HomeMy WebLinkAboutIPC-E-02-3PCA.pdfTelephone (208) 388-2674, FAX (208) 388-6936
LARRY D. RIPLEY
Senior Attorney
April 15, 2002
HAND DELIVERED
Ms. Jean D. Jewell, Secretary
Idaho Public Utilities Commission
472 West Washington Street
P. O. Box 83720
Boise, Idaho 83720-0074
Re: Case No. IPC-E-02-03
Power Cost Adjustment Filing
Dear Ms. Jewell:
Please find enclosed for filing an original and seven (7) copies of the
Company's Application for authority to implement a Power Cost Adjustment (PCA) rate for
electric service to customers in the State of Idaho for the period May 16, 2002 through
May 15, 2003. Also enclosed are nine (9) copies of the testimony and exhibits of Mr.
Gregory W. Said, with one copy designated as the Reporter's Copy. A computer disk
containing Mr. Said's testimony is also enclosed.
I would appreciate it if you would return a stamped copy of this transmittal
letter for our files.
Very truly yours,
/s/
Larry D. Ripley
LDR:jb
Enclosures
c: Parties of Record (w/enclosure)
APPLICATION, Page 1
LARRY D. RIPLEY ISB #965
Idaho Power Company
P.O. Box 70
Boise, Idaho 83707
Phone: (208) 388-2674
FAX: (208) 388-6936
Attorney for Idaho Power Company
Express Mail Address
1221 West Idaho Street
Boise, Idaho 83702
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION )
OF IDAHO POWER COMPANY FOR ) CASE NO. IPC-E-02-3
AUTHORITY TO IMPLEMENT POWER )
COST ADJUSTMENT (PCA) RATES FOR ) APPLICATION
ELECTRIC SERVICE FROM MAY 16, 2002 )
THROUGH MAY 15, 2003. )
)
Application is hereby made to the Idaho Public Utilities Commission (the
"Commission") by Idaho Power Company ("Idaho Power") for approval of two Tariff
Schedules 55 implementing a Power Cost Adjustment ("PCA") of 2.2885 cents per kWh
for the period May 16, 2002 through September 30, 2002, and a PCA of 1.9059 cents per
kWh for the period October 1, 2002 through May 15, 2003.
In support of this Application, Idaho Power represents as follows:
I.
Idaho Power is an Idaho Corporation, whose principal place of business is
1221 West Idaho Street, Boise, Idaho 83702.
APPLICATION, Page 2
II.
Idaho Power operates a public utility supplying electric service in Southern
Idaho and Eastern Oregon. Idaho Power is subject to the jurisdiction of this Commission in
Idaho and to the jurisdiction of the Oregon Public Utility Commission in Oregon. Idaho
Power is also subject to the jurisdiction of the Federal Energy Regulatory Commission (the
"FERC").
III.
On March 29, 1993, by Order No. 24806 issued in Case No. IPC-E-92-25,
the Commission approved the implementation of an annual Power Cost Adjustment
procedure.
IV.
Attachment 1 to this Application is a copy of Idaho Power's proposed new
Electric Rate Schedule, IPUC No. 26, Tariff No. 101, Schedule 55, which provides for the
implementation of a Power Cost Adjustment rate of 2.2885 cents per kWh for the period
May 16, 2002 through September 30, 2002.
V.
Attachment 2 to this Application shows in full, each proposed change from
existing rates to the May 16, 2002 rates by striking over the proposed deletions to existing
IPUC No. 26, Tariff No. 101, Schedule 55, and highlighting additions.
VI.
Attachment 3 to this Application is a copy of Idaho Power's proposed new
Electric Rate Schedule, IPUC No. 26, Tariff No. 101, Schedule 55, which provides for the
implementation of a Power Cost Adjustment rate of 1.9059 cents per kWh for the period
October 1, 2002 through May 15, 2003.
APPLICATION, Page 3
VII.
Attachment 4 to this Application shows in full each proposed change from the
rate that would become effective on May 16, 2002 to the rate that would become effective
on October 1, 2002, by striking over the proposed deletions to the IPUC No. 26, Tariff No.
101, Schedule 55, that would become effective on May 16, 2002, and highlighting
additions.
VIII.
The PCA for the period May 16, 2002 through September 30, 2002 will
consist of: (1) 90 percent of the difference between the Projected Power Cost and the
Commission's approved Base Power Cost, (2) the True-Up of the March 2001 through
March 2002 power costs, and (3) the residual PCA rate component of 0.3826 cents per
kWh which remains in effect through September 30, 2002.
IX.
The Projected Power Cost was computed by inserting the National Weather
Service Northwest River Forecast Center's April 1, 2002 projection of 3.63 million acre feet
of April through July Brownlee streamflow runoff into the Commission adopted equation for
projecting PCA expenses. The resulting Projected Power Cost of $106,509,695 equates
to a cost of 0.7634 cents per kWh. This 0.7634 cents per kWh is 0.2396 cents per kWh
higher than the Commission's approved base of 0.5238 cents per kWh. By Commission
Order No. 25880, the Company is authorized to adjust rates by 90 percent of the 0.2396
cents per kWh difference, or 0.2156 cents per kWh.
APPLICATION, Page 4
X.
The true-up component of the PCA rate is 1.6903 cents per kWh. This was
computed by dividing the total adjusted deferrals of $223,286,727 for the period March 1,
2001 through March 31, 2002 by 13,209,552 MWh, the 2000 Idaho jurisdictional firm sales
value.
XI.
In addition to the projection component and the true-up component, this
year’s PCA also included a residual PCA component due to the fact that a portion of last
year’s PCA was deferred for amortization during the October 1, 2001 through
September 30, 2002 time period. That residual PCA component that remains through
September 2002 is 0.3826 cents per kilowatt hour.
XII.
After September 30, 2002, the PCA charge would be reduced by the amount
of the residual PCA rate component and the resulting PCA would be 1.9059 cents per
kWh.
XIII.
