20080107Smith rebutttal.pdf

2008 JAN -4 PI.l
t¡ 4: 36
UTid 0 PUBLICCOMM/SSIO; ¡
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF IDAHO POWER COMPAN FOR
AUTHORITY TO INCREASE ITS RATES
AND CHAGES FOR ELECTRIC SERVICE
TO ELECTRIC CUSTOMERS IN THE STATE
OF IDAHO.
CASE NO. IPC-E-07-8
IDAHO POWER COMPAN
DIRECT REBUTTAL TESTIMONY
OF
LORI SMITH
1 Q.Please s tate your name.
2 A.My name i sLor i Smith.
3 Q.Are you the same Lori Smith that presented
4 direct testimony in this proceeding?
5 A.Yes.
6 Q.What issues will you be responding to in your
7 rebuttal testimony?
8 A.My testimony explains why the Company's
9 forecast test year in this case better reflects the
10 operating conditions the Company expects to experience
11 during the time rates will be in effect rather than Staff's
12 proposed historic test year. i will also provide
13 information on the Company's 2007 fourth quarter results
14 that provides additional validation as to the accuracy of
15 the Company's forecasted revenue requirement. In response
16 to Staff witness Carlock's concern regarding the absence of
17 any quantification of harm caused by regulatory lag, i will
18 provide an overview of the economic impacts of regulatory
19 lag on Idaho Power Company. Finally, I will respond to
20 several adjustments proposed by other parties.
21 Q.Staff recommends use of an historic test year
22 to determine Idaho Power's rates. Why is it important that
23 the test period and the rate-effective period closely match
24 each other?
25 A.To provide the Company a reasonable
SMITH, DI-REB 1
IDAHO POWER COMPAN
1 opportunity to earn its allowed rate of return, the new
2 rates would ideally take effect with the commencement of the
3 test year. With this underlying premise in mind, the
4 Company filed the forecast test year based on its intimate
5 knowledge of the contributing factors that hinder the
6 Company's ability to earn its allowed rate of return. These
7 factors include the costs of load growth that currently
8 outpace revenue that can be obtained with the rates set
9 based on an historical test year or a hybrid test year. As
10 a result of load growth, the Company has the need to acquire
11 new generating resources, build transmission lines and
12 stations for reliability purposes, and maintain our aging
13 existing resources in an environment of rising costs.
14 Q.Do you believe the Company's forecast used to
15 determine its proposed test year is reasonable?
16 A.Yes. The Company's forecast is: 1) grounded
17 on a consistent forecast methodology utilized by the
18 Company; 2) reflective of realistic and systematic cost and
19 revenue proj eçtions; 3) supported by expenditure forecasts
20 that are developed and supported at the operating levels of
21 the Company; 4) and has been scrutinized by business unit
22 management and the Idaho Power Company management.
23 Q.Please explain how idaho Power Company's test
24 year forecast is grounded in consistent forecast
25 methodology?
SMITH, DI-REB 2
IDAHO POWER COMPAN
1 A.The 2007 test period began by using
2 historical information for the year ending December 31,
3 2006. From the base year, each of the revenue requirement
4 components was normalized or adjusted to reflect
5 expectations for 2007 financial and operating activities.
6 This forecast process used the same process that has been in
7 place for several years to produce financial forecasts that
8 are used by idaho Power's management.
9 Q.Does the forecasted data the Company used to
10 support its application for rate relief reflect realistic
11 and systematic cost and revenue projections?
12 A.Yes. The normalized revenues and net power
13 supply expense estimation process is the same that has been
14 used in prior cases when a historical or hybrid test year
15 has been filed. Additionally, the proj ections relied upon
16 in this application are integrally tied to the operations
17 and management of the Company. It is based on the same
18 information that management sees in carrying out its
19 responsibilities. Some select financial measurements in
20 this application are also used for providing metrics to the
21 financial community. The Company strives to be as accurate
22 as possible in the data that it presents.
23 Q.Has the preparation of the Company's forecast
24 test year in this case been closely scrutinized?
25 A.Yes. For the reasons i have just described,
SMITH, DI-REB 3
IDAHO POWER COMPAN
1 there has been great attention to detail in the preparation
2 of this forecast. Every effort has been made to provide an
3 appropriate explanation and support of the forecasted
4 components included in this forecast test year. Throughout
5 the preparation of the forecast, we have used a "bottom-up"
6 approach to ensure that the business units that will build,
7 operate and maintain the system during the rate effective
8 period are in agreement with the proj ected levels of
9 expendi ture .
10 Q.Is it possible to produce a test year that is
11 free from the uncertainty of prediction?
12 A.No. All rate proceedings inherently have a
13 level of estimates, anticipated adjustments or modeling
14 outputs that are based on assumptions and inputs from
15 predictive models. The use of an historic test year does
16 not remove this issue from a revenue requirement proceeding.
17 Historical test years include estimates for annualizing and
18 known and measurable adjustments to the rate effective
19 period. These adjustments require the Commission to
20 exercise informed judgment about how to best project future
21 data or adjust historical data to reflect conditions in the
22 rate effective period. The process, whether one uses an
23 historic period or forecast period, is the same.
24 Q.Do you have any other general observations
25 about the use of a forecast test year?
SMITH, DI-REB 4
IDAHO POWER COMPAN
1 A.Yes. Idaho Power Company finds itself in a
2 period of both rising capital and O&M costs. These costs
3 are best captured in the forecast test year period. These
4 escalating costs cannot be offset with efficiency gåins,
5 attrition, or cost cutting. Rates should be set for
6 customers today that match the cost to serve those customers
7 today. A business that doesn' t recover its current costs
8 will financially under-perform. This has been the
9 experience of the Company for several years, even given two
10 general rate increases since 2003.
11 The regulatory lag inherent in an historical
12 or a partial forecast test year does not currently permit
13 rates that are commensurate with a cost structure that is
14 rising to meet electrical needs of a growing customer base.
15 My testimony demonstrates that the Company has applied a
16 rational, systematic and comprehensive approach in
