20070608McDougal direct.pdf

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BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY
MOUNTAIN POWER FOR
APPROVAL OF CHANGES TO ITS
ELECTRIC SERVICE SCHEDULES
CASE NO. P AC-07-
Direct Testimony of Steven R. McDougal
ROCKY MOUNTAIN POWER
CASE NO. P AC-07-
June 2007
Please state your name and business address.
My name is Steven R. McDougal and my business address is 201 South Main
Suite 2300, Salt Lake City, Utah, 84111.
QUALIFICATIONS
What is your current position and your employment history at the Company
(also referred to as Rocky Mountain Power)?
I am currently employed as the Director of Revenue Requirements for Rocky
Mountain Power. I have been employed by the Company since 1983. My
experience includes various positions within the regulation, finance, resource
planning, business planning and internal audit departments.
What are your responsibilities as Director of Revenue Requirements?
My primary responsibilities include overseeing the calculation and reporting of
the Company s regulated earnings or revenue requirement, assuring that the inter-
jurisdictional cost allocation methodology is correctly applied and the explanation
of those calculations to regulators in the jurisdictions in which the Company
operates.
What is your educational background?
I received a Master of Accountancy from Brigham Young University with an
emphasis in Management Advisory Services in 1983 and a Bachelor of Science
degree in Accounting from Brigham Young University in 1982. In addition to my
formal education, I have also attended various educational, professional and
electric industry-related seminars.
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Do you hold any professional licenses?
Yes. I am a Certified Public Accountant (CPA) and also a Certified Internal
Auditor.
Have you testified in previous regulatory proceedings?
Yes. I have provided testimony before the Washington Utilities and
Transportation Commission and the California Public Utilities Commission.
PURPOSE OF TESTIMONY
What is the purpose of your direct testimony?
My direct testimony addresses the calculation and need for the $18.5 million
increase requested in the Company s application. In support of this calculation, I
address the following issues:
. A summary of the calculation of the $18.5 million requested rate increase.
. A description of the test period used in this case, which is twelve months
ending December 31, 2006 with known and measurable adjustments through
December 31 , 2007.
The Idaho revenue requirement calculation and revenue increase, including:
2006 actual results of operations.
Adjustments to 2006 results of operations.
Allocation methodology used.
The treatment of applicable commitments made as a condition for approval of
MidAmerican Energy Holdings Company s (MEHC) acquisition of
PacifiCorp (Case No. P AC-05-08), including amounts deferred as
previously authorized by the Idaho Public Utilities Commission (Commission)
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in Case No. PAC-06-05.
Other deferred accounting adjustments / amortizations included in the test
period for the removal from service of the uncollectible loans made to Grid
West, decommissioning ofthe damaged Powerdale hydroelectric facility, and
MEHC transaction-related severance costs.
REQUIRED RATE INCREASE
What price increase is required to achieve the requested return on equity in
this case?
Presented as an attachment to my testimony is the Company s Idaho Results of
Operations for the twelve months ended December 31 , 2006 normalized through
December 31 , 2007, labeled as Exhibit No. 11. My testimony presents evidence
that, based on its results of operations for this test period, Rocky Mountain Power
earned an overall return on equity (ROE) in Idaho of 5.3 percent for the twe1ve-
months ended December 2006 as adjusted. This return is less than the ROE
currently authorized by the Commission and is less than the return recommended
in Dr. Sam Hadaway s testimony to provide a fair and equitable return for the
Company s shareholders. An overall price increase of $22.0 million is required to
produce the 10.75 percent ROE requested by the Company in this proceeding.
Is the Company requesting the full $22.0 million required to earn a 10.
percent ROE?
No. The Company has reflected the rate mitigation cap as stipulated and approved
by the Commission in Case No. P AC-02-3. The stipulation states:
For all Idaho general rate proceedings initiated after the effective date of
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this Stipulation and Revised Protocol, and until March 31 , 2009, the
Company s Idaho revenue requirement to be used for purposes of setting
rates for Idaho customers will be the lesser of: (i) the Company s Idaho
revenue requirement calculated under the Rolled-In Allocation Method
multiplied by 101.67 percent, or (ii) the Company s Idaho revenue
requirement resulting from use of the Revised Protocol."
This adjustment reduces the rate request by $3.6 million to $18.5 million and is
shown in Exhibit No. 110n page 1.0 of Tab 1 Summary.
TEST PERIOD
Please provide an overview of the test period used in this case.
The test period for this application is based on the historical twelve-month period
ending December 31 , 2006 which has been adjusted for known and measurable
adjustments through December 31 , 2007. This test period is consistent with past
Commission practice as well as Company filings made previously in Idaho.
Is the test period in this case consistent with test periods proposed by the
Company in other states?
No. The Company has used or proposed forecasted test periods in its most recent
general rate cases in Utah, Oregon, California and Wyoming. Rocky Mountain
Power will also be proposing a forecasted test period in its next Wyoming case
consistent with the stipulation in Wyoming Docket No. 20000-230-ER-05.
Does Rocky Mountain Power prefer a forecasted test period?
Yes. A forecasted test period is Rocky Mountain Power s preferred method for
filing rate cases. While adjusting a historical test year for known and measurable
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changes can help to reduce regulatory lag, it does not fully match the costs the
Company expects to incur to the revenue received once new rates are in effect.
Forecasted rate cases match revenues and expenses, help reduce or eliminate
regulatory lag, and provide a better estimate of the Company s revenue
. requirement during the rate effective period. Additionally, during a period of
significant capital additions, a forecast test period is critical to maintain the
financial stability of the Company.
Why is it important that the test period and the rate effective period be
closely aligned?
One of the important underlying principles of fair utility rate-making is to match
capital investment and prudent expenses with revenues under conditions the
utility expects to experience in a normal operating environment. The capital
investment, prudent expenses, and revenues that are used to determine the utility
revenue requirement are calculated using a "test period." The time period and
conditions that the utility will actually experience when rates are in effect are
referred to as the "rate effective period." To the extent possible, the rate effective
period and the test period should closely match each other. Ideally, new rates
should take effect on the commencement of the test year. Traditional historical
test periods will never match the rate effective period and, as I discuss later in my
testimony, will result in the utility under-earning when it is experiencing rapid
expansion and rate base growth. The use of a forecast test period is necessary for
Rocky Mountain Power if it is expected to have a reasonable opportunity to earn
its authorized rate of return.