The total change in the PCA rate for the period May 16, 2002 through
September 30, 2002 is a 0.5644 cents per kWh increase from the existing 1.7241 cents
per kWh currently in effect. This increase would subsequently be followed by a decrease in
PCA rates on October 1, 2002. At that time, the PCA would be reduced by 0.3826 cents
per kWh to 1.9059 cents per kWh.
XIV.
This Application is not subject to RP 122 in that, as set forth in RP 122.02,
this is a change in rates related to PCA expenses.
APPLICATION, Page 5
XV.
Simultaneous with the filing of this Application, Applicant has filed its direct
case consisting of the testimony and exhibits of witness Gregory W. Said. Applicant
stands ready for immediate consideration of this Application, if it is the Commission's
determination that a hearing should be held.
XVI.
If the Commission does not authorize the issuance of Energy Cost Recovery
Bonds that have been requested in Case No. IPC-E-02-2 (the docket which has been
consolidated with this proceeding), then in that event Idaho Power requests that the tariff
filing implementing the PCA rates set forth in this Application become effective May 15,
2002 and October 1, 2002.
XVII.
On March 27, 2002, the Commission issued Order No. 28988 which
provided notice of Case Nos. IPC-E-02-2 and IPC-E-02-3 (the instant proceeding). In
Case No. IPC-E-02-2 (the request for an Energy Cost Financing Order), the Company had
already issued a special notice advising its Idaho retail customers of the intent to file its
2002-2003 PCA application. The Commission, by Order No. 28995, granted Idaho
Power’s request for a waiver of a bill stuffer in Case No. IPC-E-02-3 (the instant
proceeding) upon the implementation of a communication plan. The Company has
implemented the communication plan through the placing of print ads and the issuance of
press releases. The proposed electric rate schedules, together with this Application and
the testimony and exhibits of witness Gregory W. Said, will be kept open for public
inspection at Applicant's offices in the State of Idaho. The above procedures, in
compliance with Commission Order No. 28995, are deemed by Applicant to satisfy the
APPLICATION, Page 6
Rules of Practice and Procedure of this Commission.
XVIII.
Communications with reference to this Application should be sent to the
following:
Larry D. Ripley John R. Gale
Senior Attorney Vice President, Regulatory Affairs
Idaho Power Company Idaho Power Company
P.O. Box 70 P.O. Box 70
Boise, ID 83707 Boise, ID 83707
WHEREFORE, in the event that the Commission does not authorize the
issuance of Energy Cost Recovery Bonds, Idaho Power Company respectfully requests
that the Commission authorize the implementation of a Power Cost Adjustment rate of
2.2885 cents per kWh to customers in the State of Idaho for the period May 16, 2002
through September 30, 2002, and a PCA rate of 1.9059 cents per kWh for the period
October 1, 2002 through May 15, 2003, by permitting Idaho Power's proposed Tariff
Schedules 55 to become effective on May 15, 2002 and October 1, 2002.
DATED at Boise, Idaho, this 15th day of April, 2002.
/s/
________________________________
LARRY D. RIPLEY
Attorney for Idaho Power Company
CERTIFICATE OF SERVICE
CERTIFICATE OF SERVICE
I HEREBY CERTIFY that on this 15th day of April, 2002, I served a true and
correct copy of the APPLICATION and TESTIMONY AND EXHIBITS OF GREGORY W.
SAID in Case No. IPC-E-02-3 upon the following named parties by the method indicated
below, and addressed to the following:
Lisa D. Nordstrom x Hand Delivered
Deputy Attorney General U.S. Mail
Idaho Public Utilities Commission Overnight Mail
472 W. Washington Street FAX
P.O. Box 83720
Boise, Idaho 83720-0074
R. Scott Pasley Hand Delivered
Assistant General Counsel x U.S. Mail
J.R. Simplot Company Overnight Mail
999 Main Street FAX
P.O. Box 27
Boise, Idaho 83702
Peter J. Richardson Hand Delivered
Richardson & O’Leary, PLLC x U.S. Mail
99 East State Street, Suite 200 Overnight Mail
P.O. Box 1849 FAX
Eagle, Idaho 83616
William M. Eddie Hand Delivered
Land and Water Fund of the Rockies x U.S. Mail
P.O. Box 1612 Overnight Mail
Boise, Idaho 83701 FAX
/s/
______________________________________
LARRY D. RIPLEY
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION)
OF IDAHO POWER COMPANY FOR )
AUTHORITY TO IMPLEMENT POWER ) CASE NO. IPC-E-02-3
COST ADJUSTMENT (PCA) RATES FOR )
ELECTRIC SERVICE FROM MAY 16, )
2002 THROUGH MAY 15, 2003 )
)
IDAHO POWER COMPANY
DIRECT TESTIMONY
OF
GREGORY W. SAID
SAID, DI 1
Idaho Power Company
Q. Please state your name and business address. 1
A. My name is Gregory W. Said and my business 2
address is 1221 West Idaho Street, Boise, Idaho. 3
Q. By whom are you employed and in what 4
capacity? 5
A. I am employed by Idaho Power Company as the 6
Director of Revenue Requirement in the Pricing and 7
Regulatory Services Department. 8
Q. Please describe your educational background. 9
A. In May of 1975, I received a Bachelor of 10
Science Degree with honors in Mathematics from Boise State 11
University. 12
Q. Please describe your work experience with 13
Idaho Power Company. 14
A. I became employed by Idaho Power Company in 15
