20150527Wilding Direct.pdf

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE
APPLICATION OF ROCKY MOUNTAIN
POWER TO MODIFY THE ENERGY
COST ADJUSTMENT MECHANISM AI\[D
INCREASE RATES BY $10.2 MILLION,
OR APPROXIMATELY 3.9 PERCENT
ROCKY MOUNTAIN POWER
Case No. PAC-E-15-09
DIRECT TESTIMONY OF
MICHAEL G. WILDING
CASE NO. PAC-E.15.09
May 2015
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a.Please state your name, business address and present position with
PacifiCorp, dba Rocky Mountain Power (the "Company'o).
A. My name is Michael G. Wilding. My business address is 825 NE Multnomah
Street, Suite 600, Portland, Oregon 97232. My title is Net Power Cost Specialist.
Qualifications
a. Briefly describe your education and business experience.
A. I received a Master of Accounting from Weber State University and a Bachelor of
Science degree in accounting from Utah State University. I am a Certified Public
Accountant licensed in the State of Utah. Prior to joining the Company, I was
employed as an internal auditor for Intermountain Healthcare and an auditor for
the Utah State Tax Commission. I have been employed by the Company since
February 2014.
a. Have you testified in previous regulatory proceedings?
A. Yes. I have filed testimony in proceedings before the Idaho Public Utilities
Commission and the Wyoming Public Service Commission.
Purpose and Summary
0. What is the purpose of your testimony?
A. My testimony supports the Company's Application to update the net power costs
("NPC") in base rates that are compared to actual NPC in the energy cost
adjustment mechanism ("ECAM"). I also present and support proposed
modifications to the ECAM.
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Rocky Mountain Power
I Q. Please summarize the impact of the Company's proposed update to base
2 NPC.
3 A. The Company proposes to update the level of base NPC in customers' rates based
4 on the normalized NPC reported in the Company's recently-filed December 2014
5 Results of Operations. Total company NPC in the results of operation is $1,514
6 million, or $93.8 million on an ldaho-allocated basis. This compares to $1,385
7 million total-company, or $87.6 million Idaho-allocated, NPC currently included
8 in base rates as a result ofthe 201 I general rate casel.
9 Q. Will any items other than NPC be included in the update of base rates?
10 A. Yes. As shown Exhibit No. 3 accompanying the testimony of Ms. Joelle R.
1l Steward, the update of $10.2 million to base rates would include updates to NPC
12 of $2.8 million, revenue from the sale of renewable energy credits ("RECs") of
13 $6.5 million, and renewable energy production tax credits ("PTCs") of $0.2
14 million. Each of these items would be subject to true-up in the annual ECAM
15 filings. [n addition to these items, base rates would include $0.7 million for the
16 incremental amortization of the Deer Creek Mine unrecovered investment
17 (depreciation and depletion expense), as requested in the Company's application
l8 in Case No. PAC-E-I4-10. Since this amortization is a fixed annual amount, there
19 is no need to include it in the ECAM going forward once it is included in base
20 rates.
2l a. Please summarize the Company's proposed modifications to the current
22 ECAM.
23 A. The Company is proposing the following changes to the ECAM:
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Rocky Mountain Power
I Case No. PAC-E-I1-12.
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The 90/10 percent sharing band should be eliminated, allowing for 100
percent recovery of prudently-incurred NPC;
The calculation method should be based on retail sales at meter,
eliminating the need for Staff s base rate over-collection adjustment;
The load change adjustment rate ("LCAR") should be eliminated;
Demand side management ("DSM") costs and sales of sulfur dioxide
emission allowances ("SOz Sales") should no longer be tracked in the
ECAM;
PTCs should be included in the ECAM as they are closely related to NPC;
The deferral period should be changed to correspond with the calendar
year and the filing date should be changed to April I with rates effective
June l.
Why is the Company proposing changes to the ECAM at this time?
The Company is filing this Application for two reasons: to implement
modifications to the ECAM, and to reset base NPC along with certain other costs
as an alternative to a general rate case to mitigate customers' rate impact. In the
Company's last ECAM filing2 Commission staff recommended that the
Commission approve modifications to the ECAM which would align it with
Staffs base rate over-collection adjustment. The Company's reply comments
noted that, while it didn't oppose Staffls modification, the annual ECAM case
was not the appropriate place to implement changes to the ECAM and that there
were other changes to the ECAM that should be addressed. This Application
creates the process to address those changes.
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2 Case No. PAC-E-15-01.
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a. Has the Company experienced changed circumstances that justify
modifications to the ECAM?