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What is the effective date of new rates requested in this application?
The Company is requesting that new rates from this application become effective
January 1 2008.
If the new rates resulting from this case become effective January 1, 2008,
will the test period and the rate effective period coincide?
No. The test period is based on December 31 , 2006 results with adjustments
through December 31 , 2007. If new rates become effective January 1 2008, there
will be at least twelve months of regulatory lag built into the Company s Idaho
revenue requirement that could financially harm the Company.
Please explain what you mean by the term "regulatory lag.
The phrase "regulatory lag" refers to the time between when costs are measured
for the utility's revenue requirement and when those costs are recovered in rates
as the utility provides service to its customers. More than anything else
regulatory lag is the result of the rate-making process, and all of the incremental
steps that go into developing, proposing, challenging, litigating and approving
rates for a regulated public utility.
Why is regulatory lag a problem?
Regulatory lag is a serious problem when a utility faces a steady upward trend in
costs and investments for the foreseeable future, but rates are authorized based on
historical costs.
Exhibit No. 12 is a graphical representation of regulatory lag. This Exhibit
compares a historical base period, January 1 , 2006 through December 31 , 2006
the adjustments included through December 31 , 2007, and the rate effective
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period, January 2008 through January 2009. This exhibit highlights the mismatch
in investments, operating costs, revenues and loads between the two example test
periods and the rate effective period.
Why does Rocky Mountain Power advocate the use of forecasted test period
in rate case proceedings?
Rocky Mountain Power is in the middle of a period of increasing energy-related
costs coupled with substantial new investments being made by the Company to
serve customer energy demands. As a result, basing rates on a test period that
doesn t reflect the cost to serve customers during the rate effective period
effectively denies the Company a reasonable opportunity to earn the return
authorized by the Commission.
The Company expects a significant amount of growth across our system
over the next several years. The need to serve this growing load has required the
Company to acquire new generating resources, some of which are being reflected
in rates for the first time in this case. This filing includes 534 megawatts of
additional production capacity at the Lake Side generating facility, as well as
three new wind projects, the Leaning Juniper, Marengo, and Goodnoe Hills
projects, which add a total of 335 megawatts of capacity. Significant new
investments in transmission and distribution systems are required to integrate
these new resources and ensure continued reliability. Net power costs continue to
escalate as a result of increasing fuel costs, purchased power and load growth.
When operating costs and investments in new plant are stable the use of a
historic test period may be a reasonable regulatory approach, but only a forecast
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test period can fully capture the impacts of growing customer load, the dramatic
increases in capital investment required to serve it, and the operation and
maintenance costs required to maintain system safety and reliability. The use of a
forecast test year is the best method for the Company to properly reflect for rate-
setting purposes the costs the Company will incur in the rate effective period to
provide the level of service our customers demand and deserve.
What does the Company want the Commission to consider in relation to the
use of forecasted test periods?
The Company respectfully requests that the Commission allow Rocky Mountain
Power in future rate cases to use fully forecasted test periods that match the costs
and revenues during the rate effective period. As such, the Company requests that
a process be established to discuss the use of forecasted test periods with
interested parties in Idaho.
REVENUE REQUIREMENT CALCULATION
Please describe Exhibit No. 11.
Exhibit No. 11 , which was prepared under my direction, is Rocky Mountain
Power s Idaho Results of Operations Report (the Report). The Report is based on
historical data for the twelve-months ended December 31, 2006, which has been
normalized based on known and measurable changes through December 31 , 2007.
The Report provides totals for revenues, expenses, depreciation, net power costs
taxes and rate base, from both a total-company perspective and as allocated to the
Company s Idaho jurisdiction. The Report presents operating results for the
period in terms of both return on rate base and ROE.
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Please describe how Exhibit No. 11 is organized.
Tab 1 Summary is the Idaho allocated results based on the Revised Protocol
allocation methodology. Page 1.0 details the calculation of the rate mitigation cap
which lowers the rate request by $3.6 million.
Column (1) Total Adjusted Results on Page 1.1 is the Idaho results of
operations for the Test Period and shows the current Idaho earnings. The Total
Adjusted Results column is carried forward from the results of operations
summary, Page 2., and shows Idaho s ROE at 5.3 percent. Column (2) Price
Change indicates that a revenue increase of $22.0 million is required to raise the
return on equity from 5.3 percent to 10.75 percent in Idaho. Column (3) Results
with Price Change reflects the Idaho adjusted revenue requirement with the $22
million price increase included. Page 1.2 of Tab 1 supports the calculation of
additional revenue-related uncollectible expense associated with the price change
requested in column 2 and the net-to-gross bump up percent. 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.
Rocky Mountain Power summarizes adjustments into three different types.
Type I adjustments represent base period accounting or Commission-ordered
adjustments (i., reversing one-time write-offs). Type II adjustments typically
annualize events that occurred during the base year (i.e., contract changes or wage
increases). Type III adjustments reflect known and measurable events occurring
in the twelve months following the base period. Page 1.5 is a summary of all the
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normalizing adjustments by category contained in Tabs 3 through 8.
Tab 2 details Total Company and Idaho allocated results based on the
Revised Protocol allocation methodology. Pages 2.3 through 2.39 contain
revenues, expenses and rate base detail by FERC account. The Adjusted Total
Column of the results on page 2.2 reflects the costs, revenues and rate base that
have been calculated as described later in my testimony.
The normalizing adjustments made to actual period data to reflect on-
going costs of the Company are described in Tabs 3 through 8. Tab 9 is a
restatement of Tab 2 Idaho results using the Rolled-In allocation method instead
of the Revised Protocol allocation method. The Tab 9 results are used to calculate
the rate mitigation cap adjustment on page 1.0. Tab 10 contains the calculation of
the Revised Protocol allocation factors.
Please describe some of the key areas where the Company has experienced
cost increases driving the need for the requested price increase.
Rocky Mountain Power has incurred increases in two main areas to serve its
Idaho customers: (1) new plant investment and the associated operation
maintenance and depreciation costs, and (2) net power costs to serve retail load.