17 forecasting its test year requirement. I continue to
18 believe for purposes of this proceeding, a forecast test
19 year beginning January 1, 2007 and ending December 31, 2007,
20 is the most appropriate. Even the use of a 2007 forecast
21 test year establishes rates that will not take affect until
22 2008.
23 Q.Can you please provide an update of key
24 capital expenditure and expense results through November
25 2007 that validates the forecasted values contained in the
SMITH,DI-REB 5
IDAHO POWER COMPAN
1 forecast test year used by the Company?
2 A.Yes. I have obtained actual data for several
3 significant components of the forecast test year. This
4 actual data is for the periods June year-to-date (YTD),
5 September YTD, and November YTD. I then compared thi s
6 actual data to the Forecast Test Year Total the Company
7 filed. The components I have selected are key variables
8 that Mr. Said uses to determine the Total System revenue
9 requirement and ultimately the Idaho jurisdictional revenue
10 requirement. The primary components I have included are
11 Electric Plant in Service excluding Asset Retirement
12 Obligations (ARO) (EPIS), Accumulated Provision for
13 Depreciation and Amortization, Net Electric Plant in
14 Service, Other Operating Revenues, Operation and Maintenance
15 Expenses (O&M), Depreciation and Amortization, and IERCO
16 operating net income.
YTD YTD YTD Forecast
June Sept Nov Test Year
2007 2007 2007 Total
EPIS $3,647,262,730 $3,708,539,029 $3,788,785,684 $3,778,910,294AccumulatedProvisionforDepreciation
andAmortization 1,600,383,439 1,624,352,106 1,635,886,117 1, 607,824,827
Net EPIS 2,046,879,291 2,084,186,923 2,152,899,567 2,171,085,467
OtherOperating
Revenues 25,504,551 39,293,118 48,827,366 60,368,018
O&M Expenses 151,514,351 224,846,522 271,001,079 290,673,032
Depreciation
and 50,902,708 76,869,380 94,307,122 104,120,916
SMITH, DI-REB 6
IDAHO POWER COMPAN
Amortization
IERCO Net
Income 1,815,205 2,917,192 4,661,020 5,248,215
Q.What conclusion do you draw from this table1
2 of actual components compared to the forecast test year
3 total?
4 A.I believe this information supports the
5 Company's forecast test year and adequately reflects the
6 operating costs and capital expenditures that Idaho Power
7 Company is currently experiencing to operate effectively.
8 By the end of 2007, the Company will have made significantly
9 more capital investments of prudently incurred property
10 plant and equipment and will have spent significantly more
11 operating expenses to provide reliable service to its
12 customers. The forecast test year is a more reasonable
13 representation from which to set rates for the coming year
14 to effectively provide the Company the opportunity to earn
15 its allowed rate of return established by the Commission.
16 Q.Other wi tnesses have used the term regulatory
17 lag. Please define your understanding of the term
18 "regulatory lag" as it applies to this proceeding.
19 A.Regulatory lag occurs when there is a
20 mismatch between the time period used for test year
21 calculations and when resulting rates go into effect. For
22 purposes of this proceeding, I am using the term regulatory
23 lag or attrition as a "decline in the rate of return earned
24 ***(occurring) when rate base and/or cost of service
SMITH, DI-REB 7
IDAHO POWER COMPAN
1 increases faster than revenue and is caused both by
2 inflation and by expansionistic construction programs which
3 do not generate additional comparable revenue". Utah Power
4 & Light v. Idaho Public Utili ties Commission, 102 Idaho 282
5 (1981) .
6 Q.In reviewing Staff's testimony in which it
7 presents its revenue requirement recommendations, do you
8 believe Staff's recommendations create regulatory lag?
9 A.Yes. The Company has incurred significant
10 expenses and made substantial capital investments that it
11 will have no opportunity to recover if the Commission
12 accepts Staff's recommendations. Staff has filed a test
13 year based on 12 months ending June 2007 for rates to be in
14 effect late in the first quarter of 2008. Staff's filing
15 also includes many timing mismatches between revenue,
16 expenses and plant identified in Mr. Gale's, Mr. Steve
17 Keen's, and Mr. Said's testimony. The annualizing and known
18 and measurable -adjustments Staff proposes only address a
19 limited numer of items where timing mismatches occur. When
20 regulatory lag exists, it places financial pressure on the
21 Company by reducing its cash flow and rate of return.
22 Q.Can you provide a hypothetical example and
23 timeline of how regulatory lag associated with rate base
24 items impacts idaho Power Company?
25 A.Yes. Assume that a utility has constructed
SMITH, DI-REB 8
IDAHO POWER COMPAN
1 an asset for a total cost of $10 million including allowance
2 for funds used during construction (AFUDC). The asset was
3 constructed over three years and was placed in service in
4 April of 2007. Further assume that the company also files
5 for rate relieve using a 2007 forecasted test year with
6 rates expected to be in effect by January 2008.
7 Because the asset is placed in service nine
8 months prior to rate recovery, the company experiences
9 regulatory lag. When the asset is placed in service in
10 April 2007, regulatory accounting requires that the company
11 no longer record AFUDC which capitalizes the cost of
12 financing the asset's construction by recording income.
13 Assuming a 10-year book life, the company records months of
14 depreciation expense totaling $750,000 ($10 million divided
15 by 120 months multiplied by 9 months) in 2007. In the
16 company's 2007 forecast test year, the asset is included in
17 rate base net of accumulated depreciation at $9,250,000 ($10
18 million original cost less $750,000 of depreciation
19 expense). Because the asset is not reflected in rates until
20 January 2008, the company will not recover the $750,000 in
21 depreciation expense taken in 2007 and will not earn its
22 authorized rate of return on that asset for those 9 months
23 in 2007.
24 Let us say that one assumption in the
25 hypothetical changes. The company waits until the end of
SMITH, DI-REB 9
IDAHO POWER COMPAN
1 2007 and files for rate relief with 2007 actual test year
2 data and does not expect a rate increase until October 2008.
3 In this case, the company would still include $9,250,000
4 ($10 million original cost less $750,000 of depreciation
5 expense) in rate base in its 2007 test year filing. The
6 company continues to record depreciation expense and forgoes
7 AFUDC through 2008. Because rates do not go into effect
8 until October 2008, the company never recovers the
9 depreciation expense of $1,500,000 (18 months - April 2007
