20050118Weston Direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF PACIFICORP DBA
UT AU POWER & LIGHT COMPANY
FOR APPROVAL OF CHANGES TO ITS
ELECTRIC SERVICE SCHEDULES
CASE NO. PAC-O5-
) Direct Testimony of J. Ted Weston
ACIFICORP
CASE NO. PAC-05-
January 2005
Please state your name, business address and present position with
PacifiCorp dba Utah Power & Light Company (the Company).
My name is Ted Weston. My business address is One Utah Center, Suite 2300
201 South Main Street, Salt Lake City, Utah, 84140-2300. I am currently
employed as the Manager of Revenue Requirement in the Regulation Department.
Qualifications
Please briefly describe your education and business experience.
I received a Bachelor of Science Degree in Accounting from Utah State
University in 1983. In addition to formal education, I have attended various
educational, professional and electric industry related seminars during my career
at the Company. I joined the Company in 1983 , and I have held various
accounting and regulatory positions prior to my current position.
What are your current responsibilities?
My primary responsibilities are to calculate the Company s revenue requirement
and regulated earnings, to determine the interjurisdictional cost allocations, and to
explain those calculations to regulators in the six jurisdictions in which
PacifiCorp operates.
Purpose of Testimony
What is the purpose of your testimony?
The purpose of my testimony is to present the Company s results of operations for
the test period based on Fiscal Year 2004 (FY04), which covers the twelve month
period ended March 31 , 2004. That period has been normalized to remove any
non-recurring events and adjusted for known and measurable items to reflect a
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forward looking test period more closely aligned with the time when the new rates
will be effective. My testimony presents evidence that based on these results of
operations, PacifiCorp is earning an overall Return on Equity (ROE) in its Idaho
jurisdictional service territory of 5.8 percent. This return is far below any other
ROE recently authorized by the Commission for other investor-owned utilities in
Idaho, and less than the ROE essential to provide a fair and equitable return for
PacifiCorp s shareholders, as determined in Dr. Hadaway s testimony. In support
of this conclusion, I introduce and describe the Company s Idaho Results of
Operations Report, identified as Exhibit No.9. In describing this report, I
indicate the sources of the base data, describe certain normalizing adjustments to
the base data, and explain the Company s forward looking approach for any
known and measurable adjustments.
Based on the results contained in Exhibit No., what level of price increase is
necessary for PacifiCorp to earn the ROE recommended by Dr. Hadaway?
A price increase of $16.9 million would be required to allow the Company the
opportunity to earn the 11.125 percent ROE recommended in Dr. Hadaway
testimony.
Is PacifiCorp actually seeking to increase revenues by $16.9 million in this
proceeding?
, the Company is requesting a price increase of $15.1 million based on the
Revised Protocol stipulation. As explained in Mr. Dave Taylor s testimony and
agreed upon as part of the Multi-State Process (MSP), the Revised Protocol
stipulation imposes a limit on any increase to PacifiCorp s revenue requirement at
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101.67 percent of the Idaho revenue requirement calculated under the Rolled-
Allocation methodology. The application of this rate mitigation cap limits the
Company s requested rate increase to $15.1 million, or $1.8 million less than the
increase that is supported by Exhibit No.9. This cap is an effort to phase into the
Revised Protocol method from Rolled-In over a five year period, as further
discussed in Mr. Taylor s testimony.
What is contained in Exhibit No.
Exhibit No.9 is PacifiCorp' s Idaho Results of Operations Report ("Report"). The
base year for the Report is fiscal year 2004, which has been normalized to present
a forward looking twelve-month test period. The Report details revenues
expenses and rate base allocated to the Idaho service territory based on the
Revised Protocol methodology, in accordance with the Revised Protocol
stipulation described above. Mr. Taylor s testimony describes the changes in
jurisdictional allocation methodology between Rolled-In and the Revised Protocol
and the provision in the stipulation to phase into the Revised Protocol method.
He also details the impacts of those changes on the Idaho revenue requirement.
Please describe the contents of the Report.