The Company continues to make significant investments to serve its
customers adding over $1.8 billion of plant since the Company s last Idaho filing
in Case No. PAC-06-04. Consequently, Idaho s allocated net rate base has
increased by $51 million. This additional plant has also increased Idaho
depreciation expense by approximately $2 million and incremental operation and
maintenance costs by $653 000. As I mentioned earlier a significant portion of
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these plant increases are associated with the new combustion cycle and wind
generation plants the Company is adding to meet retail load requirements. The
justification for these new resources is explained in the testimony of Company
witness William J. Fehrman.
Net power costs continue to increase due to a combination of increasing fuel
costs, purchased power and customer load growth. Net power costs in Docket No.
P AC-06-, were filed at $685 million compared to $861 million requested in
this application. Details supporting the calculation of net power costs are provided
in the testimony of Company witness Mark Widmer.
REVENUES
Please describe the revenue normalizing adjustments made in Tab 3,
Revenue Adjustments.
Page 3.0 of tab 3 is a summary of all the adjustments in Tab 3, listing each in a
separate column itemizing the impact to revenue and rate base. The adjustments
made to normalize test period revenue are detailed on lead sheets 3.1 through 3.
with supporting documentation. I will briefly describe each of these adjustments.
Temperature Normalization (page 3.1) - Normalizes the revenue by comparing
actual load to temperature normalized load. 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
adjusted for temperature. Since weather during the base period was slightly more
extreme than average, the adjustment reduces Idaho revenue by $1 778 856. This
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adjustment to revenues corresponds to the temperature adjustment made to system
peak and energy loads.
Effective Price Change (page 3.2) - This adjustment has two components:
1) The Company is continuing to eliminate Schedule 19. This adjustment
includes annual revenues of Schedule 19 customers who bill cheaper on
Schedule 6 or 23.
2) Schedule 401 had a rate change effective September 1 , 2006, that has been
annualized in the results of operations.
Thesetwo items combined increase revenues by $91 557.
Revenue Normalization (page 3.3) - This adjustment normalizes base year
revenue by removing items that should not be included to determine retail rates
such as credits from the Bonneville Power Administration (BP A). The expense
side of the BP A credit is removed in adjustment 5.6. Another element is a pro-
forma price change for Schedule 400 and Schedule 10 which was effective
January 1 2007. The combined result of these elements totals a revenue increase
of $41 131 903.
SO2 Emission Allowances (page 3.4) - The Company has excess SO2
allowances which it periodically has the opportunity to sell. This adjustment
reflects actual sales through March 2007 and planned sales through December
2007. The Company amortizes these sales over a fifteen-year period to closer
match the revenues with the plant that generated them. This adjustment reverses
the actual sales booked during the test period and replaces those with the
corresponding amortization. The unamortized balance is included as a reduction
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to rate base. This amortization increases Idaho revenues by $172 909 and reduces
rate base by $1 458 728.
Revenue Correcting Entries (page 3.5) - The jurisdictional assignment of
general business revenues is determined by profit centers within the Company
accounting system. The Company has profit centers that cross state borders in
California, Oregon, and Washington, and the assignment of revenues booked to
those profit centers currently requires a manual adjustment. This adjustment
corrects the jurisdictional assignment and does not impact Idaho results. In
addition, some other electric revenues were assigned incorrect allocation factors
in 2006 unadjusted results. This adjustment corrects these allocation factors
increasing Idaho revenues by $994 639.
Wheeling Revenues (page 3.6) - In calendar year 2006 the Company was able to
collect some outstanding accounts receivable for service provided in prior years.
Also, several contract agreements were terminated and are not expected to be to
be renewed. These transactions are removed to reflect an on-going level of
wheeling revenues in the test period, reducing Idaho s allocation of wheeling
revenues by $325 262.
Are there additional adjustments to revenue that are included in other
portions of Exhibit No. 11?
Yes. The following adjustments are categorized as adjustments to net power costs
but both affect revenue allocated to Idaho. Both of these adjustments are
explained further in the net power costs section of my testimony.
Net Power Cost Adjustment (page 5.1) - A portion of this adjustment aligns
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wholesale sales to the results generated in the GRID model. Company witness
Mark Widmer explains how these sales were calculated in his testimony.
James River & Little Mountain Offset (page 5.5) - This adjustment includes a
revenue offset to the cost of power purchased based on contractual terms.
OPERATION, MAINTENANCE (O&M), ADMINISTRATIVE & GENERAL
(A&G) EXPENSES
Please describe Tab 4 O&M Adjustments?
Pages 4.0 through 4.0.2 summarize each adjustment in Tab 4, listing each in a
separate column itemizing the impact to expense and rate base. The adjustments
made to normalize test period expense are detailed on pages 4.1 through 4.19. The
lead sheet of each adjustment is organized by FERC account, dollar amount and
allocation factor, along with a brief description ofthe adjustment. Any applicable
supporting documentation is provided behind the lead sheets.
Are labor-related expenses treated differently than non-labor costs?
Yes. Labor-related expenses (wages, incentives, pension and benefits) are
identified and analyzed separately from non-labor costs. Wages are refined further
to identify individual labor groups. Wage increases based on union contracts are
applied to the corresponding union group and actuarial studies are utilized to
determine the appropriate expense level for pensions and employee benefits. Page
1 of my exhibit describes the process used to normalize wage and benefit
costs in further detail in the report.
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Please explain the adjustment to wages and benefits summarized on lead
sheets 4.2 through 4.
Pages 4.2 through 4.5 calculate the normalized level of wages and benefits
expected during the test period. The calculations include increases for employee
salaries and medical benefits and decreases to incentive and pension costs. The
net change in these four tabs increases jurisdictional expense by $920 331.
Was an adjustment made to the annual incentive plan payout?
Yes. The Company s Annual Incentive Plan provides performance awards based
on the following: achieving individual and group goals including safety goals
individual performance, and success in addressing new issues and opportunities
that may arise during the course of the year. The details of the plan and
justification for the expected annual payout are provided in the testimony of
Company witness Erich Wilson. To align incentive pay included in this
application to the level expected on an on-going basis, the annual expense is
reduced from $34 million to $27.5 million.
Were employee pension and benefit costs adjusted in this section also?
Yes. Consistent with other categories, pension and benefits are itemized starting
with actual results and walked forward through December 2007. Pension and
other post-retirement benefit costs are decreasing over $5 million. Medical and
other employee benefits expenses are increasing $18.3 million. These amounts are
supported in the testimony of Company witness Erich Wilson.
Does this labor-related section cover any other items?