A. Yes. The current ECAM was implemented July 1,2009, and since that time there
have been significant changes that justifu the modifications to the ECAM
proposed by the Company, including:
. The participation in an Energy Imbalance Market ("EIM") with the
Califomia Independent System Operator ("CAISO");
. The resource mix to service load has changed and the Company now relies
more heavily on resources out of its control;
. A robust hedging policy has been developed in collaboration with
stakeholders in states served by the Company;
. The Company has become, and will continue to be, increasingly reliant on
intermittent energy to service its load; and
. The Company is not recovering its prudently incurred net power costs and
no evidence has been provided in the annual ECAM's to show that the
Company is not making prudent decisions or that a disallowance is
required to incent the Company to make the right decisions.
Update to Base Rates
a. Does the Company propose to update the level of base NPC included in
customers' rates?
A. Yes. The Company proposes to update the level of base NPC in customers' rates
using the NPC reported in the Company's recently-filed Annual Results of
Operation report. Total Company NPC is $1,514 million, or $93.8 million on an
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Idaho-allocated basis. This compares to $1,385 million total-company NPC, or
$87.6 million Idaho-allocated, currently included in base rates. The NPC update is
a $2.8 million increase to customers' rates. Exhibit No. I provides a detailed
calculation of the updated base NPC.
How was the total Company NPC amount of $1,385 million, or $87.6 million
Idaho-allocated, currently included in base rates determined?
The current base NPC of $1,385 million, or $87.6 million Idaho-allocated was
determined in the 201I general rate case settlement. This was part of a two-step
increase with the first increase effective for 2012 and the second increase, the
current base NPC, was effective beginning in2013.
With that level of NPC in base rates, has the Company over- or under-
collected NPC through the ECAM?
NPC has consistently been under recovered through base rates causing large NPC
deferrals to be recovered through the ECAM. Since the 201I general rates case,
the average NPC deferral in the annual ECAM filings has been approximately
$12.8 million. Given the history of under recovery through base rates, updating
the NPC in base rates based on the 2014 Annual Results of Operations is a
conservative increase.
How are NPC calculated for the Annual Results of Operations?
NPC are calculated for the Annual Results of Operation report by projecting the
NPC needed to serve 2014 normalized load, but incorporating known changes
occurring in 2015. This is also the method most frequently used in the Company's
general rate cases in Idaho. The 2015 NPC in the results of operation incorporates
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the latest forward market prices for natural gas and electricity, signed contracts,
coal costs, and other inputs to the Company's GRID model (the production cost
model) to best represent expected NPC.
What are the major drivers causing base NPC to increase since it was last set
in Case No. PAC-E-ll-12 ("2011GRC"X
The $129 million difference on a total company basis between the Base NPC set
in the 2011 GRC and the proposed Base NPC from the Annual Results of
Operation report is summarized in Table I below by the major categories in the
NPC report.
Table 1
NPG Reconciliation
lD Bas NPG
lD Base NPC 2011 GRC PAC-E-11-12
lncrease/(Decrease) to NPC:
Wholesale Sales
Purchased Power
CoalGeneration
Gas Generation
Wheeling Hydro and Other
Total lncrease/(Decrease)
Settlement Adjustment
Total Company NPG Difference
Annual Result of Operations NPC 2015
$1,385
249
(82)
96
(73)
12
$202
$1,514
The major contributors to the variance in NPC are a reduction in
wholesale sales revenue and increased coal costs. The increase in NPC due to
lower wholesale sales and higher coal and gas fuel expenses is partially offset by
reduced purchased power expenses. Higher load and lower wind and hydro
generation also contributed to higher costs compared to Base NPC, with the
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impact of each spread across multiple cost categories.
The reduction in wholesale sales revenue is driven by the expiration of
five long-term sales contracts and reduced revenue from short-term wholesale
market sales. The drop in revenue is due to both a reduced volume of these
transactions as well as a drop in the average market prices received.
There have been some notable changes that have affected coal fuel costs
including contractual coal price increases, new coal contracts, and increased mine
operating costs at the Bridger mine.
Is the Company updating any costs, other than NPC, in the base rates?
Yes. The Company proposes to update revenues from the sale of RECs included
in base rates. The Company also proposes to include PTCs as they are closely
related to NPC. In addition, base rates would include amorlization of the
unrecovered plant investment of the Deer Creek Mine.
What is the total increase to base rates?
The Company's proposed updates to base rates results in a $10.2 million, or 3.9
percent, increase to Idaho's rates. The testimony and exhibits of Ms. Steward
provides details of the proposed increase by rate schedules. Ms. Steward's Exhibit
No. 3 shows that the updates to NPC and REC revenues have the greatest impact,
increasing rates approximately $2.8 million and $6.5 million respectively.
