20160901Weston Direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION
OF ROCKY MOUNTAIN POWER TO
UPDATE BASE NET POWER COSTS AND
IMPLEMENT A RA TE STABILITY PLAN
) CASE NO. PAC-E-16-12
)
) DIRECT TESTIMONY OF
) TEDWESTON
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ROCKY MOUNTAIN POWER
CASE NO. PAC-E-16-12
September 2016
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Please state your name, business address and present position with Rocky
Mountain Power (the "Company"), a division of PacifiCorp.
My name is Ted Weston and my business address is 1407 West North Temple, Suite
4 330, Salt Lake City, Utah, 84116. I am currently employed as the Manager of
s Regulatory Affairs for Idaho.
6 QUALIFICATIONS
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Briefly describe your educational and professional background.
I received a Bachelor of Science Degree in Accounting from Utah State University
in 1983. I began my employment with the Company in June of 1983 and have held
various accounting and regulatory positions since then. In addition to formal
education, I have attended educational, professional, and electric industry related
seminars during my career with the Company.
What are your responsibilities as Manager of Regulatory Affairs?
My primary responsibilities include the coordination and management of Idaho
Is regulatory filings, communications, and oversight of reporting requirements with
16 the Idaho Public Utilities Commission ("Commission").
I 7 PURPOSE OF TESTIMONY
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What is the purpose of your testimony in this proceeding?
My testimony supports the Company's compliance filing to update net power costs
("NPC") and retail load used for the Load Change Adjustment Rate and other
components of the Energy Cost Adjustment Mechanism ("ECAM") effective
January I, 2017, and presents an alternative Rate Stability Plan proposal to mitigate
future rate impacts for customers.
Weston, Di - I
Rocky Mountain Power
BACKGROUND
2 Q. Please explain why the Company is making this filing.
3 A. The Company filed an application' on May 27, 2015 , with the Commission to: (I)
4 increase base rates by $10.2 million effective January 1, 2016; (2) increase the level
5 ofNPC in base rates, thereby reducing ECAM deferrals; and (3) modify the ECAM.
6 After negotiating with parties, a Stipulation was reached and later approved by the
7 Commission.2 The Stipulation requires a NPC update effective January 1, 2017.
8 The update is to be based on the normalized NPC reported in the 2015 annual Result
9 of Operations report, which was provided to the Commission on April 30, 2016.
10 The Stipulation specified that the rate spread and rate design would be on an equal
11 cents per kilowatt hour ("kWh") basis, consistent with the rate increase from that
12 case. The Company committed to make the filing by September 1, 2016, to provide
13 time for review and approval prior to the January l, 2017, rate effective date.
14 Net Power Cost Update
15 Q. Please describe the impact of the NPC update and compare it to the level of
16 NPC currently in rates ("Base NPC").
17 A. The NPC reported in the 2015 Results of Operations were $1.485 billion on a total
18 Company basis; Idaho's allocation of these costs was $91.6 million or $26.90 per
19 megawatt hour ("MWh"). Base NPC included in rates are $1.529 billion total
20 Company, with Idaho's allocation approximately equal to $94.8 million or $27.21
21 per MWh. The two main drivers behind the reduction to NPC are reduced load and
22 lower prices. Both total system and Idaho retail load were lower during calendar
1 Case No. PAC-E-15-09.
2 Order No. 33440.
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Rocky Mountain Power
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year 2015 than they were in the Base NPC. Idaho's 2015 retail load was 3,407,488
MWh compared to the current base of 3,483,480 MWh. This volumetric load
change accounted for $2.1 million of the $3.2 million reduction to NPC. Company
witness Mr. Michael Wilding's testimony describes the changes to NPC in more
detail.
What impact does this update have on Idaho's annual revenue requirement
and retail rates?
The NPC update reduces Idaho's annual revenue requirement by approximately
$1.1 million. When this amount is divided by Idaho's 2015 retail load, the reduction
is approximately $0.32 per MWh as shown below.