10 through September 2008). During those 18 months, the company
11 does not earn its authorized rate of return on that asset.
12 I would note that as Mr. LaMont Keen notes in
13 his testimony, the Company is in a period of significant
14 plant growth due to customer growth, generation and
15 transmission requirements identified in the Company's 2006
16 Integrated Resource Plan, and the rising costs of preserving
17 the Company's existing power plants and transmission and
18 distribution infrastructure. This growth is expected to
19 continue well into the future. From 2000 to 2006, Idaho
20 Power's net plant has grown at an annualized rate of 4.7%
21 with $520 million in new plant added over that period of
22 time. Normalized system sales have grown at an annualized
23 rate of 1.3% over the same period.
24 Q.Staff recommends using a 13 month average for
25 the period ending June 2007 to determine Total Electric
SMITH, DI-REB 10
IDAHO POWER COMPAN
1 Plant in Service. Can you demonstrate the impact this
2 methodology has on regulatory lag?
3 A.Yes.Staff's use of a test period ending
4 June 2007 with electric plant included on the basis of 13
5 month averages, results in adverse regulatory lag. By
6 comparing Staff's proposal of Electric Plant in Service
7 (EPIS) to actual results as of November 2007, the impact of
8 regulatory lag on the Company's authorized return can be
9 demonstrated. For purposes of this analysis, annualizing
10 and known and measurable adjustments by Staff have been
11 included for illustrative purposes only and should not be
12 construed as my agreement with these adjustments.Staff's
,13 13 month average EPIS using a June 2007 year end and
14 including adjustments equals $2,065,138,126. Because
15 December 2007 actual EPIS is not available, actual November
16 2007 results will be used for comparison purposes. Very
17 conservatively, no adjustments have been made for
18 annualizing or known and measurable adjustments. Actual
19 Electric Plant in Service as of November 2007 equals
20 $2,152,899,567. The difference of $87,761,441 is the amount
21 of EPIS on which the Company has no opportunity to earn a
22 just and reasonable return. The table below quantifies the
23 amount of under recovery using both Staff proposed Weighted
24 Average Cost of Capital (WACC) and Company-proposed WACC.
25 / / /
SMITH, DI-REB 11
IDAHO POWER COMPAN
1
Difference
WACC
Tax Gross-up
Under Recovery
Staff WACC
$87,761,441
7.864%
1.642
$11,332,610
IPC WACC
$87,761,441
8.561%
1.642
$12,337,039
2
3 Because of the short time period available to
4 prepare rebuttal testiomany, I have not had the opportunity
5 to fully analyze and demonstrate the effects of regulatory
6 lag associated with all aspects of EPIS. The above
7 calculation demonstrates only the return component
8 associated with the mismatch of EPIS with the time the rates
9 will be in effect. with growing EPIS, other items would
10 also experience under-recovery due to regulatory lag. These
11 items include depreciation expense and the monthly adding of
12 EPIS beginning in January 2008 which could also be
13 quantified. However, because of time constraints they have
14 not been quantified.
15 Q.Can you provide an example of how the adverse
16 effects of regulatory lag associated with O&M impacts the
17 financial integrity of Idaho Power?
18 A.Yes. Regulatory lag associated with O&Mis
19 most clearly demonstrated with an example comparing Other
20 O&M included in Idaho Power's 2007 forecasted test year with
21 the 20D8 Other O&M forecast."Other O&M" isa subset of
22 Total Operating and Maintenance Expenses.
SMITH, DI-REB 12
IDAHO POWER COMPAN
1 In the Company's 2007 forecasted test year,
2 Other O&M was included at $288,932,502 before adjustments.
3 To properly compare the amount to the 2008 estimate which
4 excludes demand side management (DSM) and pension expense,
5 DSM ($15,732,910 from Schwendiman - Exhibit 25) and pension
6 ($4,607,443 from Schwendiman - Exhibit 25) must be removed.
7 Annualizing and known and measurable adjustments from Smith
8 - Exhibit 18 must be added. Finally, an assumption of 1.8%
9 for normalized load growth from 2007 to 2008 is
10 incorporated. The result is that Idaho Power would expect
11 to receive $281,316,961 in 2008 if new rates were in effect
12 beginning in January 2008. See accompanying Exhibit 69 for
13 the full calculation.
14 The Company's board approved 2008
15 expenditures in the amount of $282,104,200 excluding DSM
16 programs. Pension expense is no longer recorded. The
17 Company's 2008 operational incentive payment is expected to
18 be $6,535,000. The total of these amounts ($288,639,200)
19 can then be compared to the revenue amount ( $ 281, 316, 931 )
20 expected to be received. The shortfall amount of $7,322,239
21 is the result of adverse regulatory lag and will never be
22 recovered by the Company.
23 Q.Can you perform the same analysis you
24 described in your answer to the prior question to address
25 Staff's proposed Other O&M?
SMITH, DI-REB 13
IDAHO POWER COMPAN
1 A.Yes. I believe Staff begins with 12 months
2 ending June 2007 Other O&M which equals $281,559,388. Staff
3 then makes negative adjustments totaling $11,660,268 in
4 reductions. My inclusion of these adjustments is only for
5 illustrative purposes and should not be construed as my
6 agreement to these adjustments. Staff adjusted Other O&M is
7 then grown at 1.8% to reflect growth in normalized load from
8 2007 to 2008 to estimate growth in recovery. The result is
9 that IPC would expect to receive $274,757,304 in 2008 if new
10 rates were in effect beginning in January 2008. See
11 accompanying Exhibit 70 for the full calculation.
12 Idaho Power's board approved its 2008 expenditures
13 in November 2007. The total approved was $282,104,200
14 excluding DSM programs. Pension expense is no longer
15 recorded and not included. The Company's 2008 operational
16 incentive is expected to be $6,535,000. The total of these
17 amounts ($288,639,200) can then be compared to the amount
18 ($274,757,304) expected to be received under Staff proposal.
19 The shortfall of $13,881,896 is the result of adverse
20 regula tory lag and wi 1 1 never be recovered by the Company.
21 Thus, Staff's position further exacerbates the already
22 negative current impact of regulatory lag on Other O&M by
23 approximately $6.6 million.
24 Q.Idaho Power included annualizing adjustments
25 for payroll and known and measurable adjustments for a 2008
SMITH, DI-REB 14
IDAHO POWER COMPAN
1 salary structure adjustment (SSA) (Smith - Exhibit 18).
2 Don't these adjustments eliminate regulatory lag associated
3 wi th Other O&M?
4 A.No. These adjustments only address specific
5 payroll issues. Labor is only 42% of the 2008 O&M budget.
