20170512Comments.pdf

BRANDON KARPEN
DEPUTY ATTORNEY GENERAL
TDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03s7
IDAHO BAR NO. 7956
IN THE MATTER OF IDAHO POWER
COMPANY'S APPLICATION FOR
AUTHORITY TO IMPLEMENT POWER COST
ADJUSTMENT (PCA) RATES FOR ELECTRIC
SERVICE FROM JUNE 1,2017 THROUGH
MAY 31.2019.
i r !: i ' l':r l r./ i: 1"")
: il"'i' it Fll L: C j
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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CASE NO. IPC.E.I7-06
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Brandon Karpen, Deputy Attorney General, and in response to the Notice of
Modified Procedure and Notice of Comment Deadline issued in Order No. 33755 on April 26,
2017, in Case No. IPC-E-17-06 to submit the following comments.
BACKGROUND
On April l4,20l7,Idaho Power Company applied to the Commission for an Order
authorizing the Company to adjust its Schedule 55 PCA rates. The Company's PCA
Application, if approved, would increase overall revenue collected from Customers by about
$10.6 million or 0.93Yo. The Company requested that the new rates take effect on June, 1,2017.
The Commission first approved the annual PCA mechanism in 1993, and it has been
modified several times since then. See Commission Order Nos. 30715,30978,32206,32424,
33149,33307 . The Company's actual cost to provide electricity (Net Power Supply Expense, or
NPSE) varies from year-to-year depending on changes in stream flows, the amount of purchased
power, fuel costs, the market price of power, and other factors. The PCA mechanism tracks
1STAFF COMMENTS MAY 12,2017
annual differences between actual NPSE and NPSE recovered through base rates. The PCA is
also used to provide revenue sharing benefits resulting from the revenue sharing mechanism
approved in Order No. 33149 and has historically provided an annual DSM Rider credit per
Order No. 33000. In this year's PCA, earnings were not sufficient to provide customers with a
revenue sharing credit; and per Commission Order No. 33736, the DSM Rider credit is no longer
applicable. However, the Order does provide a one-time refund of unspent DSM Tariff Rider
Revenue collected by the Company.
STAFF REVIEW
Staff reviewed and audited the traditional PCA components (forecast, true-up, and
reconciliation of the true-up) and additional components applied in the PCA (Revenue Sharing
and DSM Rider Refund). Staff also reviewed the spread of incremental PCA revenue across
customer classes for both the traditional PCA components and the additional components in this
year's PCA. Staff s major findings as a result of its review are summarized as follows.
1. The assumptions used in the Company's forecast reasonably approximate cost of
operations in the next year's deferral period (June 1,2017, through May 30, 2018)
providing collections that should approximate the difference in actual NPSE and
NPSE recovery through base rates.
2. Although the Company had major equipment and facility downtime, Staff believes
there was not enough evidence to conclude that the Company was able to prevent it.
The Company made efforts to minimize its impact, and therefore, prudently incurred
actual NPSE during the deferral period.
3. Actual and base costs, revenues, and loads used to calculate the revenue requirement
were found to be accurate.
4. The methods used to calculate the revenue requirement for all components of the
PCA (including the forecast, the true-up, the reconciliation of the true-up, revenue
sharing, and the DSM Rider refund) were accurate and complied with past
Commission orders.
5. The methods used to determine the allocation of the revenue requirement across
customer classes were found to be fair and reasonable.
2STAFF COMMENTS MAY 12,2017
Through the PCA, Idaho Power Company is requesting an increase of about $10.6
million or 0.93o/o more in total revenue above what it is currently collecting through customer
rates. Current Schedule 55 PCA rates are designed to collect about $79.5 million in annual
revenue from June 1,2016, through May 30, 2017. The Company's request would increase that
amount to $90.1 million, which would be a 13.3o/o increase in Schedule 55 rates. The following
table provides a breakdown of the increase.
Tablt I: Idlho Po$'er proposed Curtomer Rrvenue Iarpact
Stlq{rp,&a
PCA Futrrt Foreca:t
PC,{ True Up (imhrdcs reconcliatfun of Tru+.up)
Aloratcd Ret tmr Sharirq
"{ssociated DSill Ritcr Change
DS!l{ rlter Refirod
Cqnent {S}
47,9.13,t99
r8,?38/41
(3"135.0r0)
t398r,530)
Prorosed {$)
66,91.{,}03
36"?10,680
DilTererce ($i
tE.97t.l@
e,-r2?-7dl)
1,155,0t0
3,985,530
o,6 lggigt!,e
39'970,6
-6.53%
lm.ffi6
1m.#/6
o/o of Tatel
l79q..ii
-3.1on
tvn.