1980. My first responsibility with the Company was to 16
develop the Secondary Transactions Simulation Model for use 17
in determining the average net power supply expenses 18
associated with multiple hydro conditions as well as the 19
expenses associated with each hydro condition. 20
In December 1981, the Company applied for an 21
increase in its general revenue requirement in Case No. U-22
1006-185. The Secondary Transactions Simulation Model 23
SAID, DI 2
Idaho Power Company
became the basis for determining the Company's normalized 1
net power supply expenses in that revenue requirement 2
proceeding. 3
In the next general revenue requirement 4
proceeding, Case No. U-1006-265, filed in September of 5
1985, I was the Company's power supply witness providing 6
direct and rebuttal testimony as well as direct testimony 7
upon rehearing. At the same time I was also the power 8
supply witness in the Company's Oregon jurisdictional 9
filing. 10
In 1988, the Company applied for a temporary 11
rate increase because of drought conditions. Once again, I 12
was the Company witness addressing power supply expenses. 13
In August of 1989, after nine years in the 14
Resource Planning Department, I was offered and I accepted 15
a position in the Company's Rate Department. With the 16
Company's application for a temporary rate increase in 17
1992, my responsibilities as a witness were expanded. 18
While I continued to be the Company's witness concerning 19
power supply expenses, I also sponsored the Company's rate 20
computations and proposed tariff schedules. 21
Because of my combined Resource Planning 22
Department and Rate Department experience, I was asked to 23
SAID, DI 3
Idaho Power Company
design a Power Cost Adjustment which would impact 1
customers' rates based upon changes in the Company's net 2
power supply expenses. I presented my recommendations to 3
the Idaho Public Utilities Commission in 1992 at which time 4
the Commission established the Power Cost Adjustment as an 5
annual adjustment to the Company's rates. I have sponsored 6
the Company's annual PCA adjustment for each of the years 7
1996 through 2001. 8
Q. What is the projection of PCA expenses for 9
the period April 1, 2002 through March 31, 2003? 10
A. The projection of PCA expenses for the 11
period April 1, 2002 through March 31, 2003 is 12
$106,509,695. This amount is $33,430,567 more than the 13
$73,079,128 normalized level of PCA expenses. 14
Q. What is the basis for the projection of 15
April 1, 2002 through March 31, 2003 PCA expenses? 16
A. The Commission, in Order No. 24806 issued in 17
Case No. IPC-E-92-25, the proceeding which created the PCA, 18
adopted a natural logarithmic function of projected April 19
through July Brownlee runoff to compute the projection of 20
April through March PCA expenses. The derivation of the 21
current equation is contained on Exhibit 1. The normalized 22
purchased power expense for Qualifying Facilities (“QF”) 23
SAID, DI 4
Idaho Power Company
and the normalized Astaris second block energy revenue are 1
constants, which have been included in the projection 2
computation. The current equation is: 3
PCA expense = 1,023,185,930 4
- 63,236,861 * (ln(runoff)) 5
+ 47,574,344 6
- 9,074,032 7
In this formula, the value $1,023,185,930 – 8
63,236,861 * (ln(runoff)) is the forecast of annual net 9
power supply expenses (fuel plus non-QF purchased power 10
minus surplus sales). The value $47,574,344 is a constant 11
for normalized QF purchased power expenses as established 12
in Order No. 27997 issued April 7, 1999. The value 13
$9,074,032 is the constant representing the market value of 14
power assumed to be acquired by Idaho Power Company for 15
Astaris second block loads. This amount, $9,074,032 is an 16
exact offset to the estimated cost of acquiring the power 17
for Astaris second block loads that is implicitly embedded 18
as non-QF purchased power within the annual power supply 19
expense projection. Although Idaho Power no longer 20
provides power for Astaris second block loads, it is still 21
appropriate for PCA projection purposes to assume that 22
Idaho Power will receive market value revenues of 23
SAID, DI 5
Idaho Power Company
$9,074,032 to offset the assumed $9,074,032 of non-QF 1
purchased power. Therefore, the projection computation 2
remains the same as last year. 3
Q. What is the April through July Brownlee 4
runoff forecast that you used to arrive at the projection 5
of PCA expenses? 6
A. The National Weather Service River Forecast 7
Center, in its April 1 forecast, projected April through 8
July Brownlee runoff to be 3.630 million acre feet. 9
Inserting this value into the equation results in a 10
projection of net PCA expenses of $106,509,695 for the 11
period April 1, 2002 through March 31, 2003. This amount 12
is $33,430,567 more than the normalized level of PCA 13
expenses of $73,079,128. 14
The Brownlee runoff information supplied by 15
the National Weather Service is contained on Exhibit 2. 16
The Brownlee Reservoir inflow appears on page 2, line 6 of 17
Exhibit 2. 18
Q. You have stated that the projected net PCA 19