6 The annualizing adjustment for payroll simply adjusts test
7 year p¿yroll expense to reflect December 2007 employment
8 levels. It does not consider growth in the number of
9 employees in 2008 and related increases to employee
10 benefits. The SSA is a known and measurable adjustment
11 recognizing that the Company would be increasing salaries to
12 continue to attract and retain high quality employees in the
13 labor markets in which it operates. On November 15, 2007
14 the IPC Board of Director's approved a 3.25% SSA effective
15 December 15, 2007. The SSA adjustment used in the Company's
16 filing was 3.00%.
17 The Company makes no adjustments to Other O&M
18 to reflect addItional costs expected in 2008 which include
19 but are not limited to growth in employment levels to serve
20 a growing customer base and to maintain additional
21 infrastructure, increased compliance costs for Sarbanes-
22 Oxley Act of 2002 and the FERC's Code of Conduct rules,
23 inflation, and other cost increases to support growth and
24 maintain reliability.
25 Q.Please describe regula tory lag impacts
SMITH, DI-REB 15
IDAHO POWER COMPAN
1 associated with the PCA's load growth adjustment rate (LGAR)
2 and its impact on the financial health of idaho Power
3 Company.
4 A.LGAR, also referred to as Expense Adjustment
5 Rate for Growth (EARG), is another significant source of
6 adverse regulatory lag for idaho Power. It disallows
7 collection of net power supply costs that are necessary to
8 serve increases in load for any reason, whether driven by
9 customer or weather related growth. Under the current PCA
10 methodology, as long as the Company has load growth between
11 the test year used for determining base rates and the time
12 those rates are in effect, the mismatch will result in an
13 adverse impact from regulatory lag.
14 The resulting adverse impact from regulatory
15 lag from this mechanism is a permanent loss to IPC and is
16 the result of two mismatches. First, the mechanism compares
17 normalized system load from the most recent test year with
18 actual system load which includes both customer growth,
19 weather volatility, and any other factors affecting demand.
20 Historical PCA information back to 1997 was readily
21 available and since 1997, actual system load has always been
22 higher than normalized system load included in rates which
23 resulted in the under recovery of prudently incurred net
24 power supply costs. Second, the difference between
25 normalized system load and actual system load is multiplied
SMITH, DI-REB 16
IDAHO POWER COMPAN
1 by a rate that is greater than what is being collected in
2 general rates.
3 To illustrate the two components of LGAR's
4 regulatory lag, please consider the analysis of 2007 year to
5 date through November as presented On Exhibit 71 - Column 7.
6 Through November 2007, actual system load has exceeded
7 normalized system load established in the 2005 rate case by
8 946,884 MWs. From January through March, differences were
9 multiplied by $16.84 with the rate changing as a result of
10 IPUC Order No. 30215 to $29.41 for April through November.
11 After jurisdictionalization and sharing, the Company
12 increased its PCA deferral expense by $22,072,707. The
13 offset to this expense is what is collected through base
14 rates. The embedded rate currently being collected for
15 PURPA power purchase contracts and other variable power
16 supply costs equals $6.81 per MW. When multiplied by the
17 change in load adjusted for losses, the Company has
18 collected $5,582,405 on the increased load. When netted,
19 the LGAR mechanism results in a pretax loss to IPC of
20 $16,490,302 contributing to the Company's inability to earn
21 its authorized rate of return.
22 Q.Has the PCA's LGAR mechanism ever resulted in
23 a benefit to Idaho Power?
24 A.To the best of my knowledge, the LGAR has
25 never resulted in a benefit to the Company for a total
SMITH, DI-REB 17
IDAHO POWER COMPAN
1 calendar year or a total PCA year (April through March) .
2 Exhibit D shows an extended analysis of LGAR beginning in
3 2001 through November 2007, the LGAR mechanism net of what
4 is recovered through base rates has resulted in a cumulative
5 pretax loss of $71.4 million which will be never recovered
6 by Idaho Power and has contributed to the Company's
7 inability to earn its authorized rate of return. This
8 combined with the 10% sharing of non-PURPA net power supply
9 costs above base non-PURPA net power supply costs places
10 extraordinary financial pressure on idaho Power during a
11 time of continuing drought and growing system load.
12 Q.You mentioned that the 10% sharing of non-
13 PURPA net power supply costs above base net non-PURPA power
14 supply costs adversely impacts the Company's finances. What
15 is financial impact of regulatory lag associated with non-
16 PURPA qualifying net power supply costs for the 11 months
17 ending November 2007?
18 A.IPC monitors regulatory lag associated with
19 the PCA closely. In addition to LGAR described above,
20 during years where actual net non-PURPA power supply costs
21 are different than base net non-PURPA costs, the difference
22 is shared with ratepayers. IPC absorbs 10% of the
23 difference while ratepayers receive 90%. This lag could be
24 positive or negative. For the 11 months ending November
25 2007, the actual non-PURPA net power supply costs equal
SMITH, DI-REB 18
IDAHO POWER COMPAN
1 $206,331,061 as compared to $39,936,874 for base non-PURPA
2 net power supply costs. The difference of $166,394,187 is
3 jurisdictionalized and shared between idaho ratepayers and
4 the Company. After jurisdictionalization and the 10%
5 sharing, IPC' s bears $15,657,693 of these costs which
6 contribute to the Company's inability to earn its authorized
7 rate of return.
8 For the ,II months ending November 2007 i the
9 sum of the effects resulting from LGAR and for the non-PURPA
10 net power supply costs is a loss of $32,147,995 on a pretax
11 basis. After tax, the loss to the Company is $19,578,128
12 which will never be recovered. The regulatory lag
13 attributable to the PCA reduces the Company's 2007 return on
14 November 30, 2007 equi ty by 1. 6%.
15 Q.What would the Company estimate the financial
16 impact of the LGAR on 2008 assuming a "normal" condition for
17 load growth?
18 A.As quantified in Mr. Said's direct rebuttal
19 testimony, the Company expects that a "normal" 2008
20 condition would result in load growth of 273,425 megawatt-
21 hours served at an additional expense of $7.9 million. In
22 Mr. Said's direct testimony, the "embedded" cost, and thus
23 what is collected, for both PURPA and non-PURPA variable
24 power supply costs is $8.59 per MW. The following