Rate Stability Proposal Total Idaho MWH $/MWH
Base NPC $ 1,529,427,580 $ 94,801,644 3,483,480 $
NPC Collected $ 92,733,539 3,407,488 $
December 2015 N ormalil.ed NPC $ 1,485,447,775 $ 91,646,156 3,407,488 $
Impact ofNPC Update $ (1,087,383) 3,407,488 $
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What is the rate impact to customers of the update to NPC?
A $1.1 million decrease in revenue requirement associated with the reset of the NPC
in base rates results in an average annual decrease of approximately 0.4 percent.
The impact by rate schedule and calculation of the rate change is shown in
Attachment B to Application.
How does the Company propose to handle the customer impact from the NPC
update?
Absent any agreement or approval on an alternative approach, the adjustment to
base rates for the reset ofNPC would flow through to all customer rates on an equal
cents/kWh basis beginning on January 1, 2017, based on the Commission review
Weston, Di - 3
Rocky Mountain Power
27.215
27.215
26.896
(0.319)
and approval of the change being in compliance with Order No. 33440. While
2 implementing a small decrease would be the simplest approach, the Company
3 believes that an alternative exists to address rate stability and mitigate future
4 increases for customers.
5 RATE STABILITY PLAN
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Please explain the Company's alternative proposal.
Order No. 33440 authorized the Company to file an NPC update with rates effective
January 1, 2017, with the option to file a general rate case by June 1, 2017, for a
January 1, 2018, rate effective date. The Company is proposing to work with
intervening parties to determine whether support exists to implement a Rate
Stability Plan through December 31, 2018, and use potential rate reductions that
may otherwise occur during that period to offset growing balances for deferred
regulatory assets that will flow into the next rate case as amortization expense. The
$1.1 million decrease would be included in this plan to pay down the balance
accumulating on the Company's books for depreciation expense that is being
deferred as a result of Commission Order 32910.3
How would the Rate Stability Plan work?
The Company would request an update to Base NPC to $91.6 million, or $26.90
per MWh, but would not adjust retail rates. The NPC update would reduce Idaho's
annual revenue requirement by approximately $1 .1 million or $0.32 per MWh.
However, rather than reducing rates by that amount, the Company recommends
keeping rates at the current level and using the incremental revenue collected from
3 Case No. PAC-E-13-04.
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customers to offset the deferred regulatory asset owed from customers for the 2013
depreciation regulatory asset.
Are there other aspects for consideration in the Rate Stability Plan?
Yes. In addition to holding base rates constant for the net power cost reset, the
Company is evaluating the impact of holding ECAM rates constant at current levels
in 2017 if the annual true-up filing would otherwise result in a rate decrease, and
use the funds to offset other growing regulatory assets to mitigate the rate impact
on future general rate cases. Based on the Company's current estimate for the 2016
ECAM deferral, the June 1, 2017, collection rate could be reduced in the range of
$4.5 to $5.5 million. Rather than implementing rate reductions in 2017 followed by
a general rate change in the near future, the Rate Stability Plan provides an
alternative to hold rates stable and provide more predictability on the timing of the
next general rate case when it could be matched up with the ordered implementation
of the next depreciation study.
The Company would also agree in this context that it would not file a
general rate case prior to June 1, 2018. Customers would benefit from rate stability
and predictability in the near-term, and small refunds owed to customers during this
same period will be used to offset deferred costs owed to the Company with the
intent of minimizing future pressures on rates and continued rate stability.
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Would regulatory assets other than deferred depreciation be considered as
part of the Rate Stability Plan?
Yes. The Commission has authorized deferral of the Carbon plant and Deer Creek
mine. While recovery of the investment in the facilities is occurring, the expenses
incurred to close and reclaim them are being deferred for future rate recovery.
How would this plan mitigate future rate impact?
If the Company simply filed to update Base NPC and decreased rates $1.1 million
January 1, 2017, followed by the annual ECAM filing effective June 1 2017, which
it anticipates would reduce the ECAM rates, whenever the Company filed its next
general rate case, customers will incur a larger increase from the "doubling impact"
of the 2013 depreciation expense.
What do you mean by a "doubling impact" of depreciation expense?