Why is the Company proposing to update the base rates for PTCs?
PTCs have a direct correlation to NPC, a PTC credit is given for each megawatt-
hour of production from qualifuing renewable facility, meaning they rise and fall
with NPC. Therefore, the Company is proposing these credits be updated in base
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rates and tracked in the ECAM.
Please explain the proposed treatment for the Deer Creek Mine costs.
As reflected in the Company's application in Case No. PAC-E-14-10 the
Company recently closed the Deer Creek Mine and the depreciation and depletion
expenses are not included in the 2014 Annual Results of Operation NPC. The
amortization of the remaining book value of the Deer Creek Mine, consisting of
the depreciation expense from unrecovered plant investment should be included in
base rates. Since this amortization is a fixed annual amount, there is no need to
true it up in the ECAM going forward once it is included in base rates. This is
consistent with the Company's application in Case No. PAC-E-14-10.
Why is it appropriate to include the amortization of remaining book value of
the Deer Creek Mine in base rates?
Prior to the Deer Creek Mine Closure the depreciation and depletion expenses
were embedded in the coal costs of the Hunter and Huntington coal plants. These
costs were included in both base and actual NPC and part of the ECAM. These
costs however, are no longer included in actual NPC and were not included in the
2014 Annual Results of Operation NPC report. Absent this adjustment they will
not be recovered through rates. Additionally, the current coal contract which
replaced the Deer Creek Mine is a benefit to customers resulting in lower NPC
than if the Deer Creek Mine would have remained in operation. Without updating
base rates to account for the amortized remaining book value of Deer Creek Mine,
customers would enjoy the benefit of the mine closure without bearing the costs.
If the amortization of the remaining book value of the Deer Creek Mine,
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1 consisting of unrecovered depreciation and depletion expenses is not included in
2 base rates a temporary adder should be included in the ECAM to allow for the
3 recovery ofsaid cost until they are reflected in base rates.
4 Energy Cost Adjustment Mechanism
5 Q. Please briefly describe the Company's current ECAM as authorized by the
6 Commission.
7 A. Commission Order No. 309043 authorized the Company to implement an ECAM,
8 a mechanism to recover the differences between actual NPC and base NPC in
9 rates. The current ECAM includes a 90110 percent sharing band, meaning
10 customers are responsible for 90 percent of the NPC differential and the Company
11 is responsible for the other l0 percent. Other items tracked in the current ECAM
12 to true-up the amount in base rates to actuals include: SO2 Sales, DSM costs, and
13 REC revenue. Various adjustments are made to the ECAM calculation including
14 the LCAR for revenue collected for Energy-Classified Production Costs
15 excluding NPC ("ECPC"), the Emerging Issues Task Force ("EITF") 04-6 coal
16 cost adjustment, and Staffs base rate over-collection adjustment to account for
17 any over- or under-collection of NPC. Beginning in 2015, the ECAM also
18 includes a resource adder to begin recovery of the Company's investment in the
19 new Lake Side 2 generation facility until it is reflected in customers' rates as a
20 component of rate base.
2I a. Please describe the Company's proposed modifications to the current
22 ECAM.
23 A. As described above, the Company is proposing the following changes to the
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3 Case No. PAC-E-08-08.
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ECAM:
. The 90/10 percent sharing band should be eliminated allowing for 100
percent recovery of prudently-incurred Idaho NPC;
. The calculation method should be based on retail sales at meter
eliminating the need for the base rate over-collection adjustment;
. The LCAR should be eliminated;
. DSM costs and SOz sales should no longer be tracked in the ECAM;
. PTCs should be included in the ECAM as they are closely related to NPC;
. The deferral period should be aligned with the calendar year and the filing
date changed to April I with rates effective June l.
Do NPC true-up mechanisms in other states include sharing bands?
Typically no. Out of all states with non-restructured power markets, only eight -
Wyoming, Utah, Idaho, Oregon, Washington, Missouri, Montana, and Vermont -
have sharing mechanisms built into their respective power cost true-up
mechanisms.
Has the recovery of NPC changed in the states within the Company's service
area since the Idaho ECAM was approved in 2009?