expenses are more than the normalized level of PCA expenses 20
by $33,430,567. What is the rate adjustment associated 21
with the projected increase in PCA expenses of $33,430,567 22
from the normalized level of PCA expenses? 23
SAID, DI 6
Idaho Power Company
A. The normalized PCA expense of $73,079,128, 1
divided by the normalized system firm load of 13,952,283 2
MWHs is used to arrive at the normalized Base Power Cost of 3
0.5238 cents per kilowatt-hour. For the period April 1, 4
2002 through March 31, 2003, the projected power cost of 5
serving firm loads is 0.7634 cents per kilowatt-hour which 6
is computed by dividing the projected PCA expense of 7
$106,509,695 by the 13,952,283 MWHs normalized system firm 8
load. The Company adjusts its rates by 90 percent of the 9
difference between the projected power cost of serving firm 10
loads (0.7634 cents per kilowatt-hour) and the normalized 11
base power cost (0.5238 cents per kilowatt-hour.) Restated, 12
this year's computation is (.9)(0.7634-0.5238)=0.2156 cents 13
per kilowatt-hour. The resulting adjustment is a 0.2156 14
cents per kilowatt-hour increase from the Base Power Cost. 15
Q. Please describe the true-up required based 16
upon the comparison of the March 1, 2001 through March 31, 17
2002 actual results to last year's projections. 18
A. In Order No. 28722, the Commission granted 19
approval of the early implementation of a partial amount of 20
the 2001/2002 PCA based upon true-up values through 21
February 2001. March 2001 was left to be included in this 22
year’s computation of the true-up making this year’s true-23
SAID, DI 7
Idaho Power Company
up based upon the 13-month period March 2001 through March 1
2002. 2
The Power Cost Adjustment true-up deferral 3
for the 13-month period of March 1, 2001 through March 31, 4
2002 is shown on Exhibit 3. This sheet compares the actual 5
results to last year's projections, month by month, with 6
the differences accumulated in a deferred expense account. 7
Interest has been applied to the deferred expense account 8
monthly. The balance in the deferred expense account at 9
the end of March 2002 was $227,593,363 as shown on page 2, 10
line 83 of Exhibit 3. This is the amount that was under-11
collected during the PCA year. Under standard practice, 12
the deferral would be amortized during the May 16, 2002 13
through May 15, 2003 period. 14
Q. Did Mr. Gale instruct you to make an 15
adjustment to the booked true-up value of $227,593,363? 16
A. Yes. Mr. Gale instructed me to reduce the 17
booked true-up balance by $4,306,636. This amount is shown 18
on page 2, line 85, of Exhibit 3. Mr. Gale will discuss 19
his rationale for this adjustment in his testimony. When 20
the $227,593,363 is reduced by $4,306,636, the resulting 21
true-up value is $223,286,727. 22
Q. How is the adjusted true-up expense of 23
SAID, DI 8
Idaho Power Company
$223,286,727 reflected in the true-up portion of the PCA 1
rate? 2
A. In accordance with Order No. 26455 from Case 3
No. IPC-E-96-5, the true-up rate component would be 4
calculated by dividing the adjusted deferred expense 5
balance of $223,286,727 by the 1993 normalized Idaho 6
jurisdictional firm sales of 10,802,636 MWHs. Due to the 7
magnitude of last year's true-up component, the Commission 8
in Order No. 28722 authorized the use of a more current 9
normalized Idaho jurisdictional firm sales volume for 10
calculating the true-up portion of the PCA rate. This 11
year’s true-up portion of the PCA is also large. 12
Therefore, the Company proposes to again use a more current 13
normalized Idaho jurisdictional firm sales value for this 14
year's true-up rate component. The Company recommends the 15
use of 2000 normalized Idaho jurisdictional firm sales. 16
The use of the 2000 normalized Idaho jurisdictional firm 17
sales number would result in the following calculation for 18
the true-up portion of the rate: $223,286,727 (adjusted 19
deferred expense account balance) ÷ 13,209,552 (normalized 20
Idaho jurisdictional firm sales for 2000 in MWHs) = 1.6903 21
cents per kilowatt-hour. 22
Q. In addition to the projected power cost 23
SAID, DI 9
Idaho Power Company
component and the true-up component is there a third 1
component to PCA rate determinations for this year. 2
A. Yes. This year there is a residual PCA 3
component of 0.3826 cents per kilowatt-hour, which is the 4
incremental PCA rate that was deferred in April of 2001 and 5
later approved in September of 2001. This residual PCA 6
rate component remains in effect through September 30, 7
2002. 8
Q. What is the PCA rate that would become 9
effective May 16, 2002 as a result of (1) the adjustment 10
for the 2002/2003 projected power cost of serving firm 11
loads, (2) the 2001/2002 true-up portion of the PCA and (3) 12
the residual PCA component that remains in effect through 13
September 2002? 14
A. The Company's PCA rate for May 16, 2002 15
through September 30, 2002 would be 2.2885 cents per 16
kilowatt-hour. The rate is comprised of (1) the 0.2156 17
cents per kilowatt-hour adjustment for 2002/2003 projected 18
power cost of serving firm loads, (2) the adjustment of 19
1.6903 cents per kilowatt-hour for the 2001/2002 13-month 20