Yes. Payroll taxes are updated to capture the impact of the changes to employee
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salaries. This is calculated by applying the FICA tax rates to the net change in
salaries.
How are adjustments to labor expenses incorporated into the O&M
Summary?
After adjusting employee salaries and benefits, the costs are spread back to FERC
accounts based on the same percentage that existed in the base period. Pages
5.11-13 contain a summary of this spread.
Please explain the remaining adjustments to operation and maintenance
expense.
Miscellaneous General Expense (page 4.1) - This adjustment removes from
results of operation $24 047 of miscellaneous expenses that should have been
charged to non-regulated accounts and excluded from the revenue requirement
calculation. Included are Blue Sky program expenses, donations to community
and local events, and Klamath ranch management expenses.
International Assignees (page 4.6) - The International Assignee adjustment
removes costs associated with former employees on international assignments
from Scottish Power. These costs were incurred prior to the MEHC transaction
which was finalized March 21 , 2006. Since these costs are not ongoing they are
removed from results, reducing expense by $17 198.
Removing Non-Recurring Expense (page 4.7) - Four adjustments are made to
remove either one-time or out-of-period transactions included in the base period
results. This adjustment removes $354 279 associated with the following
transactions:
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. A right-of-way settlement for past use related to the Crow tribe.
. A settlement accrual associated with the 2003 Utah winter storm.
. MEHC transaction and Rocky Mountain Power re-branding expenses.
Blue Sky funded solar panels at the Salt Palace.
Memberships & Subscriptions (page 4.8) - This adjustment reduces expense by
$40 623 to reflect discontinuance of the Company s membership in Edison
Electric Institute and partial removal of industry trade membership fees that might
be used for political purposes. The adjustment removes 25 percent of membership
fees at Pacific Northwest Utility Conference Committee, Utility Air Regulatory
Group, Western Energy Institute and other trade organizations.
Power Delivery Programs (page 4.9) - This adjustment reduces operation and
maintenance expense by $1 292 550 to align the base period with the anticipated
on-going level of expense.
Incremental Generation O&M (page 4.10) - This adjustment adds operation
and maintenance expense into the test period to reflect the incremental cost of
operating and maintaining new investments in supply-side resources. Expenses
are included only for the number of months each resource will be in service prior
to December 31 2007. The adjustment increases Idaho allocated O&M by
$653 808.
Irrigation Load Control Program (4.11) - Incentive payments made to Rocky
Mountain Power customers participating in the Schedule 72 irrigation load control
program were initially system allocated in the unadjusted data. This adjustment
corrects that allocation assigning these costs situs to Idaho consistent with other
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demand side management (DSM) programs.
DSM Amortization Removal (page 4.12) - The Company recovers authorized
DSM expenses through a system benefit charge (SBC) tariff rider, Schedule 191.
This adjustment removes the related amortization of DSM costs from results to
ensure they are not included in the revenue requirement calculation.
Idaho Intervenor Funding (page 4.13) - This adjustment adds the costs
associated with Idaho intervenor funding to results, amortizing previously
deferred expenses over one year.
Idaho Cash Basis Pension Funding (page 4.14) - The Commission has ordered
other in-state utilities to include cash contributions for pension funding in rates
rather than their F AS 87 pension accrual. The Company would prefer to include
the F AS 87 accrual in rates consistent with treatment in its other jurisdictions.
However, given the Commission s direction in other cases, the Company has
adjusted its expense level to the cash contribution expected during the test period
increasing Idaho allocated expense by $1 000,086.
Grid West Loan (page 4.15) - This adjustment replaces the accrual for bad debt
with the amortization of the loan as approved by the Commission in Order No.
30156, Case No. PAC-06-03. The Grid West loan is discussed later in my
testimony in the section regarding deferred accounting items.
Postage Increase (page 4.16) - Effective May 14 2007, the U.S Postal Service
increased its rates by $0.02 from $0.29 to $0.31 for utility mailings. This
adjustment reflects that additional cost by applying the two-cent increase to the
average number of retail customers during calendar year 2006. The adjustment
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increases Idaho allocated expense by $10 097.
MEHC Transition Savings (page 4.17) - After completion of the MEHC
acquisition ofPacifiCorp certain cost saving programs were implemented. The
major focus was to reduce the amount of corporate overhead by eliminating
several employees' positions. Those whose positions were eliminated qualified
for a change-in-control (CIC) severance payout based on years of service and
salary. This adjustment removes the salary and severance paid to these former
employees. Deferral of this severance cost was authorized in the Idaho Public
Utility Commission Order No. 30225, Case No. PAC-06-11. The Company is
proposing a three-year amortization of this deferral and has included one year of
amortization expense in this filing. The net impact of this adjustment is to
decrease Idaho allocated expense by $2 962 769.
Rocky Mountain Power expects annual savings of $35.4 million related to
the MEHC transition related employee reductions. In order to achieve these
savings Rocky Mountain Power spent $39.5 million for CIC severance payments.
This results in a payback period of less than 15 months. The three-year
amortization is proposed as a way of better matching the CIC-related costs to the
savings expected from the employee reductions. Page 4.19 described below shows
that these employee reductions are not being used to meet the A&G cost
commitment included in commitment 131.
MEHC Affiliate Management Fee and Direct Billings Commitment (page
18)
This adjustment complies with MEHC acquisition commitments and has two
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elements. First, MEHC commitment 128 states:
a) MEHC and PacifiCorp will hold customers harmless for increases in
costs retained by PacifiCorp that were previously assigned to affiliates
relating to management fees. The total company amount assigned to
PacifiCorp s affiliates is $1.5 million per year, which is the amount of the
total company rate credit. This commitment expires on December 31
2010. This Commitment is in lieu of Commitment 38, and a state must
choose between this Commitment 128 and Commitment 38. (The
commitment is reflected in Row 2 of Appendix 2.
b) This commitment is offsetable to the extent PacifiCorp demonstrates to
the Commission s satisfaction, in the context of a general rate case the
following:
i) Corporate allocations from MEHC to PacifiCorp included in
PacifiCorp s rates are less than $7.3 million;
ii) Costs associated with functions previously carried out by
parents to PacifiCorp and previously included in rates have not
been shifted to PacifiCorp or otherwise included in PacifiCorp
rates; and
iii) Costs have not been shifted to operational and maintenance
accounts (FERC accounts 500-598), customer accounts (FERC
accounts 901-905), customer service and informational accounts
(FERC accounts 907-910), sales accounts (FERC accounts 911-
916), capital accounts, deferred debit accounts, deferred credit
accounts, or other regulatory accounts.