Yes. At the time of Order No. 30904 the Company had a power cost true-up
mechanism in place only in California. Since that time mechanisms have been
implemented in Utah, Wyoming, and Oregon. The California mechanism allows
for 100 percent recovery, the Wyoming and Utah mechanisms include sharing
bands and the Oregon mechanism includes both dead bands and sharing bands. In
March 2015, at the conclusion of the Company's most recent general rate case in
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Washington, the Washington
that the Company must file
mechanism by May 31,2015.
and Transportation Commission ordered
to implement a power cost adjustment
Please describe the similarities and differences in the treatment of NPC
among the Company's six jurisdictions.
As noted above, upon approval of a power cost adjustment mechanism in
Washington, all six states in the Company's jurisdiction will provide for NPC to
be recovered through a true-up mechanism. In California and Oregon, base NPC
is set annually and coincides with the defenal periods. Base NPC is set during
general rate cases in Wyoming and Utah and rarely coincides with the deferral
period. The California mechanism does not include a sharing band, the Utah and
Wyoming mechanisms have a 70/30 percent sharing band, and the Oregon
mechanism has a $30 million dead band and a 90/10 percent sharing band. The
Company has proposed eliminating the sharing band and including PTCs in the
Wyoming ECAM as part of its current Wyoming general rate case.
Is there anything unique about the Company's jurisdictions?
Yes. As described above, only eight states do not have a pass-through mechanism
that result in full recovery of prudently incurred costs. Five of those eight are
states the Company serves, so a comparison to states served by the Company is
not representative of the ratemaking approach to recovery of NPC across the
utility industry. The five states within the Company's service area are outliers
compared to the rest of the nation in that they do not allow 100 percent recovery
of NPC. By allowing full recovery of prudently incurred costs, other states have
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utilities
tariffs
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I determined that a pass-through mechanism with deadbands or sharing bands is not
2 the appropriate approach to regulate costs that are large, volatile, unpredictable,
3 and largely outside the Company's control.
4 JustiJication for Changes
5 Q. Please briefly describe the EIM and why the Company's participation in the
6 EIM warrants a change to the ECAM.
7 A. The EIM automates and optimizes the dispatch of resources on a least-cost basis
8 every five minutes to serve load within reliability and transmission constraints.
9 The EIM provides the mechanism necessary to ensure the lowest possible cost
10 resources are utilized, obviating the need for a sharing mechanism in the ECAM.
I I Conversely, maintaining a sharing mechanism creates the perverse impact of
12 either limiting benefits to customers from EIM or penalizing the Company even
13 though it is pursuing innovative solutions to reduce costs for customers.
14 Removing the sharing mechanism ensures that customers receive the full benefits
15 of the EIM, which further extends customer savings resulting from the diversity
16 and opportunity in an expanded market footprint beyond the Company's borders.
17 a. How has the resource mix by which the Company services its load changed
l8 since the ECAM was implemented?
19 A. Table 2 summarizes the generation by resource type in 2009 compared to 2013.
20 The most drastic change is the increased reliance on short term market purchases.
2l While this increased reliance on market purchases expands the exposure to market
22 prices, the Company has appropriate controls in place to mitigate the potential
23 impact to customers, including hedging natural gas and electric power to manage
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NPC volatility.
Table 2
Please briefly describe the changes to the Company's hedging policy and why
it warrants a change to the ECAM.
In a collaborative effort with interested parties, the Company made substantial
changes to its hedging policy in 2012. Considering input from stakeholders in
Utah, Wyoming, Idaho, and Oregon, the Company updated its hedging policy
including guidelines that allow a reasonable percentage of the natural gas and
power requirements to remain open to short-term market price exposure and allow
for operational flexibility. Also, hedges are normally be limited to the short-term
consistent with the Company's risk management policy to help account for
relative market illiquidity and potential inaccuracy of forecasted requirements.
These policy changes require the Company to maintain a specified level of
exposure to natural gas and power market prices, which influences NPC volatility
over which the Company has no control. The Company files detailed semi-annual
hedge reports, which describe hedges transacted since the previous report as well
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Cod 43-856 U.63ot 43-698 62.38o/r fl58'-o a6e1
NmalGas 8-577 12-6401 8-t77 lL-670/r (400'-4.6601
Ge.oficrmal & Solar 279 o.4tE,255 0-f6qt 04 -8-49/r
whd 2.063 3.Mot,3.035 4-33ct,973 47.1501
lL,r&o 3-544 S.22ot 3.tu 4.52ot'G8l l0.74Ct
Lons Tcrm Prrcbascs ad Exchaares 5.636 8_317 5.047 7-ZV/r (J89 -lo {591
Short Tcrm hreiagcs 918 l_35rt,4.331 6-l9./'3.418 !72.28o/t
OoaftinrFacilhg 2.031 2-99t 2.34t l.34ot'3t0 15.2fYr
tadrtial QueEvtu Facilbr row Scf-Gcocraiu 949 l-40!/,0 0.fiP2 (949 -99-9801
fotel Rcsorrces (GI*'L)67.t53 loo.l 70,054 tln/.2J0l 32'||/.
fotal WLobseb Sdes l0-616 9-395 0_221'tt-5@t
Net Svstcu Loed (GIEIL)57237 60.659 t.122 s.|tti
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as plans for future hedges. The policy is also subject to review by the
Commission.