The Report provides twelve-month totals for revenues and expenses. Rate base is
calculated as the average of the beginning and end of year balances. The Report
presents operating results for the period in terms of both return on rate base and
ROE. Tab 1 of the Report provides summary information. Page 1.0 is a summary
of results allocated to Idaho based on the Rolled-In methodology. Column
shows the adjusted Idaho results, and column 2 is the Rolled-In price change.
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Column 3 adds this price increase to the adjusted general business revenues to get
the Rolled-In revenue requirement. Column 4 reflects the application of the
101.67 percent cap required under the Revised Protocol stipulation. Column 5 is
the product of columns 3 and 4 and represents the maximum allowed step
increase to move to Revised Protocol. This maximum allowed amount was
compared to the Revised Protocol revenue requirement (column 6) to demonstrate
the impact of the cap (column 7). The final column is the price increase based on
the capped Revised Protocol methodology carried forward from page 1.
Page 1.1 is a summary of the normalized Idaho results of operations for
the test period with a calculation of the increase in Idaho retail revenues that
would be necessary for the Company to earn 11.125 percent ROE based on
Revised Protocol methodology. The Total Adjusted Results (Column 1) is carried
forward from the results of operations summary, Page 2., and shows a forecasted
ROE for Idaho of 5.8 percent. The Price Change (Column 2) shows that a price
increase of $16.9 million in revenues is required to increase the return from 5.8 to
11.125 percent ROE in Idaho. Column 3 summarizes Idaho s revenue
requirement. Page 1.2 supports the calculation of additional revenue-related taxes
associated with the price change requested in column 2. Page 1.3 details the
calculation of the net operating income percentage. Page 1.4 starts with Idaho
unadjusted results and summarizes the impact of the normalization adjustments by
type.
PacifiCorp summarizes adjustments into three different types. Type I
adjustments represent base period accounting or Commission-ordered adjustments
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(i., reversing one- time write-offs). Type II adjustments typically annualize
events that occurred during the base year (i., contract changes or wage
increases). Type III adjustments reflect known and measurable events that
occurred after the base period. Page 1.5 is a summary of all the normalizing
adjustments by category contained in Tabs 3 through 8.
Tab 2 details the allocation of Company results to Idaho using the Revised
Protocol allocation method. Pages 2.3 through 2.38 contain Total Company and
Idaho-allocated revenues, expenses and rate base detailed by FERC Account.
Tabs 3 through 8 summarize the normalizing adjustments by category made to
FY04 base data to reflect on-going costs of the Company. Tab 9 is a replication
of Tab 2 except the Idaho results are produced based on the Rolled-In allocation
method. Supporting documentation for the data in Tab 9 is provided under Tabs
B 1 through B20, for unadjusted results. Tab 10 contains the calculation of the
Revised Protocol allocation factors. This completes the summary explanation of
the contents of my exhibit.
Revenues
Would you describe the revenue normalization adjustments made in Tab 3,
Revenue Adjustments?
Yes. Page 3.0 summarizes each adjustment in Tab 3, listing each in a separate
column itemizing the impact to revenues, operation, maintenance, administrative
and general expenses (OMAG), taxes, and rate base, and an overall impact to the
ROE. The adjustments made to normalize the test year revenues are detailed on
pages 3.1 through 3.7 with supporting documentation. I will briefly describe each
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of these adjustments.
Weather Normalization (Adjustment 3.1) - Adjustment 3.1 normalizes revenues
in the base year by comparing actual loads to temperature normalized loads.
Weather normalization reflects weather or temperature patterns which were
measurably different than normal, as defined by using thirty year historical
averages prepared by the National Oceanic & Atmospheric Administration. Only
residential and commercial loads are considered weather sensitive. This revenue
adjustment corresponds with the temperature adjustment made to the system peak
and energy loads utilized for the development of the jurisdictional allocation
factors.
Revenue Normalizing Adjustments - Adjustment 3.2 normalizes the base year
revenues by removing items that should not "be included to determine retail rates
such as credits from the Bonneville Power Administration (BP A) and
ScottishPower merger credits. Also removed are Blue Sky revenues to assure that
this program is not subsidized by non-participating customers~ costs of the Blue
Sky program are removed in the O&M section adjustment 4.2. This adjustment
also removed the one-time change in unbilled revenues due to a change in the
methodology used to determine the amount recorded on the balance sheet for
unbilled revenues.