38-o4
PC,{ Totrl 79,541,100 90'114,088 10"583,*83 13.319(lA$Vs
Tofal Billed R*v€lus I,134,0$6310 l,l#,6{d,933 10,58S,61.'0,9315
As shown above, the PCA future forecast component has the largest impact on the
Company's requested amount. The PCA forecast is about $19 million (39.6%) higher than the
forecast used in last year's PCA and 179% of the Company's total requested increase. However,
a one-time $13 million DSM Rider refund being issued in this year's PCA along with a $2.5
million reduction in the True-up has substantially lessened that increase. The absence of a
revenue sharing credit, and the discontinuation of the annual DSM Rider credit in this year's
PCA make up the remaining increase.
The overall rate impact for the largest customer classes are provided in the following
table. A copy of Company Attachment 2 showing the impact of proposed rates for all customer
classes is included as Attachment A to these Comments.
Table 2: Overall Rate Impact
Class Description
Residential
Small General Service
Large Ceneral Service
Large Power Service
Irrigation
Micron
JR Simplot
DOE
7o Increase
o.58%
o.27%
L.t2%
1.65%
o.94%
L.95%
2.L6%
2.O3%
Rate Schedule
I
7
9
t9
24
26
29
30
Overall Incrrcase o.93%
STAFF COMMENTS aJ MAY 12,2017
Details of Staff s analysis of the Traditional PCA components, Revenue Sharing, DSM
Rider funds, and calculation of rates are discussed in the following sections.
Traditional PCA Comnonents
The traditional annual PCA mechanism has three components: (l) a "forecast" or
projection that estimates the difference between NPSE embedded in base rates and the coming
year's NPSE; (2) a"true-up" that captures the difference between actual and base NPSE and
credits the revenue from the previous year's collected forecast rate; and (3) a reconciliation of
the prior year's true-up that captures any under-recovered or under-refunded true-up amount.
The reconciliation is also called the "true-up of the true-up."
The Company combined the three traditional PCA rate components and proposed a2017
PCA rate surcharge of 0.7361 cents per kilowatt-hour (//kwh) (i.e.,0.4776 + 0.2423 + 0.1611).
The Company expects this rate will allow it to recover the traditional PCA ending balance at the
end of the coming year. The proposed rate is 0.1174 p/kwh higher than current PCA rates.
Each component is described in more detail below.
To produce the forecast, the Company used its March 31,2077, Operating Plan to
forecast NPSE for the coming year and determined the difference between these amounts and
NPSE embedded in base rates. The Company reported Idaho ratepayers' share of the difference
is about $47.8 million. This difference was then converted into a p/kWh rate by dividing the
amount by projected energy sales. The Company proposed a0.47760 P/kYfh forecast rate as
compared to a0.3422 /lkwh rate in last year's PCA.
The true-up amount is primarily made up of the differences between actual NPSE and
NPSE recovered through base rates, and revenues from the forecast rate that accrued during the
prior year. The prior year's PCA amount is not precisely recovered, because the expected cost
forecast can never be 100% accurate. The Company converts the true-up amount to a plkWh
rate by dividing it by projected energy sales. The Company calculates Idaho ratepayers' share of
the true-up amount to be $34.0 million, and expects to recover that amount through a true-up rate
of 0.2423$lkwh as compared to last year's rate of 0.3129 p/kwh. A copy of Company Exhibit
l, which details the Company's true-up calculations, is reproduced as Attachment B to these
Comments.
4STAFF COMMENTS MAY 12,2017
The reconciliation of the true-up tracks the recovery of the prior year's true-up amounts.
It nets the actual revenue collected from the true-up rates, and revenue-sharing rates against the
amounts set for recovery. Any difference is carried into the next year's true-up reconciliation
along with the true-up difference. According to the Company, the true-up was under-collected
by about $2.3 million, resulting in a proposed reconciliation of the true-up rate of 0.1611 l/kwh
as compared to a credit of 0.0364 llkwh in last year's PCA.
Staff s analyses of the three traditional PCA components are described in the following
sections.
Forecast Analysis
The Company's system level NPSE forecast for the 2017-2018 PCA year is
$377,451,633, which is$7l,766,764higher than the currently approved base level NPSE of
S305,684,869. The Company determined that the 2017-2018 PCA forecast component to be
collected from Idaho jurisdictional customers over the next year is $66,914,308. Staff believes
the Company's forecast reflects reasonable future conditions and recommends the Commission
accept the new forecasted PCA rate of 0.4776 cents per kwh.
As noted previously, the PCA forecast rate accounts for l79Yo of the projected $10.6
million revenue increase and is about 40%higher than last year's forecast. However, Staff
believes this reasonable when comparing 2016-2017 actual NPSE with the Company's proposed
forecast. Although actual NPSE during the2016-2017 deferral period as shown in Table 3 below
is about $50.3 million or 12Yo higher than the Company's forecast in this case, the Company's
forecast is roughly equal to last year's actual cost after accounting for extraordinary
circumstances that occurred during the2016-2017 deferral period. These circumstances include
a significant increase in PURPA capacity that came online during the2016-2017 defenal period,
an increase in the cost of coal generation due to increased mining cost during the deferral period,
and below average water for hydro generation that is expected to increase surplus sales and
reduce purchases this coming year. Each of these are discussed in more detail below.