true-up portion of the PCA and (3) the 0.3826 cents per 21
kilowatt-hour residual PCA component that ceases on 22
October 1, 2002. On October 1, 2002, the Company’s PCA 23
SAID, DI 10
Idaho Power Company
rate would become 1.9059 cents per kilowatt-hour for the 1
period October 1, 2002 though May 15, 2003 as a result of 2
the ending of the residual PCA component. 3
The components used to calculate the 2.2885 4
cents per kilowatt-hour for the period May 16, 2002 through 5
September 30, 2002, are shown in the Company's potential 6
Schedule 55 for the period May 16, 2002 through 7
September 30, 2002, that is Exhibit 4. 8
Q. How does the May 16, 2002 through 9
September 30, 2002 PCA rate of 2.2885 cents per kilowatt-10
hour compare to the 2001/2002 PCA rate? 11
A. The 2002/2003 PCA rate of 2.2885 cents per 12
kilowatt-hour is a 0.5644 cents per kilowatt-hour increase 13
from the 1.7241 cents per kilowatt-hour rate presently in 14
effect. Of the 0.5644 cents per kilowatt-hour increase, 15
0.3826 cents per kilowatt-hour would cease on October 1, 16
2002. Exhibit 5 is the potential tariff schedule that 17
would become effective from October 1, 2002 through May 15, 18
2003. 19
Q. What would be the percentage increase to 20
customer rates on May 16, 2002, if the Commission approved 21
the PCA rate of 2.2885 cents per kilowatt-hour? 22
A. The average percentage increase over all 23
SAID, DI 11
Idaho Power Company
customer classes would be 10.1 percent on May 16, 2002. A 1
percentage decrease of 6.2 percent would later occur on 2
October 1, 2002. 3
Q. Is the Company's recommendation a rate 4
increase of 10.1 percent resulting from a PCA rate of 5
2.2885 cents per kilowatt-hour based upon traditional PCA 6
computation methodology? 7
A. No. Mr. Gale will provide testimony 8
addressing the Company’s primary proposal to remove a 9
portion of PCA true-up amounts related to voluntary load 10
reduction programs for separate funding via the issuance of 11
bonds. The Company’s primary proposal as described by Mr. 12
Gale would result in a rate decrease of 6.6 percent on 13
May 16, 2002 rather than a rate increase of 10.1 percent 14
that would result from standard PCA treatment. 15
My computation of a PCA rate of 2.2885 cents 16
per kilowatt-hour is provided as information for the 17
Commission. If the Company's primary proposal as detailed 18
by Mr. Gale were rejected, then the Company would expect 19
traditional PCA treatment (the Company's secondary 20
proposal) resulting in the PCA rate of 2.2885 cents per 21
kilowatt-hour. 22
Q. Of the true-up balance, how much is related 23
SAID, DI 12
Idaho Power Company
to the voluntary load reduction programs for Astaris and 1
irrigation customers? 2
A. The portion of the true-up balance 3
attributable to the Astaris voluntary load reduction is 4
$76,253,930. The portion of the true-up balance 5
attributable to voluntary irrigation load reduction is 6
$70,610,462. 7
Q. Were the deferrals associated with the two 8
voluntary load reduction programs determined in an 9
identical manner? 10
A. No. The Astaris amount is equal to 90 11
percent (sharing) of the Idaho jurisdictional portion (85 12
percent) of the direct payments to Astaris for voluntary 13
load reduction. The Irrigation amount is also equal to 90 14
percent (sharing) of the Idaho jurisdictional portion (85 15
percent) of direct payments to irrigation customers, but 16
also includes 90 percent of the Idaho jurisdictional 17
portion of reduced irrigation revenues resulting from 18
voluntary load reductions. The reduced irrigation revenues 19
are an additional cost of the Irrigation class voluntary 20
load reduction program. The cost of the Astaris voluntary 21
load reduction does not include reduced revenues due to the 22
take or pay provisions of the Astaris contract. 23
SAID, DI 13
Idaho Power Company
Q. Does this conclude your testimony? 1
A. Yes, it does. 2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
Case No. IPC-E-02-3
Idaho Power Company
Current Regression
Exhibit No. 1
G. Said
Multiple R.0.920131533
R. Square 0.846642039
Adjusted R.0.844207785
Standard Err.12,686,495.39
df
Regression 1
Residual 63
Coefficients
Intercept 1,023,185,930
Observation Predicted Y
1 1928 6,750,571 15.72514 6,241,000$ 1 28,777,582.78
2 1929 3,516,226 15.07290 60,671,000$ 2 70,023,119.69
3 1930 2,730,186 14.81988 82,320,000$ 3 86,023,216.51
4 1931 2,252,206 14.62742 106,526,000$ 4 98,193,754.89
5 1932 4,693,051 15.36159 77,389,000$ 5 51,766,976.26
6 1933 4,072,824 15.21985 80,101,000$ 6 60,730,566.58
7 1934 2,284,655 14.64173 101,827,000$ 7 97,289,161.20
8 1935 3,091,888 14.94429 103,686,000$ 8 78,155,781.45
9 1936 4,976,479 15.42023 75,854,000$ 9 48,058,785.13
10 1937 3,027,697 14.92331 89,454,000$ 10 79,482,468.23
11 1938 6,995,998 15.76085 38,288,000$ 11 26,519,320.02
12 1939 3,340,542 15.02164 69,283,000$ 12 73,264,336.78
13 1940 4,217,857 15.25484 67,478,000$ 13 58,517,873.22
14 1941 3,812,543 15.15381 67,679,000$ 14 64,906,741.28
15 1942 4,777,672 15.37946 61,084,000$ 15 50,636,902.28
16 1943 9,358,641 16.05181 10,512,000$ 16 8,119,808.02
17 1944 3,363,907 15.02861 63,258,000$ 17 72,823,574.16