Rock River Warranty Reversal- Adjustment 3.3 removes a non-recurring
settlement from base year results. PacifiCorp negotiated a warranty provision
with the manufacturer as part of the installation contract of these wind generation
units that guaranteed a specified completion date for the project. The contractor
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didn t meet the terms of the contract and paid the penalty determined by the
contract.
Removal of System Balancing Activity - Adjustment 3.4 removes revenues
recorded during the test period for wholesale sales to account 456. The Company
models the normalized wholesale sales and purchase activities for net power costs
in the Generation Resource Integrated Dispatch model (GRID). This adjustment
in conjunction with adjustment 5.1 removes these net system balancing activities
from the results and adjustment 5.1 replaces these with normalized amounts, as
described in Mr. Mark Widmer s testimony.
USBR/UKRB Revenues - Adjustment 3.5 system allocates the cost of Klamath
River water rights to better align them with the benefits of the hydro system. The
s. Bureau of Reclamation (USBR) and the Klamath Basin Water Users
Protective Association (UKRB) receive a discounted tariff in exchange for their
water rights through contracts with PacifiCorp. These contracts preserve the
Company s interests in three hydro projects on the Klamath River. Because all
customers share in the benefits of the hydro production from these plants, these
costs should be shared in the same way.
Special Contract Reclassification - Adjustment 3.6 normalizes base year
revenues by reversing the system allocation of special contract revenues and
assigns those revenues to their home state. The Revised Protocol developed in
MSP specified that these special contracts would be direct assigned to their home
state. This means that the load associated with each of these contracts is included
in its home state load for development of the allocation factors, with the revenues
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also being retained by the home state.
Little Mountain - Adjustment 3.7 removes excess revenue related to Little
Mountain steam sales from months outside the test period.
This is a summary of normalization adjustments made to revenues, with
the exception of the wholesale sales normalized by GRID summarized in
adjustment 5.
OMAG Expenses
Please describe the adjustments made to base year OMAG expense in Tab 4
O&M Adjustments.
Tab 4 is a summary of the adjustments made to the Company s unadjusted FY04
OMAG expense to remove any non-recurring events as well as normalize the base
year to more accurately reflect conditions during the rate effective period. Page
0 summarizes each adjustment in Tab 4, listing each in a separate column
itemizing the impact to revenues, OMAG, taxes and rate base and an overall
impact to ROE. The adjustments made to normalize the test year OMAG are
detailed on pages 4.1 through 4.18 with supporting documentation. I will briefly
describe each of these adjustments.
Uncollectible Expense - Adjustment 4.1 removes a joint owner accrual recorded
during the base year to account for revenues billed to, but not paid by, the
minority joint owner of the Company-owned generation facility. This dispute has
since been resolved and is not considered a recurring event.
Blue Sky Program - Adjustment 4.2 removes the OMAG expenses associated
with the Blue Sky program. The Blue Sky Program is designed to encourage
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voluntary customer participation in the acquisition and development of renewable
resources. To ensure that non-participants do not subsidize this program
Adjustment 4.2 removes the expenses associated with the program from the base
year expense. The retail revenues from program participants were removed from
results in adjustment 3.2 and power purchases and sales were normalized in
adjustment 5.
Miscellaneous General Expense - Adjustment 4.3 removes from the test period
certain miscellaneous expenses such as club dues and other contributions that
should have been charged below the line to non-regulated expense.
International Assignees - Adjustment 4.4 removes from the test period housing
and other costs associated with international assignees who have either returned to
Scotland or "localized" (transferred to the U.S. compensation package). The
labor-related costs for those international assignees who returned to Scotland are
removed in the labor adjustment 4.11 and 4.12. These are expenses that the
Company does not expect to incur in the future.
DSM Liability Write-Off - Adjustment 4.5 removes a non-recurring liability
write-off from the test period. Several years ago, PacifiCorp contracted for the
development of some energy saving equipment for Oregon customers. In 2000
PacifiCorp sued for partial non-delivery and withheld payment from the
contractor. Ultimately the Company lost this claim in arbitration, a settlement
was later reached between the parties , and the Company wrote off the liability
during the test period.