The changes to the Company's hedging policy warrants changes to the
ECAM, specifically removing the sharing band, for two reasons: l) The changes
demonstrate the Company is actively controlling its NPC, and 2) the intended
market exposure, as a result of a reliance on short term firm market purchases, is
out of the Company's control.
Please describe the change in the Company's reliance on intermittent energy.
The Company has become more reliant on intermittent energy because of the
addition of QFs on the Company's system and other owned and contracted
generation that serve its load. Table 2 above shows that generation from
Company-owned wind and QFs has increased 47 percent and 15 percent
respectively.a
Why does the Company's reliance on intermittent energy to service its load
warrant a change to the ECAM?
Intermittent energy is highly dependent on the weather, which is entirely out of
the Company's control and causes several issues with respect to forecasting NPC
in customers' rates. Company-owned wind and hydro generation provide zero-
fuel-cost generation, and in the event of unfavorable weather the lost generation
has to be replaced by either coal or gas generation and/or purchased on the
market. There is also a correlation between weather and market prices; e.g. when
3 The variance related to industrial customer QFs results from the customer opting to first serve its own load
with its QF generation. For these Industrial QFs, in 2009 the Company bought 100 percent of the QFs'
output but also serviced the customers' load. In 2013 these industrial QFs chose to service their own load
f,rrst, so the Company did not receive the output from the QFs but it also did not service that portion of the
customers'load.
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the wind is blowing it blows for everyone in the same geographic area, which puts
downward pressure on prices in nearby markets.
Unexpected changes in weather are not captured in a forecast of NPC
prepared well in advance of the time the energy is actually produced and
consumed. In a recent newspaper article about the accuracy of long-term weather
forecasts, Louis Uccellini, director of the National Weather Service, stated, "We
[the National Weather Service] sustain higher accuracy out to two to three days in
advance; then it starts dropping off faster at days six through eight."s In fact, the
National Weather Service does not make specific weather predictions more than
seven days out. Under the current ECAM structure, the Company establishes base
NPC months in advance of the delivery period, and any deviations from the
forecast are only recovered or refunded at ninety cents on the dollar.
With regard to intermittent QFs specifically, it is important to note that the
Company does not operate the QFs from which it takes energy and cannot control
their generation, but is required by federal law and state regulation to purchase
power from these facilities. Any increases in production from these QF is subject
to the current ECAM sharing bands, under which the Company is paying l0
percent of the increased costs to the extent the QF contract price exceeds short-
term market prices. These federally mandated costs should be recovered through
rates without sharing.
o Palmer, B. (April 15, 2013). Long-term weather forecasts are a long way from accurate. The Washington
Posl, retrieved from www.washingtonpost.com.
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Sharing Bands
a. Please describe the Company's experience with sharing bands in the current
ECAM.
The ldaho ECAM currently includes a 90/10 percent sharing band, meaning the
Company is responsible for 10 percent of the NPC variance and the other 90
percent is either paid by or refunded to customers. Since the implementation of
the current ECAM, the actual operation of the mechanism has been asymmetrical
with the Company consistently under recovering its costs by approximately $7
million. The sharing bands deny the Company the opportunity to recover prudent
expenses even though adequate, safe, reliable electricity service has been
provided.
What did the Commission conclude in Order No. 30904 with regard to the
sharing band?
The Commission found that "the symmetrical sharing band provides the Company
an incentive to actively control its NPC."6
Is the sharing band an effective incentive mechanismi
No. The Company believes that the sharing band provides no meaningful
incentive, but it instead has historically served to penalize the Company despite
prudent management and limit benefits to customers that may be achieved
through the Company's efforts to reduce NPC. Despite the ineffectiveness of the
sharing band as an incentive mechanism the Company has shown it has made its
best efforts to control NPC. The Company's accountability to the Commission,
customers and shareholders, along with the potential competition of self-
6 Case No. PAC-E-08-08, Commission Order No. 30904 Issued September 29,2009, page 13.
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generation and direct access (available in portions of the Company's six-state
service territory), provide effective incentive to minimize NPC.