PacifiCorp has only included $7.3 million in this application for management fee
billings. (The historical test year includes three months of billings from Scottish
Power and nine months from MEHC. However, the total amount of $7.3 million
is expected to be the on-going level of annual charges from MEHC.) Since the
total charges included in the case are at $7.3 million no additional adjustment was
necessary .
MEHC commitment 130 states:
a) MEHC and PacifiCorp will hold customers harmless for increases in
costs resulting from PacifiCorp corporate costs previously billed to PPM
and other former affiliates ofPacifiCorp. Oregon Commission Staffhas
valued the potential increase in total company revenue requirement if
these costs are not eliminated as $7.9 million annually (total company)
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through December 31 , 2010 and $6.4 million annually (total company)
from January 1, 2011 through December 31 , 2015, which shall be the
amounts of the total company rate credit This commitment shall expire on
the earlier of December 31 , 2015 or when PacifiCorp demonstrates to the
Commission s satisfaction, in the context of a general rate case, that
corporate costs previously billed to PPM and other former affiliates have
not been included in PacifiCorp s rates. This Commitment is in lieu of
Commitment 38, and a state must choose between this Commitment I 30
and Commitment 38.
b) This commitment is offsetable to the extent PacifiCorp demonstrates to
the Commission s satisfaction, in the context of a general rate case, that
corporate costs previously billed to PPM and other former affiliates have
not been included in PacifiCorp s rates.
PacifiCorp has reduced costs and transferred 31 employees to PPM who had been
previously charging part of their time to PPM. This will result in annual salary
and benefit savings in excess of $6.2 million.
Most of the employee transfers to PPM occurred in 2005. However, $243
thousand related to these transferred employees was in the test period prior to the
MEHC transaction. This amount is removed in this adjustment. The remainder of
the $7.9 million reduction was achieved through elimination of other corporate
costs.
Administrative and General Cost Commitment (page 4.19) - Commitment 131
of the MEHC transaction established a rate credit if the amount of A&G included
in the case exceeds a specified level.
a) MEHC and PacifiCorp commit that PacifiCorp s total company A&G
costs as reflected in FERC Accounts 920 through 935 will be reduced by
$6 million annually from a baseline amount of $228.8 million. The
maximum amount of the total company rate credit in any year is $6
million per year. This commitment expires December 31 , 2010. Beginning
with the first month after the close of the transaction, Idaho s share of the
$0.5 million monthly rate credit will be deferred for the benefit of
customers and accrue interest at PacifiCorp s authorized rate of return.
This Commitment is in lieu of Commitments 22 and U 23 from the Utah
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settlement, and a state must choose between this Commitment I 31 and
Commitments 22 and U 23.
b) The credit will be offsetable on a prospective basis, for every dollar that
PacifiCorp demonstrates to the Commission s satisfaction, in a subsequent
general rate case, that total company A&G expenses included in
PacifiCorp s rates (including any adjustments adopted by the Commission
to these categories) are less than $6 million above the "Stretch Goal" and
have not been shifted to other regulatory accounts. The 2006 Stretch Goal
will be $222.8 million. Subsequent Stretch Goals shall equal the 2006
Stretch Goal multiplied by the ratio of the Global Insight's Utility Cost
Information Service (UCIS)-Administrative and General- Total
Operations and Maintenance Index (INDEX CODE Series JEADGOM),
for the test period divided by the 2006 index value. If another index is
adopted in a future PacifiCorp case, that index will replace the
aforementioned index and will be used on a prospective basis only. If this
occurs, the Stretch Goal for future years will equal the Stretch Goal from
the most recent full calendar year multiplied by the ratio of the new index
for the test period divided by the new index value for that same most
recent full calendar year.
The commitment is to reduce A&G expense to $222.8 million on a total-
company level. In 2006, actual A&G expenses totaled $239 million; however
after taking normalizing adjustments into account, the test period in this
application includes only $208.5 million for A&G expense, well below the $222.
million specified in the commitment. In addition, pursuant to the Commission
order in Case No. PAC-06-, the Company has been deferring Idaho
allocated share of the committed reductions since April 1, 2006, and will continue
to defer the credit until new rates are effective that reflect the reduction in A&G
expense.
In the MEHC transition deferral case the Commission ordered that Rocky
Mountain Power could not use the transition reductions to meet the A&G cost
commitment and also request recovery of the CIC related costs (Order No.
30225). The bottom of page 4.19.1 includes a recalculation of the A&G
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commitment showing that absent the MEHC transition-related savings included
on page 4.17 the A&G expenses would have been $211.3 million, which is also
below the $222.8 million commitment level. This shows that Rocky Mountain
Power was significantly below the A&G commitment even without the savings
associated with the transition-related employee reductions.
Are there additional cost changes expected as a result of the MEHC
transaction?
Yes. The commitments to accelerate distribution circuit fusing and continue the
Saving SAIDI program, as agreed in general commitment 35, are expected to
increase expense. The distribution circuit fusing program is expected to increase
costs by $1.5 million per year for five years. The Saving SAID I initiative will be
extended for three years at an additional cost of $2 million annually. However
additional cost savings from these two programs are expected to offset the
expense.
Net Power Costs
Please explain the adjustments to power costs.
Net Power Cost Adjustment (page 5.1) - This adjustment normalizes power
generation, fuel, purchased power, wheeling expense, and sales for resale based
on normal hydro and weather conditions and in a manner consistent with the
contractual terms of the Company s sales and purchase agreements. The
calculation of net power costs is explained in detail in Company witness Mark
Widmer s testimony.
Trail Mountain Closure (page 5.2) - The Trail Mountain Mine was used to
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supply coal to the Hunter Plant. The mine was closed and regulatory assets were
recorded on the Company s books in April 2001 for purposes of amortizing the
costs associated with closing the mine through March 2006. The associated
amortization expense was excluded from the cost of coal. This adjustment
removes all balances from results because the assets were fully amortized prior to
the end of 2006.