Customer Guarantee Reversal - Adjustment 4.6 removes customer guarantee
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payments from OMAG as these items should be booked below the line.
ScottishPower made several customer guarantees as part of its merger
commitments, and failure to comply with these guarantees resulted in fines to be
paid to the customer. A review of the test period identified that some of the
customer guarantee payments were incorrectly booked above the line.
Deferred Generation Asset Write-off Removal- Adjustment 4.7 removes from
the base year the write-off of prior period preliminary survey and investigation
costs. This accounting treatment is based on F ASB Statement of Position (SOP)
81-, Accounting for Performance of Construction-Type and Certain Production-
Type Contracts, and SOP 98-, Reporting on the Costs of Start-Up activities.
These accounting pronouncements state that any project investigation and
development costs incurred prior to receiving management approval should be
expensed rather than deferred. In FY04, $5.4 million was expensed due to these
pronouncements, and $4.3 million was incurred in prior years. Only the prior
period amount was removed, leaving an annual amount of expense in the test
period.
Remove Settlement Termination Expenses - Adjustment 4.8 removes the test
year expenses associated with a potential legal liability accrued by the Company
in connection with the termination of the failed sale of the California service
territory. This is a one time, non-recurring event.
Direct Access Cost Removal- Adjustment 4.9 removes Oregon direct access
costs from the test year. During FY04, an accounting entry transferring Oregon
direct access costs from account 901 to 580 used two different locations: one
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Oregon location, and the other a system location, which caused one side of the
entry to be system-allocated rather than direct-assigned to Oregon. This
adjustment corrects that allocation error.
Regulatory Asset Correction - Adjustment 4.10 removes a credit to expense
created by an accounting error while writing off a contra account for the
California FAS 109 regulatory asset. In September 2003, this contra account was
written off by debiting account 1823109 and crediting account 930 for $19
million. During the same month another entry was made to reverse a second
quarter adjustment for $4.6 million. Then in December an attempt was made to
remove any impact of this entry from results by transferring it below the line to
account 426. When the second entry was made, however, the full $19 million
was transferred to account 426. This caused the test period expense to be
understated by the $4.6 million.
General Wage Increase - Adjustments 4.11 and 4.12 annualize changes to
wages and headcount that have occurred during FY04. PacifiCorp has several
labor groups, both union and non-union, each with different effective contract
renewal dates. These adjustments include several elements. First, there were
several changes to employee levels, both new hires and employees no longer
employed with the Company. In the case of new hires, their salaries have been
annualized. In the case of those no longer employed by the Company, their
salaries were removed. Second, the salaries and bonuses of the international
assignees who have returned to Scotland have been removed along with
adjustment 4.4, which removed their other benefits. Third, based on a weighted
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matrix of the Company s annual incentive goals, approximately 2.5 percent of the
AlP payout was determined to be driven by the financial results of the Company
and was removed. Fourth, social security and payroll taxes were adjusted to
reflect the impact of these wage changes as well. The overall impact was an
increase of salaries and payroll taxes of $6.1 million. The current OMAG
Capitalization ratio is then applied, which assigns 76 percent to OMAG, and the
net increase of $4.5 million is spread back to all OMAG accounts on the same
ratio as they were originally charged
Proforma General Wage Increase - Adjustments 4.13 and 4.14 recognize that
before this requested rate change is effective, an additional wage increase will
also take effect. These increases are layered on from their effective date forward.
(Adjustments 4.11 and 4.12 annualized wage increases that occurred during
FY04.) Adjustments 4.13 and 4.14 have four elements: (1) salaries were
increased prospectively from the date of their contract renewal dates, (2) we
reflected the impact these wage increases will have on the annual incentive
payout, (3) pension and benefits were normalized, and (4) the incremental impact
of these changes to payroll taxes was calculated. Because incentive pay is
affected by increases to base pay, we also escalated the incentive pay for these
changes. In addition, as discussed in Mr. Dan Rosborough's testimony, although
pension and post-retirement benefits total $44.8 million in FY04, the latest
actuarial report indicates that before the rate effective date they will total $86.
million. Additionally medical, dental , vision, and other employee benefits will
increase by $15.4 million from FY04levels. These increases have been included
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in this adjustment and spread back to each FERC account on the same ratio as
labor. Mr. Rosborough's testimony discusses these cost increases as well.