How has the Company demonstrated its best efforts to actively control NPC?
The Company has proven itself to be an industry leader by participating in an
EIM with CAISO which indeed demonstrates the Company's best efforts to
control NPC. EIM automates and optimizes the dispatch of resources on a least-
cost basis every five minutes to serve load within reliability and transmission
constraints. The Company's participation in the EIM eliminates the argument that
the Company needs an outside incentive to optimize the dispatch of resources to
serve customers and provides ample evidence that the Company is actively
controlling its NPC.
The Company's efforts are further evident in the fact that in the six Idaho
ECAM filings to this point only $1.17 million of NPC has been disallowed. This
is compared to approximately $480 million of Idaho-allocated NPC incurred over
the same time frame, which equates to a 0.24 percent disallowance rate.
Furthermore, all of these adjustments were simply accounting issues; no costs
have been disallowed based on prudence. The majority of the disallowance, $814
thousand of the $1.17 million, relates to the implementation of the back cast
adjustment which was an adjustment based on the calculation of the ECAM and
not the prudence of NPC.
Is a sharing band an effective tool to manage and/or share risk?
No. Sufficient internal and external controls exist and are in place to appropriately
manage risk, including the Company's Risk Management Policy, Governance and
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Approvals Process, and Front Office Procedures and Practices. These policies and
procedures outline the internal controls the Company has implemented and the
measures taken to protect the interests of its customers and shareholders. Internal
controls include hedging limits and documented management approval of hedge
transactions consistent with governance requirements, system controls (logic in
the natural gas and power transactions trade capture system), contract reviews and
documented management approval of new contracts consistent with governance
requirements. The Company must also plan to provide a least-cost, least-risk
portfolio of resources, and it must operate its resources in a prudent manner.
These standards apply regardless of the existence of an ECAM and/or sharing
band, and consequently the sharing band has no impact on the Company's day-to-
day operations.
How do customers benefit from eliminating the sharing band?
An ECAM without a sharing band will provide more accurate price signals to
customers of the cost of power. Additionally, as NPC are the largest single
component of base rates, a properly designed ECAM without sharing bands
mitigates the need for the Company to constantly file a GRC. This is evident in
the fact that the Company has not filed a GRC in California, where there is no
sharing band, since 2009. Finally, eliminating sharing bands allows customers to
receive the total benefit of any cost savings that may be realized through
participation in the EIM.
Wilding, Di - l8
Rocky Mountain Power
I ECAM Calculotion
2 Q. Please explain the current calculation of the NPC deferral in the ECAM.
3 A. Currently the NPC defenal is calculated monthly by comparing the Base NPC
4 Rate ($/IVIWh) to the Actual NPC Rate ($A4Wh) to arrive at a NPC differential
5 rate ($/\,{Wh). The NPC differential rate is then multiplied by the actual Idaho
6 load at input to arrive at the NPC deferral which is then subject to the 90110
7 sharing. Currently the Base NPC Rate and the Actual NPC Rate are calculated
8 monthly using total Company NPC and total Company load at input.
9 Q. Please explain the proposed calculation of the NPC deferral in the ECAM.
l0 A. The Company proposes using a similar calculation as the base rate over-collection
I I adjustment method proposed by Commission staffT to calculate the NPC deferral,
12 thus eliminating the need for the back cast adjustment. However, the Company's
13 proposal would reflect the seasonal rates used in Idaho, and calculate the NPC
14 Differential using sales at meter in place of load at input.
l5 The NPC recovered through rates is calculated monthly. The first step is to
16 determine the NPC embedded in rates (Base NPC $A4Wh) for both the summer
17 (May - October) and winter (November - April) blocks by dividing the Idaho-
l8 allocated Base NPC by the Idaho base load at the meter (i.e. Idaho retail sales)
19 used to set rates. The Base NPC $A,lWh for the appropriate block is then
20 multiplied by the monthly Idaho actual retail sales (Actual ID Sales) during the
2l deferral period to arrive at the monthly Idaho NPC Collected in rates.
22 The monthly Actual Idaho NPC is calculated by dividing total company
23 NPC by total company Actual Sales to arrive at the monthly Actual NPC $A4Wh.
Wilding, Di - 19
Rocky Mountain Power
7 Case No. PAC-E-15-01, Commission StaffComments.
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The Actual NPC $A4Wh is multiplied by the Actual ID Sales to arrive at the
Actual ID NPC for the month.
The Idaho NPC Collected is then compared to the Actual Idaho NPC to
arrive at the NPC deferral. The figure below illustrates the monthly NPC deferral
calculation.