18 1945 5,107,273 15.44618 22,367,000$ 18 46,418,231.91
19 1946 6,864,248 15.74184 27,110,000$ 19 27,721,565.26
20 1947 5,145,808 15.45369 42,921,000$ 20 45,942,893.05
21 1948 5,701,715 15.55628 40,564,000$ 21 39,455,764.68
22 1949 5,284,463 15.48028 41,482,000$ 22 44,261,513.24
23 1950 6,666,559 15.71261 24,971,000$ 23 29,569,514.38
24 1951 6,887,280 15.74519 24,297,000$ 24 27,509,738.22
25 1952 10,645,884 16.18068 16,180,000$ 25 (29,731.86294)
26 1953 6,266,915 15.65079 30,786,000$ 26 33,478,793.54
27 1954 5,375,988 15.49745 44,669,000$ 27 43,175,650.00
28 1955 3,663,733 15.11399 58,885,000$ 28 67,424,444.03
29 1956 7,679,163 15.85402 19,935,000$ 29 20,627,397.13
ANOVA
RESIDUAL OUTPUT
Regression Statistics
SUMMARY OUTPUT
Exhibit No. 1
Case No. IPC-E-02-03
Page 1 of 2
30 1957 8,142,974 15.91267 19,918,000$ 30 16,918,876.92
31 1958 7,347,318 15.80985 33,513,000$ 31 23,420,898.63
32 1959 3,990,168 15.19934 58,383,000$ 32 62,027,129.72
33 1960 4,207,224 15.25231 63,415,000$ 33 58,677,491.36
34 1961 2,917,876 14.88637 88,633,000$ 34 81,818,836.92
35 1962 4,838,084 15.39203 59,122,000$ 35 49,842,307.34
36 1963 4,901,728 15.40510 51,038,000$ 36 49,015,863.44
37 1964 6,173,173 15.63572 30,226,000$ 37 34,431,851.43
38 1965 8,808,795 15.99126 5,756,000$ 38 11,948,764.14
39 1966 3,085,249 14.94214 71,438,000$ 39 78,291,711.64
40 1967 5,295,808 15.48243 37,363,000$ 40 44,125,898.10
41 1968 3,178,096 14.97179 53,367,000$ 41 76,416,744.51
42 1969 6,851,881 15.74003 29,438,000$ 42 27,835,598.96
43 1970 6,400,738 15.67192 12,586,000$ 43 32,142,656.32
44 1971 11,081,252 16.22077 5,243,000$ 44 (2,564,349.539)
45 1972 8,051,202 15.90133 15,647,000$ 45 17,635,608.09
46 1973 3,795,548 15.14934 22,988,000$ 46 65,189,259.52
47 1974 9,837,354 16.10170 6,450,000$ 47 4,965,130.655
48 1975 8,899,862 16.00155 6,411,000$ 48 11,298,365.63
49 1976 7,742,737 15.86227 15,129,000$ 49 20,106,029.07
50 1977 2,036,372 14.52668 95,568,000$ 50 104,564,260.80
51 1978 5,885,210 15.58795 46,375,000$ 51 37,452,710.71
52 1979 3,662,618 15.11369 47,708,000$ 52 67,443,692.11
53 1980 6,180,456 15.63690 16,932,000$ 53 34,357,289.68
54 1981 3,880,244 15.17141 52,133,000$ 54 63,793,670.22
55 1982 9,629,565 16.08035 5,952,000$ 55 6,315,156.637
56 1983 10,537,116 16.17041 2,348,000$ 56 619,676.3765
57 1984 12,447,717 16.33705 2,971,000$ 57 (9,917,693.726)
58 1985 5,467,688 15.51437 28,551,000$ 58 42,106,094.18
59 1986 8,603,101 15.96763 17,008,000$ 59 13,442,920.55
60 1987 2,657,135 14.79276 76,325,000$ 60 87,738,280.12
61 1988 2,461,731 14.71638 104,676,000$ 61 92,568,546.41
62 1989 4,426,855 15.30320 58,475,000$ 62 55,459,598.19
63 1990 2,853,052 14.86390 98,643,000$ 63 83,239,557.72
64 1991 2,622,549 14.77966 101,823,000$ 64 88,566,792.34
65 1992 1,798,651 14.40255 125,185,000$ 65 112,414,032.80
AVERAGE 48,039,308$
Exhibit No. 1
Case No. IPC-E-02-03
Page 2 of 2
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
Case No. IPC-E-02-3
Idaho Power Company
National Weather Service
April 1 Forecast
Exhibit No. 2
G. Said
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
Case No. IPC-E-02-3
Idaho Power Company
True-up Deferral
Exhibit No. 3
G. Said
Power Cost Adjustment SummaryMarch 2001 thru March 2002 March April May June July August September October November December January February March Totals
PCA Revenue
Normalized Firm Load 1,106,080 991,176 1,033,117 1,143,545 1,352,219.00 1,422,263 1,206,799 1,112,398 1,030,835 1,162,545 1,229,083 1,162,223 1,106,080 15,058,363.00PCA Component Rate 1.832 1.832 3.861 3.861 3.861 3.861 3.861 3.861 3.861 3.861 3.861 3.861 3.861Revenue at 85%1,722,388 1,543,459 3,390,535 3,752,943 4,437,779.93 4,667,654 3,960,533 3,650,723 3,383,046 3,815,298 4,033,666 3,814,242 3,629,989 45,802,256.05
Load Change Adjustment
Actual Firm Load - Adjusted Mwh 1,144,140 1,099,682 1,270,223 1,441,473 1,508,747.00 1,522,447 1,185,500 1,128,174 1,128,733 1,366,447 1,334,814 1,160,746 1,167,079 16,458,205.00Normalized Firm Load Mwh 1,106,080 991,176 1,033,117 1,143,545 1,352,219.00 1,422,263 1,206,799 1,112,398 1,030,835 1,162,545 1,229,083 1,162,223 1,106,080 15,058,363.00Load Change Mwh 38,060 108,506 237,106 297,928 156,528.00 100,184 (21,299)15,776 97,898 203,902 105,731 (1,477)60,999 1,399,842.00
Expense Adjustment (@ 16.84)(640,930)(2,323,930)(3,992,865)(5,017,108)(2,635,931.52)(1,687,099)358,675 (265,668)(1,648,602)(3,433,710)(1,780,510)24,873 (1,027,223)(24,070,027.92)
Actual Non-QF PCA Expense Adjustment $-640930.4 -2323929.68 -3992865.04 -5017107.52 -2635931.52 -1687098.56 358675.16 -265667.84 -1648602.32 -3433709.68 -1780510.04 24872.68 -1027223.16 -24070027.92Purchased Water $0 0 0 0 0.00 0 0 0 0 0 0 0 0 0.00
Programs Cost $0 7,537,706 15,880,037 18,910,578 27,746,298.13 35,314,980 25,136,737 19,991,481 4,636,639 13,751,072 6,358,463 5,314,643 5,352,489 185,931,123.16Mobile Generation Costs $0 0 1,147,773 25,695 1,194,966.08 760,180 1,394,432 724,228 259,098 (14,829)0 0 0 5,491,543.11