Finally, we reflected the incremental impact to payroll taxes for each of these
items.
Scottish Power Cross Charge - Adjustment 4.15 reflects the impact of the cross
charge agreement executed by PacifiCorp and Scottish Power UK (SPUK), which
governs the allocation of costs incurred by each entity on behalf of the other.
September 30, 2003 , the Company filed a Compliance Filing pursuant to the
IPUC directives in the merger Order No. 28213 addressing conditions adopted
regarding these affiliated interest transactions. The Securities and Exchange
Commission authorized SPUK and its subsidiaries to bill PacifiCorp for corporate
service costs incurred on behalf of PacifiCorp.
What is included within corporate costs?
Corporate costs include costs relating to executive management and corporate
oversight provided to all ScottishPower pic divisions by SPUK and its
subsidiaries. Similarly, costs incurred by PacifiCorp on behalf of SPUK will be
cross charged to SPUK. All costs incurred by PacifiCorp for SPUK were charged
below the line and are not included in the Company s revenue requirement
application. Although SPUK has provided corporate services to PacifiCorp since
the merger, cross charges began to be invoiced only as of April 2004.
What measures are in place to ensure that these costs are reasonable in
amount?
Both SPUK and PacifiCorp employ controls designed to ensure compliance with
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the corporate cross charge policy before payment is exchanged. Monthly
financial meetings, which monitor levels of Group Corporate costs and any
variances from amounts budgeted for a particular activity, are ongoing. Each
quarter, Price W aterhouseCoopers undertakes an external audit review of the
Group Corporate financial records.
Please quantify the cost categories included in Adjustment 4.15.
Adjustment 4.15 reflects the SPUK annual cross charge to PacifiCorp of
$15 657 489 per year~ Idaho s allocated share is $933,312. The cross charge is
attributed to the following categories:
Corporate secretarial & shareholder services
Executive Directors
Group human resources
Corporate finance
Strategic planning
Corporate Services (IT & Office Space)
Total
$3.9 million
$2.3 million
$2.1 million
$3.8 million
$1.3 million
.$2.2 million
$15.6 million
How are the corporate costs allocated across the various entities?
The cross charge agreement provides that corporate costs are directly charged
directly allocated, or apportioned on a four-factor formula. Costs directly
attributable to an affiliate will be directly charged. For example, external audit
fees attributable to PacifiCorp, yet charged to SPUK, will be directly assigned.
When direct charging is not applicable, the cost is evaluated for direct allocation.
Direct allocation applies when a cost is based on a specific factor. For example, a
cost based on personnel headcount would be directly allocated based on the
headcount at each affiliate. The employee newsletter costs, for example, are
directly allocated based on the number of employees at an affiliate. Common
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corporate costs that cannot be directly assigned or directly allocated are
apportioned based on a four-factor formula. The four factors are sales, operating
profit, net assets, and employee headcount. PacifiCorp believes the volume of
sales, amount of assets, number of employees and profitability are reflective of
the magnitude of common corporate resources required by the US and UK
entities. These four factors are essentially the same as the traditional three factors
PacifiCorp has used for a number of years, with the addition of a profitability
measure. By including profitability as a factor in the allocation methodology, the
entity that is relatively "light" on assets , yet profitable, will be allocated a larger
share of corporate costs compared to the three-factor formula. About 41.4 percent
of common corporate costs, such as corporate secretarial, group human resources
and group finance costs, are allocated to PacifiCorp on the four-factor formula.
Workers ' Compensation Expense - With respect to Adjustment 4., the
Company received notice that the Insurance Carrier used by the Company to
provide employee Workers' Compensation insurance was in bankruptcy. The
Company therefore set up a contingency reserve for $11.5 million in August
2003. Based on current actuarial studies, the reserve has been reduced by $5.
million on the Company books to $5.6 million. Since it is not known whether this
item will be covered by other insurers, this adjustment removes the expense side
of both the establishment of the reserve and the write-off transactions from base
year expenses.