The 2013 depreciation study increased Idaho's annual depreciation expense
approximately $1. 7 million; however, that impact has never been included in rates
as a result of previous stipulations. The incremental depreciation expense is
currently being deferred with a projected balance of $6.9 million by December 31,
2017. If not addressed, the amortization expense from the deferral would also be
included in rates at the same time as the incremental depreciation expense.
Depending on the amortization period, that expense could be as much or more than
the incremental depreciation expense, doubling the impact on rates.
When will the next depreciation study be filed?
The next depreciation study needs to be completed and approved with effective
dates by January 1, 2019. Depending on the timing of the next general rate case the
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rate impact of that study may also be part of the rate case. The implementation of a
new depreciation study with rates anticipated to be effective January 1, 2019, could
potentially triple the incremental impact of depreciation expense in that general rate
case.
Please explain the timing and implementation of the Rate Stability Plan.
Pursuant to the Stipulation,4 updated tariffs were filed as Attachment A to the
Application to reflect the equal cents per kWh impact for all rate schedules.
However, with the option of a Rate Stability Plan, rates would not change January
1, 2017, and instead the Company would calculate the incremental revenues
collected by multiplying the actual monthly retail sales by the $0.00032 cents per
kWh and offset this incremental revenue collection by a corresponding amount of
amortization expense from the depreciation regulatory asset, reducing that balance.
The same type of approach could be taken with the 2017 ECAM filing. The
Company would calculate the ECAM balance from the 2016 deferral and design
rates to collect that amount, but not change rates on Electric Service Schedule No.
94, ECAM Cost Adjustment. Beginning June 1, 2017, the same accounting
adjustment would occur; the incremental cents per kWh reduction from the ECAM
rate would also be applied to the actual kWh from retail sales to calculate the
additional amortization expense applied to the depreciation regulatory asset. The
monthly amortization of the depreciation regulatory asset would equal the
incremental revenues collected and would continue until May 31 , 2018, the end of
the rate effective date of the 2017 ECAM filing. Depending on the actual level of
4 Case No. PAC-E-15-09.
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retail sales, the majority of the depreciation regulatory asset could be collected by
June 1, 2018.
Why would collection of the depreciation regulatory asset in this manner
benefit customers?
Customers benefit in several ways: first, future rate increases would be mitigated;
second, it assures customers pay only what they owe, no more or less; and third,
customers that are benefiting from the use of assets begin to pay for the increased
depreciation since a rate case has not been held for several years; and, finally, it
eliminates long-term intergenerational inequities. When amortizations are included
in base rates, the recovery is dependent on the timing of future rate cases.
Recovering the regulatory asset through a balancing account ensures only the exact
amount owed is paid which is fair for both customers and the Company.
As part of the Rate Stability Plan, what else will the 2018 ECAM filing
consider?
Based on current NPC forecasts the Rate Stability Plan could potentially continue
to keep rates stable through 2018 by decreasing ECAM rates with a corresponding
increase to base rates to shift rate recovery from the ECAM into base rates. For
example, the discussions with intervening parties could explore whether recovery
of Lake Side II could be shifted from the ECAM to base rates, or could adjust the
level of PTC in base rates without any net rate change.
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How would the plan handle any over or under collection of the 2013
depreciation regulatory asset?
If the ECAM deferral and loads are close to forecasted levels, the remaining
depreciation deferral balance would be minimal. The Company recommends
transferring any over or under collection of the depreciation deferral into the 2017
ECAM deferred balance.
What would happen under the Rate Stability Plan if actual NPC in 2017 are
higher than forecasted, resulting in an increase, rather than a decrease in the
ECAM collection rate?
If the 2017 ECAM deferral was higher than the current ECAM collection rate of
$14.5 million the Company would recommend increasing the ECAM collection
rate effective June 1, 2018.
What about the $1.1 million in base rates from the January 1, 2017 Base NPC
update?