Fuel Expense-Coal $7,981,848 6,449,302 7,085,494 8,852,816 9,318,032.28 8,463,943 6,768,167 7,651,354 8,034,974 8,226,471 9,870,768 8,685,919 8,976,730 106,365,817.30Fuel Expense-Gas $0 0 0 0 238,000.00 244,400 255,406 288,880 494,980 764,613 297,464 286,648 467,163 3,337,553.12Non-Firm Purchases $23,797,993 27,531,814 39,544,151 53,042,177 55,013,781.29 45,317,057 34,270,507 1,158,901 5,628,068 8,014,917 8,387,471 1,279,841 1,864,327 304,851,006.01
Quantified Purchase from BPA $0 0 0 0 0.00 0 0 1,148,546 0 0 0 0 0 1,148,546.00Surplus Sales $(37,298,224)(32,471,710)(15,652,344)(6,494,509)(29,581,147.87)(31,151,673)(25,075,684)(3,856,654)(4,375,317)(3,010,640)(8,059,153)(1,525,463)(7,368,672)(205,921,191.08)
FMC 2'nd Blk Engy-Cmdty Price Only $0 0 0 0 0.00 0 0 0 0 0 0 0 0 0.00Total Non-QF $(6,159,313.15)6,723,182.74 44,012,246.46 69,328,768.34 61,284,878.98 57,261,788.48 43,108,240.05 26,841,068.26 13,029,839.25 24,297,893.92 15,074,503.35 14,066,459.17 8,264,813.85 377,134,369.70
BASEFuel Expense $4,737,000 3,341,000 2,293,000 2,843,000 5,076,000.00 6,445,000 5,587,000 6,026,000 6,909,000 7,127,000 6,051,000 5,051,000 4,737,000 66,223,000.00
Non-Firm Purchases $296,000 339,000 1,356,000 1,872,000 2,473,000.00 1,252,000 615,000 162,000 345,000 844,000 879,000 642,000 296,000 11,371,000.00Surplus Sales $(2,742,000.00)(3,195,000.00)(597,000.00)(208,000.00)(142,000.00)(595,000.00)(1,570,000.00)(3,022,000.00)(3,883,000.00)(2,809,000.00)(2,978,000.00)(2,781,000.00)(2,742,000.00)(27,264,000.00)FMC 2'nd Blk Engy-Cmdty Price Only $(889,475.62)(826,062.77)(979,683.11)(693,150.51)(600,808.00)(745,141.45)(664,245.01)(742,239.84)(625,639.68)(739,128.10)(799,266.67)(769,197.02)(889,475.62)(9,963,513.40)
Net 90% Items $1,401,524.38 (341,062.77)2,072,316.89 3,813,849.49 6,806,192.00 6,356,858.55 3,967,754.99 2,423,760.16 2,745,360.32 4,422,871.90 3,152,733.33 2,142,802.98 1,401,524.38 40,366,486.60
Change From Base $(7,560,837.53)7,064,245.51 41,939,929.57 65,514,918.85 54,478,686.98 50,904,929.93 39,140,485.06 24,417,308.10 10,284,478.93 19,875,022.02 11,921,770.02 11,923,656.19 6,863,289.47 336,767,883.10
Sharing Percentage 90%90%90%90%90%90%90%90%90%90%90%90%90%
Idaho Allocation 85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%
Non-QF Deferral $(5,784,040.71)5,404,147.82 32,084,046.12 50,118,912.92 41,676,195.54 38,942,271.39 29,942,471.07 18,679,240.70 7,867,626.38 15,204,391.85 9,120,154.06 9,121,596.98 5,250,416.45 257,627,430.57
Actual QF (Includes Meridian Amort)$3,306,679 4,026,365 5,245,969 2,913,630 5,787,563.41 5,480,579 4,342,465 3,160,426 2,396,464 2,540,236 2,649,442 2,357,414 2,334,218 46,541,449.28
Base QF $1,314,445 2,038,265 3,024,735 5,108,325 5,317,475.00 5,059,785 3,531,295 2,438,425 1,539,895 1,713,885 1,567,845 1,459,785 1,314,445 35,428,605.00Change From Base $1,992,234 1,988,100 2,221,234 (2,194,695)470,088.41 420,794 811,170 722,001 856,569 826,351 1,081,597 897,629 1,019,773 11,112,844.28
Quantified Benefit from BPA $0 0 0 0 0.00 0 0 95,049 (128,604)0 0 0 0 (33,555.00)
Total Non-shared Deferral $1,992,234 1,988,100 2,221,234 (2,194,695)470,088.41 420,794 811,170 817,050 727,965 826,351 1,081,597 897,629 1,019,773 11,079,289.28
Sharing Percentage 100%100%100%100%100%100%100%100%100%100%100%100%100%Idaho Allocation 85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%85.0%
QF Deferral $1,693,399 1,689,885 1,888,049 (1,865,491)399,575.15 357,675 689,494 694,493 618,770 702,398 919,357 762,985 866,807 9,417,395.89
Mobile Home Metering Costs $0 0 0 0 18,637.71 10,450 10,184 6,641 8,841 11,665 14,353 12,909 12,849 106,528.87Intervenor Funding $0 0 0 0 9,661.84 20,134 0 0 0 0 0 0 0 29,796.03Credit From IDACORP Energy $0 0 0 0 (166,666.67)(166,667)(166,667)(166,667)(166,667)(166,667)(166,667)(166,667)(166,667)(1,500,000.03)
Total Deferral $(5,813,029.65)5,550,573.45 30,581,560.23 44,500,478.65 37,499,623.64 34,496,209.85 26,514,949.13 15,562,983.84 4,945,524.80 11,936,490.59 5,853,531.46 5,916,582.68 2,333,416.60 219,878,895.28
Principal Balances
Beginning Balance ***$0.00 (5,813,029.65)(262,456.21)30,319,104.02 74,819,582.68 112,319,206.32 146,815,416.17 173,330,365.30 188,893,349.14 193,838,873.94 205,775,364.53 211,628,896.00 217,545,478.67 0.00
Amount Deferred $(5,813,029.65)5,550,573.45 30,581,560.23 44,500,478.65 37,499,623.64 34,496,209.85 26,514,949.13 15,562,983.84 4,945,524.80 11,936,490.59 5,853,531.46 5,916,582.68 2,333,416.60 219,878,895.28
Ending Balance $(5,813,029.65)(262,456.21)30,319,104.02 74,819,582.68 112,319,206.32 146,815,416.17 173,330,365.30 188,893,349.14 193,838,873.94 205,775,364.53 211,628,896.00 217,545,478.67 219,878,895.28
Interest Balances Accrual thru Prior Month $0.00 0.00 (42,626.42)(36,824.61)114,770.91 478,928.60 1,029,351.92 1,763,613.64 2,622,418.47 3,574,526.58 4,452,630.45 5,566,121.57 6,626,535.11
Monthly Interest Rate **6.00%6.00%6.00%6.00%6.00%6.00%6.00%6.00%6.00%6.00%6.00%6.00%6.00%
Monthly Interest Inc/(Exp)$0.00 (29,065.15)(1,312.28)151,595.52 374,097.91 561,596.03 734,077.08 866,651.83 944,466.75 969,194.37 1,028,876.82 1,058,144.48 1,087,727.39 7,746,050.75Prior Month's Interest Adjustments $0.00 (13,561.27)7,114.09 0.00 (9,940.22)(11,172.72)184.64 (7,846.99)7,641.36 (91,090.50)84,614.30 2,269.06 204.94 (31,583.31)