Membership and Subscriptions - Adjustment 4.17 follows precedent
established by the Commission for treatment of national and regional trade
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organizations. The Company has included 75 percent of dues paid to Pacific
Northwest Utilities Conference Committee, Utility Air Regulatory Group, Edison
Electric Institute, and Western Energy Institute and removed all other
membership dues from results.
Irrigation DSM - Adjustment 4.18 corrects the allocation of payments made to
Idaho irrigators. The load control payments were recorded to account 557, which
is system allocated. By direct assigning these costs to Idaho, we have aligned the
costs associated with the load reduction in Idaho with the benefit of lower loads.
This reduction to load means a reduced amount of system costs gets allocated to
Idaho.
Net Power Costs
How are the Company s forecasted Net Power Costs (NPC) for the test
period developed?
Mr. Mark T. Widmer s testimony describes how NPC is normalized for the test
period. The NPC forecast normalizes steam and hydro power generation, fuel
purchased power, wheeling and sales for resale in a manner consistent with
normalized operation of production facilities and the contractual terms of sales
and purchase agreements. NPC is forecasted using the GRID model.
NPC Study - Adjustment 5.1 removes the actual net power costs incurred during
FY04 and replaces those with the normalized results of the GRID model.
Trail Mountain Closure Amortization - Adjustment 5.2 relates to the
Company s March 2001 closure of its Trail Mountain Mine, which supplied coal
to the Hunter Plant (a jointly owned facility) and replaced that coal with lower
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cost coal from the Sufco contract.
Will you explain what led to the Company s decision to close Trail
Mountain?
Yes. When the Company acquired the Trail Mountain Mine from Arco in 1992, it
was aware that acquisition of the Trail Mountain reserves provided the Company
with access to the adjacent Cottonwood Lease. Production from Trail Mountain
and Cottonwood leases would ensure a future supply of coal for the Hunter Plant.
The Company first nominated the Cottonwood lease for bid in 1991. By 1998
however, PacifiCorp knew that the economically recoverable coal reserves at
Trail Mountain were limited. In 1999, the Company began to consider other
alternatives to pursuing the Cottonwood coal reserves and producing its own coal
and issued a request for proposal from outside suppliers. PacifiCorp s long term
fueling strategy called for the Company to move into adjacent Cottonwood coal
reserves and to continue to produce its own coal, a fact that the other producers in
the area knew. At the time PacifiCorp issued its request for proposal, Utah's coal
production was about 25 million tons annually, with the Company producing
around 8 million tons, or 32 percent of the total production. The Company
mines have long provided the Company with leverage in the Utah coal market and
on coal prices. Coal suppliers knew that for their bids to be successful, they
would have to be superior to the Company s own cost of production. As a result
the Company was able to negotiate a very favorable five-year contract with an
outside supplier. This contract provided an economic justification to cease further
environmental permitting of the Cottonwood lease and to close the Trail
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Mountain Mine.
How have customers benefited from the Trail Mountain Closure?
Customers are receiving annual fuel savings of over $19 million a year under the
new coal purchase contract compared to continued operation of Trail Mountain.
Even with a five-year amortization of the closure cost and including a carrying
charge on the un-recovered plant investment, customers still receive a net benefit
of over $7 million annually.
How is the Company accounting for these closure costs?
A petition for a deferred accounting order allowing deferral of the Trail Mountain
un-recovered investment was filed with the Idaho Commission on February 8
2001. This application was approved in Order No. 28700 issued April 5, 2001.
The original application requested deferral of the un-recovered assets only and did
not take into account the additional costs associated with closing the mine.
Closure costs were an additional $19 million which was also deferred. In April
2002, two regulatory assets totaling $46 million were recorded on the Company
books, one for the Trail Mountain Closure costs and the other for the un-
recovered Trail Mountain Investment. These regulatory assets are being
amortized over a five-year period. The amortization expense is recorded in
Account 501 , Fuel Expense. However, because this amortization includes the
joint owners' share, we removed it from the normalized fuel costs included in
Adjustment 5., Net Power Cost study, and added only PacifiCorp s share of
twelve months amortization expense of $7,935 023. This adjustment also
removes the $1 194 806 of joint-owner payments to PacifiCorp from Account
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456, because the joint owners' share of amortization expense is not included.