25 quantifies the financial impact of the LGAR under the
SMITH, DI-REB 19
IDAHO POWER COMPAN
1 various proposals in this proceeding.
2
Load Growth
Load Growth
Adjustment Rate
LGAR Charge
LGAR Charge (AfterJurisdictionalizationand Sharing)
Estimated Collection:
Load Growth
Less estimatedsystem lossesEstimated Sales
Ida.ho
Jurisdictional %
II Emedded II Cos t
Estimated Collection
Under Recovery
3
2008
IPC
273,425
$29.16
$6,795,450
$5,791,762
Staff ICIP - Reading
273,425 273,425
$62.79 $67.74
$17,168,356
$14,632,590
$18,521,810
$15,786,138
273,425 273,425 273,425
(21,874)(21,874)(21,874)
251,551 251,551 251,551
94.7%94.7%94.7%
238,219 238,219 238,219
$8.59 $8.59 $8.59
$2,046,299 $2,046,299 $2,046,299
($3,745,463)($12,586,290)($13,739,839)
4 As presented above, LGAR immediately results
5 in a detriment to the Company if LGAR is set at any value
6 above "embedded" cost and the Company is experiencing
7 growth. Even with IPC's proposed rate, the Company
8 experiences a $3,745,463 loss while the rate proposed by
9 Staff and Reading results in a more severe impact. In
10 addition, the Company bears 10% of the $7.9 million cost to
11 serve the additional load.
12 Q.Are you familiar with Staff witness English's
13 testimony regarding FAS 87 and the removal of capitalized
SMITH, DI-REB 20
IDAHO POWER COMPAN
1 pension expense from rate base?
2 A.Yes.
3 Q.Please explain what FAS 87 is.
4 A.In 1985 the Financial Accounting Standards
5 Board issued FAS 87. This standard required companies to
6 record pension expense on an accrual basis rather than a
7 cash basis. The standard also defined a methodology for
8 calculating the net periodic pension cost (FAS 87 expense)
9 that, in simplistic terms, reflects the current year's
10 accrual of pension benefits by employees plus increases in
11 the net present value of the obligation to pay benefits
12 already accrued to employees less returns on investments
13 held by the pension plan.
14 Q.Wha tis your understanding 0 f Mr. Eng li sh ' S
15 recommendations?
16 A.In his testimony Mr. English recommends the
17 removal from rate base of $5,833,205 of pension costs the
18 Company capitalized from 2003 through 2007, net of
19 accumulated depreciation on that amount. He also recommends
20 the removal of $162,316 from depreciation expense related to
21 the annual depreciation of the capitalized FAS 87 pension
22 costs he would remove from rate base.
23 Q.Do you agree with Mr. English's
24 recommendation?
SMITH, DI-REB 21
IDAHO POWER COMPAN
1 A.No. Mr. English's proposed reduction in rate
2 base would result in a $5,833,205 write-off to Idaho Power's
3 plant-in-service and a charge to 2008 income for that same
4 amount.
5 Q.Do you believe it is appropriate for Staff to
6 make a retroactive rate base adjustment extending back to
7 2003?
8 A.No. Staff is proposing to retroactively
9 remove amounts previously included in rate base. An after-
10 the-fact adjustment to prior periods is unreasonable because
11 it requires that the Company go back in time to disallow
12 amounts recorded in prior periods, creates a mismatch of
13 expenses and revenues, and results in a retroactive
14 adjustment to the Company's financial records that will be
15 recognized as a reduction in 2008 earnings.
16 Q.Why did Idaho Power continue to capitalize a
17 portion of pension expense under FAS 87 after the 2003 rate
18 caSe?
19 A.Idaho Power is required to keep its
20 books in compliance with the FERC's Uniform System of
21 Accounts codified in the Code of Federal .Regulations
22 (CFR). The Idaho Commission has by order, adopted the
23 FERC Uniform System of Accounts for Idaho regulatory
24 accounting purposes. The Code of Federal Regulations
25 prescribes that applicable pension expenses should be
SMITH, DI-REB 22
IDAHO POWER COMPAN
1 allocated to electric plant and capitalized.
2 Q. Mr. English asserts that in the 2003
3 rate case, the Commission intended to order Idaho Power
4 to remove all FAS 87 pension expenses for rates. Do
5 you agree?
6 A.No. In Order 29505, issued May 25, 2004, the
7 Commission did not disallow any capitalized pension expense
8 and did not remove depreciation expense related to
9 capitalized pension costs, nor did it forbid the Company
10 from capitalizing a portion of pension expense in future
11 years. Had the Commission intended to disallow capitalized
12 pension expense from rate base, one might have expected the
13 Commission to order the removal of prior years' capitalized
14 pension expense from rate base at the same time it denied
15 recovery of FAS 87 expense. Had the Commission asked
16 removal from rate base, the Company would then have had the
17 opportunity to explain why it is proper to capitalize
18 pension expense at that time and the effect upon the Company
19 of such a removal requirement. The Company has complied
20 with Order No. 29505 as it was written and issued by the
21 Commission. Mr. English argues that he "believers) it was
22 the Commission's intent to remove all of FAS 87 pension
23 expense from rates." In fact the issue was never raised or
24 addressed in the 2003 rate case and the final Order in this
SMITH, DI-REB 23
IDAHO POWER COMPAN
1 case was silent on the issue of capitalizing pension
2 expense.
3 Q.Did the Commission state in Order No. 29505
4 that Idaho Power must remove capitalized pension expense
5 from rate base or that idaho Power would not be permitted to
6 capitalize pension expense?
7 A.No. In Order 29505, the Commission ordered
8 that the revenue requirement be reduced by the amount of
9 pension expense to reduce the test year pension plan
10 expenses to zero. No amount was required to be removed from
11 rate base related to capitalized pension expense. Idaho
12 Power did advise the Commission it had removed $2,014,489
13 from rate base for 2003 in its Notification of Computational
14 Errors in Establishing the Company's Revenue Requirement
15 filed with the Commission on June 11, 2004.
16 Q.Mr. English stated in his testimony that
17 Staff was unaware that pension expense was being
18 capitalized. Did Idaho Power intentionally conceal this
19 information from the Commission?
20 A.Of course not. Idaho Power did not conceal
21 this information from the Commission. Idaho Power has
22 recorded pension expense to account 926200, which is a
23 separate account used only for pension expense.It has been
24 a long-standing practice of Idaho Power, and a standard
25 industry practice based on the above cited CFR direction, to
SMITH, DI-REB 24
IDAHO POWER COMPAN
1 allocate amounts recorded in Account 926 to various other
2 accounts, including construction work in process. Mr.
3 English recognized this historic practice in his testimony