Figure I
NPC Def errol = (ectuol NPCsly.nx Actuo.l ID Sates) -
(nase NPCslyy,nx Actual ID Sales)
Please explain how the other components of the ECAM will be calculated
under the proposed method.
The true-up of the LCAR (if continued), DSM costs (if continued), and revenues
from the sale of RECs would be calculated using the same method as NPC, by
comparing the actual collection through rates to the actual costs and/or revenues.
This same method will be used to true-up PTCs. However, there would not be a
seasonal rate; rather, just a single annual rate. There would be no changes to the
remaining components of the ECAM: SOz Sales (if continued), the EITF 04-6
coal cost adjustment, and the Lake Side 2 resource adder.
What are the benelits of the proposed method?
There are three distinct benefits of the proposed calculation: 1) by using retail
sales at meter in place of load at input the ECAM is not affected by differences in
actual line losses and line losses computed in base rates; 2) by using a seasonal
NPC embedded in rates, the ECAM accurately reflects the revenue collected from
Idaho customers that pertains to NPC; and 3) the proposed calculation eliminates
the need to make an after-the-fact base rate over-collection adjustment.
Wilding, Di - 20
Rocky Mountain Power
a.
A.
I Load Change Adjustment Rate
2 Q. Please describe the LCAR.
3 A. The LCAR is an adjustment to the ECAM that accounts for the collection of
4 Energy-Classified Production Cost excluding NPC (i.e. energy-classified fixed
5 costs from the most recent general rate case) as changes in load occur. The LCAR
6 is calculated by comparing the Idaho base load to Idaho actual load and
7 multiplying the difference by the LCAR rate which is currently $5.47AvIWh. The
8 Commission described the LCAR by stating, "The load growth [change]
9 adjustment portion of the power cost adjustment mechanism removes some costs
l0 from [ECAM] recovery when loads grow and adds some costs to [ECAM]
I I recovery when loads decline."8
12 a. Why should the LCAR be removed from the ECAM?
13 A. Capital costs and other operation and maintenance costs included in the LCAR
14 calculation do not have a similar profile to NPC; they are not highly volatile or
15 largely outside the Company's control and therefore should not be included in the
16 ECAM. Furthermore, the LCAR is asymmetrical in the fact that it only considers
17 changes in loads (or sales going forward) but ignores changes in the actual
l8 underlying actual underlying energy component of production costs. This would
19 be the equivalent of calculating the NPC deferral based only on the change in
20 sales and failing to take into account the actual NPC incurred.
2l a. What is the effect of ignoring the actual underlying ECPC fixed costs in
22 calculating the LCAR?
23 A. The inherent flaw in the LCAR adjustrnent is that it assumes the actual ECPC
Wilding, Di-21
Rocky Mountain Power
8 Case No. GNR-E-I0-03, Order No. 32206, page 6.
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equals the base. These costs were set at $20.2 million as part of the 201I GRC. In
the recently-filed Annual Results of Operations, current ECPC are $23.3 million,
or $3.1 million (approximately 17 percent) greater than the base set in the 20ll
GRC. However, since the increase in the ECPC is not accounted for in the LCAR
adjustment, the Company has refunded customers approximately $3.1 million
through the LCAR adjustment in ECAMs filed since 2012.
For example, in the most recent ECAM filing the Company refunded to
customers approximately $0.8 million through the LCAR adjustment. However,
as noted above costs were $3.1 million above base ECPC. If actual ECPC costs
would have been considered it would have resulted in a recovery of
approximately $2.0 million after adjusting for load growth and sharing bands.
Although correcting the LCAR adjustment would result in cost recovery, the
Company is proposing to eliminate the LCAR adjustment on the basis that the
ECAM was not intended to be a fixed cost adjustment mechanism, ECPC are not
highly volatile or largely outside the Company's control, and the ECAM
calculation already accounts for fluctuations in Idaho load.
How does the ECAM calculation capture fluctuations in Idaho load, thus
mitigating the need for the LCAR?
The impact of fluctuations in Idaho sales is accounted for in the ECAM
calculation by comparing the [daho NPC Collected in rates to the Actual Idaho
NPC incurred. If Idaho loads increase, the Idaho NPC Collected also increases
and consequently the NPC deferral would decrease. tf Idaho loads decrease the
Idaho NPC Collected also decreases and consequently the NPC deferral would
Wilding, Di - 22
Rocky Mountain Power
I increase.
