been executed under very speci fic, Commission-approved
13 procedures. Prior to the implementation of these
14 procedures, the Company had discretion regarding the timing
15 of advance purchase or sale of energy. This discretion was
16 the primary rationale for the 90%-10% sharing ratio as a
17 means to provide the Company with an incentive to make wise
18 decisions with regard to the purchase or sale of energy.
19 With the onset of the prescriptive buying and selling
20 methodology embodied in the Risk Management Policy, the
21 concept of providing incentives to encourage wise decisions
22 based upon the Company's market price view has been greatly
23 diminished. It is the Company's belief that because of the
24 prescriptive risk management policy 100% pass-through of PCA
25 expenses to customers is appropriate.
SAID, DI 7
Idaho Power Company
1 Q.Does the accuracy of PCA expense forecasts
2 since the initial PCA forecast in 2003 impact the Company
3 recommendation for a one~year deviation?
4 A.Yes. True-up amounts for the first seven
5 years (1994 through 2000) were never more than $15.5 million
6 above or below the forecast. During the energy crisis years
7 of 2000 and 2001, the subsequent year true-ups 2001 and 2002
8 were $185.6 million and $223.3 million respectively. In the
9 years 2004 through 2007, the true-up has not been less than
10 $35 million.
11 Q.Have the large true-ups in years 2001 through
12 2007 corresponded with near normal streamflow conditions?
13 A.No. Six of the eight years 2000 through 2007
14 were drought conditions with hydro generation in the lowest
15 20 percent of historical conditions. Only one year, 2006
16 was above the middle 20 percent of historical conditions and
17 one other year, 2000, was near normal. Over the eight year
18 period of time (2000 through 2007) tracking at 90 percent
19 rather than 100 percent has cost the Company nearly $100
20 million in unrecovered power supply expenses. Prolonged
21 drought conditions have not resulted in sYmetrical
22 deviations from normalized levels reflected in base rates.
23 Q.Please summarize the rationale for one year
24 tracking of deviations in net power supply and PURPA
25 expenses as proposed by the Company.
SAID, DI 8
Idaho Power Company
1 A.The Company believes that in light of
2 persistent drought conditions, the lack of inclusion of
3 prescriptive hedging acti vi ties in PCA forecast methodology,
4 and the failure of a number of PURPA proj ects to come on-
5 line as envisioned in the last approved test year, it would
6 be appropriate for the Commission to allow 100 percent
7 tracking of net power supply and PURPA expenses in the
8 2008/2009 PCA year.
9 Q.What is the impact of the Company
10 recommendation to allow 100 percent tracking of net power
11 supply and PURPA expenses for the 2008/2009 PCA year on the
12 quantification of the PCA rate contained in Ms.
13 Schwendiman' s testimony.
14 A.The computation of the true-up and true-up of
15 the true-up components of the PCA are unaffected this year.
16 The computation of the forecast rate, based upon 100%
17 deviation of forecast power supply expenses from levels
18 included in base rates, is a negative 0.1314 cents per
19 kilowatt-hour as compared to Ms. Schwendiman's computation
20 of a negative 0.1183 cents per kilowatt-hour for the 90%-10%
21 sharing method.
22 Using 100% tracking provides the Company's
23 customers with an immediate benefit due to a forecasted
24 Brownlee runoff that is greater than the historical average
25 runoff underlying base rates. if the actual year power
SAID, DI 9
idaho Power Company
1 supply expenses fall below base rate levels, customers will
2 see additional benefits in next year's true-up computations.
3 However, if the continued impacts of drought, continued
4 deferrals of PURPA generation and prescriptive hedging
5 activity results in positive actual power supply expense
6 levels, the Company will be protected against another year
7 of aSYmetric recovery of power supply expenses.
8 Q.Does the Company view this 100 percent
9 tracking of deviations in net power supply and PURPA
10 expenses for one year as a response to a one-time problem?
11 A.It should come as no surprise that because
12 of increased volatility in power supply expenses the Company
13 believes that the 90%-10% sharing of PCA costs and benefits
14 is not working as well today as it did in 1992 when the PCA
15 was first implemented. The Company has addressed the
16 problems associated with the 90%-100% sharing in the
17 testimony of Mr. Steve Keen in the last two general rate
18 cases (IPC-E-OS-28 and IPC-E-07-08). idaho Power believes
19 that its one-year recommendation should be approved and the
20 previously ordered LGAR workshops be expanded to include
21 discussions as to appropriate PCA sharing levels into the
22 future, as well as other methodological changes to the PCA.
23 Q.Does this conclude your testimony?
24 A.Yes.
SAID, DI 10
idaho Power Company