After implementing the NPC update January 1, 2017, base rates will be higher by
approximately $1.1 million; initially those additional revenues will be used to
recover the deferred depreciation balance. Effective June 1, 2018, the $I. I million
plus an additional increase of approximately $0.6 million will be required to
incorporate the $1.7 million incremental annual 2013 depreciation expense into
base rates. The $0.6 million would be part of the rate stabilization shift from the
ECAM into base rates.
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Depreciation Regulatory Asset
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What is the 2013 depreciation regulatory asset?
In 2013, the Company filed Case No. PAC-E-13-02 to implement new depreciation
rates. The Commission approved5 the 2013 depreciation rates with a January 1,
2014, effective date. The approved rates incrementally increased Idaho's annual
depreciation expense by approximately $1. 7 million. Order No. 329106 authorized
the Company to create a regulatory asset to defer, on a monthly basis, any aggregate
net increase or decrease in Idaho 's allocated depreciation expense beginning
January 1, 2014, until the date that the 2013 depreciation rates were included in
rates. However, the Company has not filed a general rate case since then so the
incremental depreciation expense continues to be deferred. As of July 31 , 2016, the
balance of the depreciation regulatory asset was $4.3 million and growing by
approximately $150 thousand per month. By December 31, 2017, if plant-in­
service stays flat, the projected balance of the regulatory asset will be
approximately $6.9 million.
When is the Company's next depreciation study due?
The Company is required to update depreciation rates at least every five years;
therefore, new depreciation rates would need to be approved and effective by
January 1, 2019.
5 Order No. 32926
6 Case No. PAC-E-13-04
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Rocky Mountain Power
LAKE SIDE II
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Would you explain how recovery of Lake Side II is currently occurring?
The Commission authorized7 recovery of Lake Side II in the ECAM by using a
4 resource adder of $1.99 per MWh for each hour of production, capped at $5.4
5 million Idaho's annual revenue requirement, with the intent that when the Company
6 filed its next rate case recovery of Lake Side II would be moved into base rates.
7 The Company intends to explore options with parties on the approach and timing
8 of how to move the Lake Side II recovery from the ECAM to base rates and mitigate
9 the impact on rates over time.
10 PRODUCTION TAX CREDITS
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Are PTC currently included in base rates?
Yes. Customers receive a credit or reduction to their annual revenue requirement of
approximately $7 million due to PTC from Company owned wind facilities.
Renewable resources that qualify receive PTC for the first ten years after their in­
service date. The Company built most of its wind facilities from 2006 to 2010.
Under current tax laws, the level of PTC that the Company receives began declining
in 2016 and will be gone by the end of 2020. In Order No. 33440, the Commission
approved dollar for dollar tracking of PTC in the ECAM. The Company intends to
explore options with parties on the approach and timing of how to reflect the
changing level of PTC in base rates and mitigate the impact on the next rate case.
7 Order No. 32910
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If Lake Side II and PTC are tracked in the ECAM with no sharing, how will
customers benefit by shifting recovery into base rates?
Recovery of the ECAM deferral balance occurs up to seventeen months after it's
4 incurred. Accordingly, when the Company files a rate case, the updated revenue
5 requirement would include the impact for these two items in base rates, which
6 would overlap with recovery of the deferred amounts through the ECAM for up to
7 17 months before those deferred amounts drop out of the ECAM. However, if
8 recovery of all or a portion of these costs could be transitioned into base rates prior
9 to the next general rate case while holding rates flat on a net basis through a
10 reduction to the ECAM, customers would benefit through rate predictability and
11 less volatility in rates ..
12 CONCLUSION
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Please summarize the Company's alternative Rate Stability Plan contained in
this Application.
The Rate Stability Plan would: (1) update Base NPC effective January 1, 2017, to
$91.6 million or $26.90 per MWh; (2) not changing base or ECAM rates prior to
June 1, 2018; (3) utilize the incremental revenue collected from base and ECAM
rates to amortize the 2013 depreciation deferred balance; and (4) delay filing the
next general rate case one year with rates not effective prior to January 1, 2019. The
Rate Stability Plan would provide customers two additional years of rate stability
while addressing several pending regulatory issues and mitigating future rate
impact.
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Q. Does this conclude your direct testimony?
2 A. Yes.
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