West Valley Lease (page 5.3)- West Valley is a gas-fired"generating unit
located in West Valley City, Utah. This adjustment reduces the annual lease
expense for the West Valley facility as agreed in MEHC transaction commitment
127:
a) MEHC and PacifiCorp commit to reduce the annual non-fuel costs to
PacifiCorp customers of the West Valley lease by $0.417 million per
month (total company) or an expected $3.7 million in 2006 (assuming a
March 31 , 2006 transaction closing), $5 million in 2007 and $2.1 million
in 2008 (the lease terminates May 31 , 2008), which shall be the amounts
ofthe total company rate credit. Beginning with the first month after the
close of the transaction to purchase PacifiCorp, Idaho s share of the
monthly rate credit will be deferred for the benefit of customers and
accrue interest at PacifiCorp s authorized rate of return. (This commitment
is reflected in Row 1 of Appendix 2.
b) This commitment is offsetable, on a prospective basis, to the extent
PacifiCorp demonstrates to the Commission s satisfaction, in the context
of a general rate case, that such West Valley non-fuel cost savings:
i) are reflected in PacifiCorp s rates; and
ii) there are no offsetting actions or agreements by MEHC or
PacifiCorp for which value is obtained by PPM or an affiliated
company, which, directly or indirectly, increases the costs
PacifiCorp would otherwise incur.
Starting on March 21, 2006, the lease reduction is included in unadjusted results.
This adjustment reduces the lease by $417 000 per month for the period January
2006 to March 21 , 2006, for a total reduction of$1.1 million total company, or
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$86 thousand allocated to Idaho.
Effective March 21 2006, the savings related to the West Valley lease
have been deferred pursuant to the Commission order in Case No. P AC-06-05.
To be consistent with the commitment, these savings will be deferred until they
are reflected in rates. Page 5.1 shows a schedule of the Idaho related deferrals
assuming a January 1, 2008, effective date of new rates from this application.
Once the final deferral amount is known, the accumulated credit balance will be
returned to Idaho customers through rates as determined in a future rate case.
Green Tag - Renewable Energy Credit (page 5.4) - The base period includes
renewable energy credits purchased with Blue Sky program funds. Because the
Blue Sky program should not impact regulated results, this adjustment removes
the cost of those credits from results reducing Idaho expense by $40 484.
James River Royalty & Little Mountain Offset (page 5.5) - In 1993
PacifiCorp executed a contract with James River Paper Company with respect to
the Camas mill, later acquired by Georgia Pacific. Under the agreement
PacifiCorp built a steam turbine and purchases steam from the mill to power the
turbine. Included in PacifiCorp s net power costs as purchased power expense are
the contract costs of steam energy for the Callas unit, but the power cost model
(GRID) does not include an offsetting revenue credit for the capital cost recovery
and maintenance cost recovery amounts. This adjustment adds the royalty offset
to account 456, Other Electric Revenue, increasing Idaho revenues by $437 824.
This adjustment also normalizes the ongoing level of revenues related to
steam sales from the Little Mountain generator to a nearby customer.
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Contractually, the steam revenues from the Little Mountain plant are tied to
natural gas prices. The GRID model calculates the cost of running the Little
Mountain plant but does not include the offsetting steam revenues. This
adjustment aligns the steam revenues to the gas prices and plant production
modeled in GRID which decreases Idaho revenues by $117 694.
BP A Regional Exchange (page 5.6) - This adjustment removes the BP
regional exchange credit from Account 555 because this is a pass-through from
BPA to the Company s eligible residential and small farm customers in Oregon
Washington and Idaho, and should not be included in determination of the
Company s revenue requirement. The associated revenue credit was removed in
Tab 3.3.
DEPRECIATION AND AMORTIZATION EXPENSE
How is the depreciation expense for the test period developed in the Report?
The depreciation expense was developed by applying composite depreciation
rates based on the last authorized depreciation study to depreciable plant balances.
This was accomplished in two steps: First, the actual depreciation expense is
annualized for major plant additions added during the base year. Second
depreciation expense is added for pro forma major plant additions added to rate
base between January and December 2007. The amount of expense related to pro
forma plant additions is based on the number of months the resource is included
in the test period rate base. This calculation is summarized on pages 6.1 and 6.
and increases Idaho s depreciation expense by $1 799,722. Page 6.2 takes one-
half of the incremental depreciation expense to adjust the associated accumulated
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depreciation reserve. The full plant detail associated with these major plant
additions are on pages 8.8 through 8.
TAXES
Please describe adjustments to taxes in the Report.
Interest True-up (page 7.1) - This adjustment aligns interest expense with net
rate base by applying the weighted cost of debt to the net investment allocated to
Idaho. This assures that the interest expense taken as a tax deduction is based
solely on utility rate base.
Property Taxes Expense (page 7.2) - This adjustment takes the difference
between the property taxes included in unadjusted results, which are based on
investment balances at January 2006, and taxes calculated based on January 2007
investment balances. This adjustment increases Idaho-allocated property taxes by
$451 877.
Renewable Energy Tax Credit (page 7.3) - The federal government has
extended an income tax credit for investment in qualifying renewable resources.
The Company owns a 78.8 percent share of the Foote Creek wind project in
addition to 100 percent of the Leaning Juniper, Goodnoe Hills and Marengo wind
plants. The tax credit calculation is based on the Company s share of the energy
produced at those facilities multiplied by two cents per kilowatt hour. The
adjustment reduces Idaho income taxes by $787 256.
Gross Receipts Tax (page 7.4) - Utah legislation repealed its gross receipts tax
effective in 2007. Because gross receipts taxes are system allocated, this
adjustment removes that tax from results, decreasing other income tax expense
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allocated to Idaho by $232 726.
Idaho State Tax Settlement (page 7.5) - In fiscal year 2003 the Company made
a state income tax settlement payment of$634 571. Idaho s allocation of this
settlement is based on a five-year average of the Income Before Tax (IBT)
allocation factor with the product amortized over five years. This treatment is
consistent with the Idaho Commission Order No. 29518 and increases expense by
042.
Idaho Investment Tax Credit (page 7.6) - This adjustment normalizes the Idaho
state investment tax credit (ITC) the Company has taken based on property placed
into service. Because PacifiCorp is a 46(f)(1) company, the ITC unamortized
balance is reflected in results of operations as a reduction to rate base.
Update Section 199 Domestic Deduction (page 7.7) - For calendar years 2007
through 2009 the Section 199 domestic production activity deduction rate is 6
percent instead of the 3 percent that was in place for this deduction in calendar
years 2005 and 2006. This adjustment updates the schedule m to reflect the 6
percent rate for calendar year 2007.