Total Current Month Interest $0.00 (42,626.42)5,801.81 151,595.52 364,157.69 550,423.31 734,261.72 858,804.84 952,108.11 878,103.87 1,113,491.12 1,060,413.54 1,087,932.33 7,714,467.44
Interest Accrued to date $0.00 (42,626.42)(36,824.61)114,770.91 478,928.60 1,029,351.92 1,763,613.64 2,622,418.47 3,574,526.58 4,452,630.45 5,566,121.57 6,626,535.11 7,714,467.44 Balance in All Accounts $(5,813,029.65)(305,082.63)30,282,279.41 74,934,353.59 112,798,134.93 147,844,768.09 175,093,978.94 191,515,767.62 197,413,400.52 210,227,994.98 217,195,017.57 224,172,013.79 227,593,362.72 227,593,362.72
* Negative amounts indicate benefit to the ratepayers.Pricing Adjustment (4,306,635.82)(4,306,635.82)
** Interest rate changed per IPUC Order 24806.***Beginning balance per IPUC Order 28358 223,286,727 223,286,726.90
Exhibit No. 3
Case No. IPC-E-02-03
Page 1 of 1
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
Case No. IPC-E-02-3
Idaho Power Company
Schedule 55
Power Cost Adjustment
Effective 5-16-02 thru 9-30-02
Exhibit No. 4
G. Said
IDAHO POWER COMPANY TENTH REVISED SHEET NO. 55-1
CANCELS
I.P.U.C. NO. 26, TARIFF NO. 101 NINTH REVISED SHEET NO. 55-1
IDAHO Issued by IDAHO POWER COMPANY
Issued – April 15, 2002 John R. Gale, Vice President, Regulatory Affairs
Effective – May 16, 2002 1221 West Idaho Street, Boise, Idaho
SCHEDULE 55
POWER COST ADJUSTMENT
APPLICABILITY
This schedule is applicable to the electric energy delivered to all Idaho retail Customers served
under the Company’s schedules, to the primary portion of the FMC Special Contract, and to all other
Idaho retail Special Contracts. These loads are referred to as "firm" load for purposes of this schedule.
BASE POWER COST
The Base Power Cost of the Company's rates is computed by dividing the Company's power
cost components by firm kWh load. The power cost components are the sum of fuel expense and
purchased power expense (including purchases from cogeneration and small power producers), less
the sum of off-system surplus sales revenue and FMC secondary load revenue. The Base Power Cost is
0.5238 cents per kWh.
PROJECTED POWER COST
The Projected Power Cost is the Company estimate, expressed in cents per kWh, of the power
cost components for the forecasted time period beginning April 1 each year and ending the following
March 31. The Projected Power Cost is 0.07634 cents per kWh.
TRUE-UP
The True-up is based upon the difference between the previous Projected Power Cost and the
power costs actually incurred. The True-up is 2.0729 cents per kWh.
POWER COST ADJUSTMENT
The Power Cost Adjustment is 90 percent of the difference between the Projected Power Cost
and the Base Power Cost plus the True-up.
The monthly Power Cost Adjustment applied to the Energy rate of metered schedules and
Special Contracts is 2.2885 cents per kWh. The monthly Power Cost Adjustment applied to the per unit
charges of the nonmetered schedules is the monthly estimated usage times 2.2885 cents per kWh.
EXPIRATION
*The Power Cost Adjustment included on this schedule will expire September 30, 2002.
BEFORE THE
IDAHO PUBLIC UTILITIES COMMISSION
Case No. IPC-E-02-3
Idaho Power Company
Schedule 55
Power Cost Adjustment
Effective 10-01-02
Exhibit No. 5
G. Said
IDAHO POWER COMPANY ELEVENTH REVISED SHEET NO. 55-1
CANCELS
I.P.U.C. NO. 26, TARIFF NO. 101 TENTH REVISED SHEET NO. 55-1
IDAHO Issued by IDAHO POWER COMPANY
Issued – April 15, 2002 John R. Gale, Vice President, Regulatory Affairs
Effective – October 1, 2002 1221 West Idaho Street, Boise, Idaho
SCHEDULE 55
POWER COST ADJUSTMENT
APPLICABILITY
This schedule is applicable to the electric energy delivered to all Idaho retail Customers served
under the Company’s schedules, to the primary portion of the FMC Special Contract, and to all other
Idaho retail Special Contracts. These loads are referred to as "firm" load for purposes of this schedule.
BASE POWER COST
The Base Power Cost of the Company's rates is computed by dividing the Company's power
cost components by firm kWh load. The power cost components are the sum of fuel expense and
purchased power expense (including purchases from cogeneration and small power producers), less
the sum of off-system surplus sales revenue and FMC secondary load revenue. The Base Power Cost is
0.5238 cents per kWh.
PROJECTED POWER COST
The Projected Power Cost is the Company estimate, expressed in cents per kWh, of the power
cost components for the forecasted time period beginning April 1 each year and ending the following
March 31. The Projected Power Cost is 0.7634 cents per kWh.
TRUE-UP
The True-up is based upon the difference between the previous Projected Power Cost and the
power costs actually incurred. The True-up is 1.6903 cents per kWh.
POWER COST ADJUSTMENT
The Power Cost Adjustment is 90 percent of the difference between the Projected Power Cost
and the Base Power Cost plus the True-up.
The monthly Power Cost Adjustment applied to the Energy rate of metered schedules and
Special Contracts is 1.9059 cents per kWh. The monthly Power Cost Adjustment applied to the per unit
charges of the nonmetered schedules is the monthly estimated usage times 1.9059 cents per kWh.
EXPIRATION
*The Power Cost Adjustment included on this schedule will expire May 15, 2003.