4 on page 8, "idaho Power routinely capitalizes a portion of
5 its benefits as overhead." Likewise, Idaho Power's
6 capitalization of pension overhead was a routine practice
7 that was not hidden from the Commission.
8 Q.Do you agree with Mr. English's statement on
9 page 9 of his testimony that, "The FAS 87 pension expense is
10 an accrual of pension expense that the Company is required
11 to record on its books for annual reporting purposes. It
12 has no bearing on the amount of money the Company is
13 required to contribute to the pension plan."
14 A.No. FAS 87 pension expense and the amount of
15 money a company is required to contribute to the plan are
16 not unrelated numers. Both reflect costs to the company
17 for operating the plan - one on an accrual basis and one on
18 a cash basis. They are both impacted by the same factors -
19 the amount of money invested to date and the returns on
20 those investments, employee count and salary growth, etc.
21 Furthermore, over the life of a pension plan, the amount of
22 cash contributed to the pension plan and the amount of FAS
23 87 pension expense recorded (without respect to a
24 capitalized portion) must be equal. While there are
25 significant timing differences between the two amounts, it
SMITH, DI-REB 25
IDAHO POWER COMPAN
1 is disingenuous to imply that the two items are completely
2 unrelated.
3 Furthermore, the flow of cash contributions
4 by a company into a pension trust is not the best reflection
5 of the cost of having a pension plan. The intent of a
6 pension plan is to attract and retain employees. As
7 employees work, they accrue benefits that must be paid to
8 them at a future date. In reality this accrual of benefits
9 occurs fairly smoothly with a generally increasing slope as
10 inflation and employee growth slowly increase the rate at
11 which these benefits accrue. In contrast, cash payments to
12 a plan can be very lumpy and occur in some years, but not
13 others based upon market returns, cash needs of the company
14 and minimum funding requirements. Typically, the FAS 87
15 expense will more closely follow the smoother pattern of the
16 accrual of benefits, but FAS 87 expense can also be somewhat
17 variable due to variations in the return on plan assets and
18 in actuarial assumptions. Despite the variability of these
19 two measures, it must be recognized that employees continue
20 to accrue additional benefits through their service to the
21 company that must ultimately be paid to those employees in
22 future years. Mr. English's contention that, since a
23 company is not currently making contributions to its pension
24 plan, it therefore does not incur a cost from operating that
25 plan, is to ignore the economics of the plan.
SMITH, DI-REB 26
IDAHO POWER COMPAN
1 Q.Setting aside for the moment the issue of
2 previously capitalized pension expense, what is the
3 Company's current practice regarding current and future
4 pension costs?
5 A.On June 1, 2007, the Commission issued Order
6 30333. This Order clarified that the Company should seek
7 recovery of future pension costs on a cash basis, or when
8 future contributions are made to the plan. Pursuant to this
9 Order, the Company began deferring FAS 87 pension expense to
10 a regulatory asset in August of 2007. As a result, until
11 the Company makes contributions to the plan, it will not
12 record a charge to earnings for FAS 87 pension expense nor
13 will it capitalize a portion of FAS 87 pension expense to
14 plant. Prior to August of 2007, the Company had a prepaid
15 asset relating to previous contributions made to the pension
16 plan. As the Commission's Order only relates to future
17 contributions to the plan, the Company could not begin
18 deferring FAS 87 pension expenses until the previously made
19 contributions had been fully amortized through expense.
20 Q.In your opinion is inclusion of the
21 capitalized portion of pension in rate base consistent with
22 prior commission orders and accepted regulatory accounting
23 procedures?
SMITH, DI-REB 27
IDAHO POWER COMPAN
1 A.Yes. The Company treatment is consistent
2 with both FAS 87, the FERC Uniform System of Accounts and
3 generally Accepted Accounting Principles (GAAP).
4 Q.Staff Witness English, at pages 12-15 of his
5 testimony states that he has adjusted the actual test year
6 operating payroll in a manner that is consistent with
7 treatment in prior Commission orders. Do you agree with
8 this adjustment?
9 A.No. As I have stated, the Company's
10 annualization of year-end payroll of the forecast test year
11 for 2007 is representative of the reasonable expenses the
12 Company expects to incur during the effective rate period of
13 the forecast test year. Although his use of annualization
14 is consistent with prior Commission orders, Mr. English has
15 applied the payroll adjustment to an incorrect test period,
16 given the Commission's responsibility to set rates that
17 reasonably provide the Company an opportuni ty to earn its
18 allowed rate of return.
19 Q.Staff Witness English does not include a
20 known and measurable adjustment for a 2008 salary structure
21 adjustment. Likewise, Micron witness Dr. Peseau states on
22 page 23 of his testimony that "I take issue with the
23 Company's request to raise its revenue requirement by
24 $3,020,719 to account for a 2008 salary structure
25 adjustment". Have they correctly analyzed the 2008 payroll
SMITH, DI-REB 28
IDAHO .POWER COMPAN
1 issue?
2 A.No. The forecast test year for 2007 was
3 compiled to reflect the Company's expected operating and
4 capital costs to reliably serve its Idaho customers and to
5 minimize the regulatory lag associated wi th the historical
6 and hybrid test years previously used by the Company. A
7 standard adjustment to establish the revenue requirement in
8 a rate proceeding is to identify those known and measurable
9 adjustments to expenses, such as payroll. The impact of
10 this known and measurable adjustment is to establish the
11 expected expense representative of the effective rate
12 period. The Commission must determine the appropriate
13 expense timeframe to apply the consistent adjustment that
14 has been included in prior cases. Mr. English and Dr.
15 Peseau suggest totally removing an increase in expense that
16 has already been implemented effective December 15, 2007 and
17 will impact the rate effective period in 2008.
18 Q.~taff Witness Vaughn describes at pages 10-11
19 an adjustment to the Staff's actual test year for a credit
20 received from the Federal Energy Regulatory Commission
21 (FERC) involving FERC administration and Other Federal
22 Agency (OFA) charges. Do you agree with this adjustment?
23 A.No.
24 Q.Please describe what the FERC administration