In addition, because the regulatory assets include the joint owners
portion, it was necessary to correct the balance of the unamortized regulatory
asset included in the test period. Adjustment 5.2 decreased the regulatory assets
by $3 366 682, reflecting the appropriate regulatory asset balance of $19,808 687
in the adjusted test period.
BPA Regional Exchange Credit - Adjustment 5.3 removes the BPA credit from
purchase power expense. The Company receives an annual amount from BP A to
be passed on to its customers. This is accounted for by reducing power costs on
the expense side and providing a credit to customer bills on the revenue side.
Since this is a straight pass-through from BP A, it is not included in the
determination of PacifiCorp s revenue requirement. The credit to revenues was
removed in adjustment 3.
Depreciation and Amortization Expense
Were there any adjustments to the actual depreciation expense?
Yes. The Company is adding the new Currant Creek generation facility, as
described in Mr. Stan K.Watters' testimony. All components of this investment
(with the exception of its impact on NPC) are summarized in adjustment 8.11.
Have you included amortization expense for other miscellaneous items?
The actual results include amortization expense for other deferrals and regulatory
assets included in Tab B16 of my exhibit.
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Taxes
Please describe the adjustments to taxes.
This section has four adjustments to income taxes and one to property taxes.
Interest True-Up - Adjustment 7.1 aligns interest expense with net rate base by
applying the weighted cost of debt to Idaho net investment.
Deferred Tax Balance Reclass - Adjustment 7.2 is necessary to correct the
allocation of two deferred tax balances. A review of these two accounts, which
were being allocated on a SO factor, revealed they actually contained several
state-specific regulatory assets which should be direct assigned to specific states
, alternatively, should be excluded from the revenue requirement calculation.
For example, the deferred income taxes associated with the recovery of the excess
power costs incurred during the Western power crisis were recorded in one
account. These costs were recovered on a separate rider and should not be
included in these results. The supporting work papers detail the components of
each account and their correct allocation.
Wyoming Wind Tax Credit - Adjustment 7.3 recognizes that the federal
government offered an income tax credit for investment in renewable resources
placed into service before December 31 2001. The Company owns 78.8 percent
share of the Foote Creek wind project in Wyoming. The total Company tax credit
of $2.2 million is based on PacifiCorp s share of the energy produced at that
facility. This adjustment includes that tax credit in results.
Property Tax - Adjustment 7.4 aligns property taxes with the investment
included in this filing. Property taxes are based on the plant investment as of
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January 1 of each year. The property taxes in FY04 are based on plant balances
as of December 31 , 2002. This adjustment applies the imputed rates to the plant
balance included in the filing.
IRS Settlement Amortization - Adjustment 7.5 amortizes payments made for
state income taxes over five years. In FY04 PacifiCorp paid $634 571 to state
taxing authorities as a result of the IRS settlement for years 1994 through 1998.
The requested amortization of these payments over 5 years is consistent with the
number of years to which the IRS settlement applies. This adjustment complies
with the Stipulation in Case No. PAC-03-05 wherein the Company committed
to propose a methodology for the recovery of future audit assessments
Rate Base
Please describe each of the adjustments to rate base balances.
Update Cash Working Capital- Adjustment 8.1 aligns cash working capital
with the operating expenses included in the filing. PacifiCorp utilizes a Lead /
Lag study to account for the lag associated with providing electric service to
customers. While there are several different methods used to calculate working
capital, the Company believes cash working capital based on a Lead / Lag study is
the most accurate. The Company updated its study based on fiscal year 2003 data
Environmental Settlement - Adjustment 8.2 deducts the unused insurance
settlement for environmental clean-up sites from rate base. In 1996, the Company
received an insurance settlement of$38 million to cover the cost of Company
clean-up sites. These funds were transferred to PacifiCorp Environmental
Remediation Company (PERCO), which is performing the clean-up at these sites.
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PacifiCorp
As remediation work is performed on the clean-up sites, the funds from the
insurance settlement are used, reducing the fund balance.
Trapper Mine - Adjustment 8.3 adds PacifiCorp s 21.4 percent interest in the
Trapper Mine, which provides coal to the Craig Generating Plant, into rate base.