2 Demand Side Management Costs and SOz Sales
3 Q. Please describe the tracking of DSM costs in the ECAM.
4 A. The ECAM currently tracks DSM costs by comparing actual Idaho allocated
5 DSM costs to the Idaho allocated DSM costs in base rates. The difference is either
6 collected from or returned to customers. The inclusion of DSM costs in the
7 ECAM is the result of the settlement stipulation in the 2011 GRC which states:
8 "the Parties agree that, due to the uncertainty of the jurisdictional treatment of the
9 dispatchable irrigation load control [DSM] program currently being discussed by
l0 the MSP [Multi-State Protocol] Standing Committee, Idaho's share of the
I I customer load control [DSM] service credit will be tracked in the ECAM."
12 a. Why should the ECAM discontinue tracking DSM costs?
13 A. The uncertainty surrounding the MSP treatment of DSM costs is no longer an
14 issue. MSP dictates that DSM costs are Situs assigned thus eliminating the need to
15 track these cost in the ECAM. In addition, the Company has modified this DSM
16 program to make it more cost effective and aligned with the benefits received.
17 a. Please describe the tracking of SO2 sales in the ECAM.
l8 A. Revenue from sales of SOz emissions allowances is not included in Idaho base
19 rates. Instead, all SOz sales revenue is tracked in the ECAM as an after-the-fact
20 credit to customers.
2l a. Why should the ECAM discontinue tracking SOz sales?
22 A. SOz sales have become immaterial. In the 2015 ECAMe ldaho SOz sales
23 amounted to a $71 credit to customers. [n 2016, the Company expects to pass
Wilding, Di-23
Rocky Mountain Power
e Case No. PAC-E-I5-01.
I through a $19 credit to customers for SOz sales. These sales should no longer be
2 tracked in the ECAM, but should revert back to being included in base rates in the
3 Company's next general rate case.
4 PTCS Addcd TO ThC ECAM
5 Q. Please explain why PTCs should be included in the ECAM.
6 A. The generation of energy at certain company-owned facilities is eligible for the
7 renewable electricity production tax credit under Internal Revenue Code section
8 45, and the credit is included as an offset to the Company's federal income taxes.
9 For each kilowatt hour of energy generated at eligible wind-powered generating
l0 facilities the Company receives a $0.023 credit ($0.011 credit for eligible hydro
I I generating facilities) on its tax return, for a duration of l0 years beginning on the
12 date which the facility became commercially operable. The value of these credits
13 is reflected as a reduction to current income tax expense on the financial
14 statements and for rate making purposes.
15 The amount of renewable electricity production tax credit received is
16 entirely dependent on the amount of generation at eligible facilities. The
17 generation is highly dependent on weather, varying from year to year as weather
18 patterns fluctuate. The forecasted generation of these facilities used to set base
19 NPC is the same output currently used to calculate the value of the renewable
20 electricity production tax credits in general rate cases. To the extent the
2l generation from these plants varies from the forecast, the impact on NPC gets
22 updated via the ECAM filings but the value of the PTC is not trued-up. Therefore,
23 including a true-up of the PTCs in the ECAM would be appropriate.
Wilding, Di -24
Rocky Mountain Power
I Deferral Period ond Filing Date
2 a. Does the Company propose any changes to the deferral period and filing
3 timeline of the ECAM?
4 A. Yes. The Company proposes changing the deferral period to correspond to the
5 calendar year (January - December). To accommodate this change the filing date
6 would be moved to April I with rates effective June l. If the Commission
7 approves this new deferral period the first ECAM filing after changes are
8 effective will include a 13 month period of December to December.
9 Q. Have you included an example ECAM calculation that incorporates the
l0 Company's proposed changes?
I I A. Yes. Exhibit No. 2 includes an example ECAM calculation template with the new
12 ECAM components included.
13 a. Does this conclude your direct testimony?
14 A. Yes.
Wilding, Di-25
Rocky Mountain Power
CONFIDENTIAL
Case No. PAC-E-I5-09
ExhibitNo. I
Witness: Michael G. Wilding
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOLTNTATN POWER
CONFIDENTIAL
Exhibit Accompanying Direct Testimony of Michael G. Wilding
May 2015
THIS EXHIBIT IS CONFIDENTIAL
AND IS PROVIDED UNDER
SEPARATE COVER
Case No. PAC-E-I5-09
Exhibit No. 2
Witness: Michael G. Wilding
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
ROCKY MOI'NTATN POWER
Exhibit Accompanying Direct Testimony of Michael G. Wilding
May 2015
Rocky Mountain Power
Exhibit No. 2Page 1 ol 1
Case No. PAC-E-15-09
Witness: Michael G. \Mlding
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