25 and other federal agency charge reimbursements were for and
SMITH, DI-REB 29
IDAHO POWER COMPAN
1 the period of time that was involved in accumulating the
2 overcharge.
3 A.The FERC and other federal agencies assess
4 utilities for costs related to their administrative and
5 regulatory duties. Numerous utili ties sued over the
6 accuracy of the charge and as a resul t, Idaho Power received
7 reimbursement for fees collected from 1999 through 2006.
8 Q.Ms. Vaughn recommends that the Company flow
9 through this reimbursement to its customers over a five year
10 period. Do you agree with this recommendation?
11 A.No. There are essentially two reasons for my
12 di sagreemen t :( 1) Ms. Vaughn con tends that the Company
13 over~collected its expenses in prior years. This would only
14 be true if the Company had over earned since the period of
15 time she uses i. e. from 2003 forward. As Company witness
16 Steve Keen has demonstrated in his rebuttal testimony, the
17 return on equity for those time periods was well below the
18 allowed return established in those two cases and
19 accordingly there was no overcharge.(2 ) Ms. Vaughn has
20 simply selected one expense item out of many to make a
21 retroactive adjustment for ratemaking purposes. She is
22 artificially increasing the Company's revenues for the next
23 five years when she creates the amortization of her created
24 credit. This amortization has no relationship to the. actual
25 ongoing costs of the Company. It will simply cause the
SMITH, DI-REB 30
IDAHO POWER COMPAN
1 Company to under-earn through the device of creating a
2 revenue stream from a prior period by assuming that the
3 Company has over-collected on an expense item for a prior
4 period.
5 Q.What would be the financial impact of Ms.
6 Vaughn's recommendation?
7 A.The Company would be required to write-off
8 approximately $3.3 million to its 2008 income.
9 Q.Staff Witness Vaughn concludes between pages
10 12-19 that the actual test year revenue requirement should
11 be reduced by $879,887 based on an accumulation of
12 assumptions and proj ections related to the Company's
13 employee use of Purchasing Cards (P-card). Do you agree
14 with this adjustment?
15 A.No. Ms. Vaughn has not done a complete
16 review and analysis with a statistically reliable sample.
17 Her conclusions are based on inferences about the sample
18 that she selected. She admittedly ignores the deductions in
19 my Exhibit No. 17 that have been consistent with prior
20 cases in the future test year filed by the Company and she
21 arbitrarily adjusts the actual test year expense for
22 personal vehicle mileage by 50%. To suggest making
23 adjustments to lower the actual test year revenue
24 requirement by $879,887 based on this substantially
25 unsupported analysis is improper. I recommend the
SMITH, DI-REB 31
IDAHO POWER COMPAN
1 Commission make no adjustment based on Staff witness
2 Vaughn's analysis.
3 Q.On pages 9-11 of her testimony, Staff Witness
4 Stockton suggests working capital adjustments for prepaid
5 items and aligns the fuel stock inventory to reflect
6 normalized operating criteria. Do you agree with these
7 adjustments to the actual test year?
8 A.I agree that Ms. Stockton's mechanical
9 adjustment of the Company's working capital to match Staff's
10 proposed test year was done correctly, but I do not believe
11 Staff's test year appropriately reflects the Company's costs
12 during the period rates will be in effect.
13 Q.Dr. Peseau recommends on pages 23-24 of his
14 testimony that the Commission deny $2.2 million of the
15 Company's proposed revenue adjustment for IERCo. Is that an
16 appropriate adjustment?
17 A.No. The $2.2 million Dr. Peseau refers to is
18 additional revenues that IERCo received in 2006 as a result
19 of increased production experienced at Bridger Coal Company
20 (one-third ownership by IERCo) which was needed to make up
21 for reduced deliveries from Black Butte Coal Company. This
22 was strictly a 2006 event and has not reoccurred in 2007.
23 Dr. Peseau's only justification for this
24 adjustment is that "parties are obviously still unable to
25 assess this prediction". In other words, Dr. Peseau is
SMITH, DI-REB 32
IDAHO POWER COMPAN
1 asserting that the Company's forecast of IERCo' s 2007
2 revenues and resulting net income could not be relied upon.
3 The facts do not support Dr. Peseau' s conclusion. For the
4 11 months ending November 2007,IERCo has recorded $4.6
5 million of net income. To test the accuracy of the
6 Company's forecast, a simple annualization can be completed.
7 By annualizing the $4.6 million, the projected 2007 net
8 income equals $5.0 million in net income. In the Company's
9 2007 forecasted test year, rERCo' s net income was estimated
10 to be $5.2 million. Additionally, Staff has included the
11 Company's 2007 forecast of IERCo's net income in its
12 proposed revenue requirement.
13 Q.Does this conclude your rebuttal testimony?
14 A.Yes, it does.
SMITH, Dr -REB 33
IDAHO POWER COMPAN
Idaho Power Company
Regulatory Lag: O&M Analysis
Other O&M (2007 Forecast Test Year)$288,932,502
Less:
DSM (Schwendiman, Exhibit 25)
Pension (Schwendiman, Exhibit 25)
Other O&M before Adjustments
(15,732,910)
(4,607,443)
268,592,149
Adjustments (Smith, Exhibit 18):
Annualized Payroll
2008 Payroll SSA
Incentive Expense
Adjusted Other O&M (2007 Forecast Test Year)
4,500,064
3,020,719
229,859
276,342,791
Assumed Sales Growth (1)
Estimated Collection in 2008 (2)
2008 Approved Budget excluding DSM
Regulatory Lag
4,974,170
281,316,961
288,639,200
($7,322,239)
(1) Assumes a 1,8% growth in normalized sales from 2007 to 2008.
(2) Assumes new rates are in effect January 2008.
Exhibit No. 69
Case No. IPC-E-07-08
L. Smith, IPC
Page 1 of 1
Idaho Power Company
Regulatory Lag: O&M Analysis
Other O&M per Staff Exhibit 113
Less:
Acct 501
Acct 547
Acct 555
Other: Unidentified by Staff
$558,975.639
119,484,800
7,085,900
150,364,531
481,020
Other O&M (12 months ending June 2007)$281,559.388
Staff Adjustments per Staff Exhibit 113 (1)
Standard Commission Adjustments
Donn English Adjustments
Cecily Vaughn Adjustments
Total Staff Adjustment
(22,234,882)
8,661,379
1,913,235
(11,660.268)
Adjusted Other O&M (Staff)269,899,120
Assumed Sales Growth (2)
Estimated Collection in 2008 (3)
2008 Budget excluding DSM
Regulatory Lag
4,858,184
274,757,304
288.639,200
($13,881,896)
(1) Including Staff adjustments in this analysis is only for
demonstrating regulatory lag, This should not construed as
my agreement with these adjustments.
(2) Assumes a 1,8% growth in normalized sales from 2007 to 2008.
(3) Assumes new rates are in effect January 2008.
Exhibit No. 70
Case No. IPC-E-07-08
L. Smith. IPCo
Page 1 of 1
Id
a
h
o