Remove Prior Period M Items (page 7.8) - After the completion of the MEHC
transaction PacifiCorp switched its fiscal year from ending in March to align with
a calendar year ending December. This created two fiscal year closes for tax
purposes in March and December. During the twelve-month period ending
December 2006 there are two year-end true-ups for the tax provision. This
adjustment reduces the true-ups to reflect a single annual amount.
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RATE BASE
Please describe each of the adjustments to the rate base balances.
Cash Working Capital (page 8.1) - This adjustment is necessary to true-up cash
working capital for all normalizing adjustments made in this filing. Cash working
capital is calculated by adding total O&M expense allocated to Idaho (excluding
depreciation and amortization) and Idaho s share of allocated taxes. This total is
divided by the number of days in the year to determine the company s adjusted
daily cost of service. The daily cost of service is multiplied by net lag days to
produce the required working capital for daily operations. Net lag days are
calculated using a detailed lead-lag study that analyzes the lead and lag time
associated with the Company s cash receipts and payments. This adjustment
increases rate base by $1 538 111.
Trapper Mine (page 8.2) - PacifiCorp owns a 21.4 percent share of the Trapper
Mine, which provides coal to the Craig generating plant. This investment is
accounted for on the Company s books in account 123., Investment in Subsidiary
Company, which is not included as a rate base account. This adjustment adds the
Company s portion ofthe Trapper Mine net plant investment to rate base in order
for the Company to earn a rate of return on its investment (the normalized coal
cost from Trapper Mine includes all O&M costs but does not include a return on
investment). The adjustment increases Idaho-allocated rate base by $431 740.
Jim Bridger Mine (page 8.3) - PacifiCorp owns a 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
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Rocky Mountain Power
Pacific Minerals, Inc. (PMI). Because of this ownership arrangement, the coal
mine investment is not included in electric plant in service. This adjustment is
necessary to properly reflect the Bridger Coal Company investment in rate base in
order for the Company to earn a rate of return on its investment (the normalized
coal costs for Bridger Coal Company include the O&M costs of the mine, but
provide no return on investment).
The Company s share of rate base related to PMI's investment in the
Bridger coal mine is projected to increase significantly during 2007. Most of the
investment increase relates to Bridger Coal Company s transition to an
underground mine. Production costs for the surface mine are forecasted to
increase significantly due to increased overburden ratios, longer haulage
distances, escalating royalties, and diminishing coal quality. The development of
the underground mine assures customers a long-term least-cost coal supply
altemative. This adjustment increases Idaho rate base by $7,766,323.
Glenrock Mine Removal (page 8.4) - Closure of the Glenrock mine and the sale
of equipment and supplies used for reclamation was completed during 2006. This
adjustment removes those costs from the base period, thereby eliminating
Glenrock mine from ongoing results.
Environmental Settlement (page 8.5) - In 1996, the Company received an
insurance settlement of $33 million for environmental clean-up projects. These
funds were transferred to a subsidiary called PacifiCorp Environmental
Remediation Company (PERCO). This fund balance is amortized or reduced as
PERCO expends funds on clean-up projects. In 1998, PERCO received an
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additional $5 million of insurance proceeds plus associated liabilities from
PacifiCorp. This adjustment includes $1 069 257 of unspent insurance proceeds as
a reduction to Idaho-allocated rate base.
Customer Advances for Construction (page 8.6) - This adjustment is required
to properly assign customer advances for construction that were allocated system-
wide in the unadjusted data. This adjustment reduces Idaho rate base by $499 058.
Centralia Transmission Line Sale (page 8.7) - In December 2006, the
Company completed the sale of the Centralia transmission line to TransAlta
Centralia Generation LLC. This adjustment removes the net investment and
depreciation expense originally included in results.
Major Plant Additions (page 8.8) - This adjustment places into rate base one-
half of major plant additions (defined as projects $2 million or greater) added
during calendar year 2006 (added as a type II adjustment) and calendar year 2007
(added as type III adjustment). Current Creek Phase II, Leaning Juniper, and the
Huntington Unit II scrubber make up the majority ofthe additions added in 2006.
For 2007 major projects include the Lake Side generation facility, Marengo and
Goodnoe Hills wind projects, and the Blundell bottoming cycle investment, along
with significant transmission investments. A complete list of these projects is
included on pages 8.2 - 8.5. Each generation resource investment was
weighted by the in-service date to align the rate base investment with its inclusion
in the calculation of net power costs. The accumulated depreciation reserve was
also adjusted to match the depreciation expense and retirements calculated as
described earlier. Exhibit No. 13 is a summary of the revenue requirement related
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Rocky Mountain Power
to each of these resources based on the investment and costs included in this
filing.
Miscellaneous Rate Base (page 8.9) - This adjustment is made to be consistent
with Commission practice and to reflect known changes to miscellaneous rate
base accounts through December 31 , 2007. The positive balances in the plant held
for future use and cash accounts are removed from rate base. An initial payment
for the Cottonwood coal lease required to secure coal reserves for the Company
generation facilities in southern Utah is added to rate base. An increase to fuel
stock inventory is reflected to capture increases in the cost of coal and additional
tons stored at each site. The net impact of the adjustment is to increase Idaho rate
base by $1 027 706.
Upper Beaver Hydro Sale (page 8.10) - The Company entered into an
agreement to sell the Upper Beaver hydro facilities to the city of Beaver, Utah.
This adjustment removes the net investment, operating costs, property taxes and
depreciation from results, reducing rate base by $106 147 and expense by
$10 702.
Cove Hydro Decommission (page 8.11) - Cove is a hydroelectric facility located
on the Bear River in Idaho. This facility was decommissioned in the Fall of 2006
and most of the assets were retired while a few were transferred to other locations
for use as spare parts. This adjustment removes the retired assets from rate base.
Powerdale Hydroelectric Facility (page 8.12) - Powerdale is a hydroelectric
generating facility located on the Hood River in Oregon. This facility was
scheduled to be decommissioned in 2010; however, in 2006 a flash flood washed
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out a major section of the flow line. The Company determined that the cost to
repair this facility was not economical and determined it was in our customers
best interest to cease operation of the facility. The Company has applied with the
Commission for approval to transfer the un-depreciated net investment to a
deferred account (Case No. PAC-07-04). This adjustment transfers this
investment from electric plant in-service to a regulatory asset and removes the
avoided O&M expense.