The normalized coal cost of Trapper Mine includes all operating and maintenance
costs but does not include a return on investment. It is necessary to add the
Company s investment in Trapper Mine to rate base, since this investment is
recorded on the Company s books in Account 123.1 - Investment in Subsidiary
Company, which is not normally a rate base account.
Jim Bridger Mine - Adjustment 8.4 adds PacifiCorp s two-thirds interest in the
Bridger Coal Company, which supplies coal to the Jim Bridger Generating Plant.
The Company s investment in Bridger Coal Company is recorded on the books of
Pacific Minerals, Inc. (PMI). Because of this ownership arrangement, the coal
mine investment is not included in electric plant in service. The normalized coal
costs for Bridger Coal Company include the operating and maintenance costs of
mining, but provide no return on investment. This adjustment is therefore
necessary to properly reflect the Bridger Coal Company investment in base year
rate base.
Plant Held for Future Use - Adjustment 8.5 removes Plant Held for Future Use
from the beginning balance that was written off during the year. While the plant
was not included in the ending balance, it was still on the books at the beginning
of the year.
Correction of Weatherization Allocation - Adjustment 8.6 reverses the system
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allocation of weatherization loans. During the year, the Company received
payment for some Utah DSM loans. These payments were incorrectly allocated
on a system wide basis rather than directly to Utah, however, and this adjustment
makes the necessary correction.
Hydro Relicensing Obligations - Adjustment 8.7 includes in rate base the net
balance of the North Umpqua and Bear River FERC relicensing settlement
obligations and associated amortization expense. During the FERC relicensing
process, FERC required the Company to comply with several new requirements
as a condition for approval of the new license. The North Umpqua agreement is
for 35 years and Bear River is a 30 year agreement. FASB requires net present
value accounting of these future obligations, creating a regulatory asset and
offsetting liability on the Company s books. The Company proposes a straight-
line amortization of these obligations. Whether there is a net asset or liability is
based on the timing of obligation payments verses the straight line amortization of
the asset. This amortization has two components, principal and interest. The
principal is amortized to account 404. The Company has filed an accounting
application requesting that the interest expense be recognized as an operating
expense rather than interest for regulatory purposes.
Customer Advances - Adjustment 8.8 corrects balances that were recorded in
the base period to a corporate location rather than state-specific locations. This
adjustment corrects the allocation of customer deposits by situs assignment of
those balances.
Sale of Naches - Adjustment 8.9 removes the net investment of the Naches
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hydroelectric facility that was sold in fiscal year 2005.
Sale of Skookumchuck - Adjustment 8.10 removes all effects of the
Skookumchuck dam, gross plant, accumulated depreciation and deferred tax
balances, depreciation and operating expenses from the base year results of
operations. The project was sold because current generating costs to produce
power at the Skookumchuck hydroelectric unit was extremely high and was no
longer efficient for PacifiCorp to continue to operate. The Skookumchuck dam
was constructed for the purpose of holding and storing water for the Centralia
plant. Later the hydroelectric unit was added. The hydro dam and generating unit
were not sold initially with the Centralia plant because a few counties had
expressed interest in purchasing it. Since these counties no longer have the funds
to purchase the dam and hydroelectric unit, the Company is in the process of
selling Skookumchuck to Washington LLC, a limited liability Company formed
by TransAlta USA, Inc., the same entity that purchased the Centralia plant.
Currant Creek Addition Phase I - Adjustment 8.11 adds the investment
depreciation, operating costs and property taxes into results.
Does this conclude your description of rate base adjustments?
Yes.
Would you describe the rest of the Report?
Yes. Tab 9, Rolled-In, is are-cast of Tab 2 based on Rolled-In allocation. Tab
, Allocation Factors, summarizes the derivation of the jurisdictional allocation
factors using the MSP Revised Protocol allocation methodology. Mr. Taylor
describes the derivation of these allocation factors in his testimony. Tabs B
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through B20 provide fiscal year 2004 unadjusted results by function. The Rolled-
In allocation methodology was provided since the Company has not received
approval from all jurisdictions to use Revised Protocol and hasn t yet made the
programming changes to produce these reports.
Does this conclude your direct testimony?
Yes.
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