P
o
w
e
r

C
o
m
p
a
n
y
Re
g
u
l
a
t
o
r
y

L
a
g
:

L
o
a
d

G
r
o
w
t
h

A
d
j
u
s
t
m
e
n
t

w
i
t
h
i
n

t
h
e

P
C
A

(
2
0
0
1

t
h
r
o
u
g
h

N
o
v
e
m
b
e
r

2
0
0
7
)
Te
s
t

y
e
a
r

u
s
e
d

f
o
r

n
o
r
m
a
l
i
z
e
d

s
y
t
e
m

l
o
a
d
1
i
~
~
2
§
I
YT
D

N
o
v
20
0
1
20
0
2
20
0
3
20
0
4
20
0
5
~
20
0
7
19
9
3
19
9
3
19
9
3
19
9
3

a
n
d

2
0
0
3
20
0
3
20
0
3

a
n
d

2
0
0
5
20
0
5
Ja
n
.
M
a
y
/
J
u
n
-
D
e
c
Ja
n
-
M
a
y
/
J
u
n
-
D
e
c
15
,
3
9
1
,
4
6
2
15
,
7
8
9
,
5
4
4
15
,
1
4
6
,
8
4
3
14
,
7
0
0
,
1
5
2
14
,
5
6
3
,
4
2
3
15
,
3
0
2
,
9
1
2
14
,
4
9
1
,
9
2
8
13
,
9
5
2
,
2
8
3
13
,
9
5
2
,
2
8
3
13
,
9
5
2
,
2
8
3
14
,
2
3
2
,
3
8
7
14
,
1
0
7
,
5
7
3
14
,
5
0
6
,
1
9
7
13
,
5
4
5
,
0
4
4
1,
4
3
9
,
1
7
9
1,
8
3
7
,
2
6
1
1,
1
9
4
,
5
6
0
46
7
,
7
6
5
45
5
,
8
5
0
79
6
,
7
1
5
94
6
,
8
8
4
$1
6
.
8
4
$1
6
.
8
4
$1
6
.
8
4
$1
6
.
8
4
$1
6
.
8
4
$1
6
.
8
4
$1
6
.
8
4
/

$
2
9
.
4
1
2
$1
8
,
5
4
0
,
3
6
7
$2
3
,
6
6
8
,
6
9
9
$1
7
,
0
3
6
,
5
7
1
$6
,
5
1
1
,
0
9
7
$6
,
5
0
1
,
2
4
0
$1
1
,
3
6
2
,
5
8
7
$2
2
,
0
7
2
,
7
0
7
Ac
t
u
a
l

T
o
t
a
l

S
y
s
t
e
m

L
o
a
d

(
A
d
j
u
s
t
e
d
)
To
t
a
l

S
y
s
t
e
m

N
o
r
m
a
l
i
z
e
d

L
o
a
d

-

M
W
h
Ch
a
n
g
e

i
n

L
o
a
d

(
M
W
h
s
)
Lo
a
d

G
r
o
w
t
h

A
d
j
u
s
t
m
e
n
t

R
a
t
e
LG
A
R

C
h
a
r
g
e
(A
f
t
e
r

J
u
r
i
s
d
i
c
t
i
o
n
a
l
i
z
a
t
o
n

a
n
d

S
h
a
r
i
n
g
)
Es
t
i
m
a
t
e
d

C
o
l
l
e
c
i
o
n
:
Ch
a
n
g
e

i
n

L
o
a
d

(
M
W
h
s
)
Le
s
s

e
s
t
i
m
a
t
e
d

s
y
s
t
e
m

l
o
s
s
e
s

a
t

8
%
Id
a
h
o

J
u
r
i
s
d
i
c
t
i
o
n
a
l

%
1,
4
3
9
,
1
7
9

1
,
8
3
7
,
2
6
1

1
,
1
9
4
,
5
6
0

4
6
7
,
7
6
5

4
5
5
,
8
5
0

7
9
6
,
7
1
5

9
4
6
,
8
8
4
(1
1
5
,
1
3
4
)

(
1
4
6
,
9
8
1
)

(
9
5
,
5
6
5
)

(
3
7
,
4
2
1
)

(
3
6
,
4
6
8
)

(
6
3
,
7
3
7
)

(
7
5
,
7
5
1
)
1,
3
2
4
,
0
4
5

1
,
6
9
0
,
2
8
0

1
,
0
9
8
,
9
9
5

4
3
0
,
3
4
4

4
1
9
,
3
8
2

7
3
2
,
9
7
8

8
7
1
,
1
3
3
85
.
0
%

8
5
.
0
%

8
5
.
0
%

8
5
.
0
%
/
9
4
.
1
%

9
4
.
1
%

9
4
.
1
%

9
4
.
1
%
1,
1
2
5
,
4
3
8

1
,
4
3
6
,
7
3
8

9
3
4
,
1
4
6

3
8
8
,
6
3
6

3
9
4
,
6
3
8

6
8
9
,
7
3
2

8
1
9
,
7
3
6
$5
.
2
4

$
5
.
2
4

$
5
.
2
4

$
5
.
2
4
1

$
6
.
6
7

$
6
.
6
7

$
6
.
6
7
/

$
6
,
8
1

$
6
.
8
1
$5
,
8
9
7
,
2
9
5

$
7
,
5
2
8
,
5
0
8

$
4
,
8
9
4
,
9
2
5

$
2
,
7
2
4
,
3
9
3

$
2
,
6
3
2
,
2
3
9

$
5
,
0
5
9
,
9
0
7

$
5
,
5
8
2
,
4
0
5
($
1
2
,
6
4
3
,
0
7
2
)

(
$
1
6
,
1
4
0
,
1
9
1
)

(
$
1
2
,
1
4
1
,
6
4
6
)

(
$
3
,
7
8
6
,
7
0
4
)

(
$
3
,
8
6
9
,
0
0
1
)

(
$
6
,
3
0
2
,
6
7
9
)

(
$
1
6
,
4
9
0
,
3
0
2
)
($
7
1
,
3
7
3
,
5
9
6
)
Em
b
e
d
d
e
d

P
U
R
P
A

&

V
a
r
i
a
b
l
e

P
o
w
e
r

S
u
p
p
l
y

E
x
p
e
n
s
e

R
a
t
e
Es
t
i
m
a
t
e
d

C
o
l
l
e
c
t
i
o
n

o
f

P
U
R
P
A

&

V
a
r
i
a
b
l
e

N
e
t

P
o
w
e
r

S
u
p
p
l
y

C
o
s
t
Ea
r
n
i
n
g
s

(
L
o
s
s
)

b
e
f
o
r
e

T
a
x
Cu
m
u
l
a
t
i
v
e

2
0
0
1

t
h
r
o
u
g
h

2
0
0
7

E
a
r
n
i
n
g
s

(
L
o
s
s
)

b
e
f
o
r
e

T
a
x
("II !£z
r~

m
CI
'
i
~
~3
(
"
¡
;
~
g
m
~
..
:
-
6
g
:
a~
6
~
..
0

(
)
.
.