REVISED PROTOCOL ALLOCATION METHOD
What allocation methodology is the Company using to calculate the revenue
requirement attributed to its Idaho jurisdiction in this application?
The Company utilizes the Revised Protocol Allocation method (Revised Protocol)
to calculate the Idaho jurisdictional revenue requirement in this application.
Revised Protocol, approved by the Commission in Case No. P AC-02-
prescribes how the costs associated with the Company s generation, transmission
and distribution system will be assigned or allocated among its six state
jurisdictions for purposes of establishing its retail rates. As described in the
Revised Protocol, the Company will continue to plan and operate its generation
and transmission system on an integrated basis in a manner that achieves a least
cost/least risk resource portfolio for all of its customers. The Revised Protocol
describes regulatory policies which, if followed by all states on a long-term basis
should afford Rocky Mountain Power a reasonable opportunity to recover all of
its prudently incurred costs.
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Summarize the allocation of costs using Revised Protocol.
Generation and transmission costs are allocated to all jurisdictions. Plant is
generally allocated using a System Generation (SG) factor which is weighted 75
percent to demand and 25 percent to energy. Generation and transmission O&M
is also allocated on an SG factor. Distribution costs are generally directly assigned
to each jurisdiction. The bulk of A&G costs and the costs of general and
intangible plant are allocated based on each state s proportional share of plant
investment.
Please describe the information included in Tab 10 of this application.
Tab 10 details the calculation of allocation factors and the corresponding
allocation percentages used in this filing, consistent with the Revised Protocol
allocation method.
MEHC TRANSACTION COMMITMENTS
Does the Company s application incorporate the commitments made as a
condition ofthe Commission s approval ofMEHC's acquisition of
PacifiCorp?
Yes. The commitments made as a condition of the Commission s approval of
MEHC's acquisition ofPacifiCorp (Case No. PAC-05-08) cover a broad range
of benefits, including customer service, financial protection, Commission access
to information, affiliate transactions, generation (including renewable resource
and environmental issues), transmission projects, low-income and community
programs, and corporate presence. All commitments directly impacting this
application and the calculation of the Company s revenue requirement have been
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Rocky Mountain Power
taken into account in its preparation.
Please summarize commitment 126 and how your filing incorporates this
commitment.
MEHC transaction commitment 126 states:
MEHC and PacifiCorp commit to $142.5 million (total company amount)
of offsetable rate credits as reflected in Appendix 2 and as described in the
following Commitments I 27 through I 31. These rate credits will be
reflected in rates on the effective date of new rates as determined by the
Commission in a general rate case. The rate credits will terminate on
December 31 , 2010, to the extent not previously offset, unless otherwise
noted. The rate credits in Commitments I 27 and I 31 are subject to
deferred accounting as specified therein. Where total company values are
referenced, the amount allocated to Idaho will equal the Idaho-allocated
amount using Commission-adopted allocation factors.
This commitment references the detailed commitments 127 through 131 which are
each discussed individually in my testimony and detailed in Exhibit No. 11.
Commitment 127 regarding the West Valley lease is discussed above in the
description of adjustment 5.3. Commitments 128 and 130 dealing with affiliate
billings are addressed above in the description of adjustment 4.18. Commitment
131 dealing with the A&G cost commitment is addressed in adjustment 4.19.
Please summarize commitment 129 and how your filing incorporates this
commitment.
MEHC transaction commitment 129 states:
a) MEHC commits to use an existing, or form a new, captive insurance
company to provide insurance coverage for PacifiCorp s operations. The
costs of forming such captive will not be reflected in PacifiCorp
regulated accounts, nor allocated directly or indirectly to PacifiCorp. Such
captive shall be comparable in costs and services to that previously
provided through ScottishPower s captive insurance company Dornoch.
MEHC further commits that insurance costs incurred by PacifiCorp from
the captive insurance company for equivalent coverage for calendar years
2006 through 2010, inclusive, will be no more than $7.4 million (total
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Rocky Mountain Power
company). Oregon Commission Staff has valued the potential increase in
PacifiCorp s total company revenue requirement from the loss of
ScottishPower s captive insurance affiliate as $4.3 million annually, which
shall be the amount of the total company rate credit. This commitment
expires on December 31 2010.
b) This commitment is offsetable ifPacifiCorp demonstrates to the
Commission s satisfaction, in the context of a general rate case, the costs
included in PacifiCorp s rates for such insurance coverage are not more
than $7.4 million (total company).
MEHC formed a new captive insurance company called MEHC Insurance
Services Limited on March 21 , 2006, to comply with this commitment. The costs
associated with this newMEHC insurance coverage from March 21 , 2006, to
December 31 , 2006, are as follows:
Account Description
548522 Captive Property Insurance
548523 Captive Liability Insurance
Amount
$ 4,468 565
$ 1 276,086
$ 5 744 651
x 365/285
$ 7,357 184
Annualize Mar 21 - Dec 31
The $5 744 651 represents the total insurance payments after the MEHC
transaction close. Since this was only for 285 days, the number is annualized to
compare against the $7.4 million commitment. Since the annualized insurance
cost is less than $7.4 million, no adjustment is necessary.
DEFERRAL ACCOUNTING
Please summarize the accounting deferrals included in this filing.
The following accounting deferrals are included in this filing:
GRID West Loan (page 4.15; Case No. PAC-06-03)
MEHC Rate Credits (pages 4., 4.19, and 5.3; Case No. PAC-06-05)
MEHC Transition Savings (page 4.17; Case No. PAC-06-11)
Powerdale Hydroelectric Facility (page 8.12; Case No. PAC-07-04)
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Rocky Mountain Power
Where available, the Company has reflected the deferral according to the
Commission Order. The Company respectfully requests the Commission
recognize the ratemaking treatment for each of the deferrals. The Company also
requests the Commission issue its Order specifying that new rates reflect the
MEHC transaction rate credits (i.e. commitment 126, including the West Valley
lease, affiliate billings, and the A&G cost commitment) in order for the Company
to discontinue the monthly deferral of the agreed upon amounts and officially
satisfy the related commitment. In that case, the Company s next general rate case
will reflect the return of the accumulated deferred balances to its customers.
Does this conclude your testimony?
Yes.
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