5STAFF COMMENTS MAY 12,2017
Table 3: 2017 For*cest l'ersnc 2016-2017 Act*al
20r6't017
FERC Account Actual Difiereace Silfereace
2017-2018
Forecast
%s
Sqptus Sales S
Coal S
O*rcr Fuct(Gas) S
Purchascd Powcr Non-PURPA $
PLRPA $
DR lnceativ'es $
3rd Partv Transadlsirm $
(25.768,27?}
1,11,879,874
i7.830,518
79,009,663
I8!.?1,1,395
7,059,424
6,017,0?5
s (34,3?1,858) S
$ l?6,?69.503 S
$ 3?,305,583 S
$ 53,615,387 S
s 181,714,395 s
S 7,,r01,698 S
$ 6,01?,025 $
(8,603,581)
(15,I1S.3?l)
(514,936)
(36_394,375)
347,21*
-33?6
-l Io/il
- I9"6
-330,6
0et
5%
0$6
?sta! $ 43?"?3?,631 $3??,451,631 S (50,380,9&S)-13$t
The largest impact in the Company's PCA forecast is a $23 million increase in PURPA-
related costs (See Table 4 below) above last year's forecast. It is driven by an approximate
340 MW increase of PURPA wind and solar capacity in combination with about a $40 per MWh
cost difference as compared to market prices.l Because PURPA generation is a must-buy
obligation, the Company has no choice but to accept increases in PURPA-related NPSE. As a
result, Staff believes it is proper to use last year's actual PURPA NPSE in its forecast as shown
in Table 3, above.
Table 4: 2017 Forecart vers$$ 2016 Fcrecart
t0t6-2017
F.f,RC Arcoont Fcrec*st
10t7-1018
Forecast
$*/*
Differercs Differesce
rryphrs Salcs 5
Coal S
O&er Fud (Gas) S
PtrchasedPowerNon-PUR.PA S
PURPA $
D8.IncentilrEs g
3rd Paty Transmissiotr S
(?0,930,1,17)
I tr2,137,l06
39,20!,83]
54_98S,467
l5*,75S,382
7,401,699
J.999,"{12
$ (3{,371,858}
$ I:6"?69,503
$ 37,305,583
$ 52_615"287
$ I81,714,395
s 7,401.,698
s (13,441,711)
$ 1*,64?,39?
s (1,89?,139)
$ (!"373,180)
s 32,956,013
$
$ r?.613$6.0r7.025
-64or.t
l}irb
-5o.&
-4i.6
l,t9&
0+ri
09t
Total g 357,54?,740 $3?7,451,63? $ 19.903.&9!6*r
The second largest increase to the PCA forecast is due to a 13Yo increase in coal
generation NPSE above last year's PCA forecast as reflected in Table 4. According to the
Company, the cause of the increase is from increased coal cost from Bridger Coal Company due
t Average cost of PURPA generation is$62.42 per MWh versus predicted average market prices of $23 .46. See
Blackwell DI, at I l.
6STAFF COMMENTS MAY t2,2017
to the Joy Longwall mining equipment collapse and reduced Bridger generation during the2017-
201 8 deferral period. This could result in a l8o/o increase in the per ton cost of coal caused by
accelerated depreciation of equipment losses, mine recovery costs, and reduced economies of
scale from lower coal production. See Company Response to ICIP Production Request No. 6.
Staff finds it reasonable that with larger amounts of must-take PURPA generation and higher
coal generation costs as compared to other resources, the amount of coal generation will trend
downward. Given these trends, Staff believes that an llYo decrease in coal generation cost as
compared to actual cost during the deferral period is reasonable.
The Company is expecting higher surplus sales and reduced purchases due to a projected
increase in the amount of hydro generation for the 2017-2018 defenal period. See Blackwell, DI
at 10. The Company projects a $13.4 million increase in surplus sales compared to last year's
forecast (Table 4) and an $8.6 million increase compared to actual surplus sales during the
deferral period (Table 3). Similarly, increased amounts of hydro generation should reduce the
amount of Non-PURPA purchases as reflected in Table 3. The increase in surplus sales benefits
customers because it offsets increases in coal fuel expenses and PURPA obligations. Although
surplus sale prices are forecasted to decline by 14% to $15.88 per MWh in the coming year, Staff
believes an increase in surplus sales volume and a decrease in system purchases as a result of
more abundant hydro generation is reasonable. Any changes to the forecast will be trued-up in
the following year.
True-Up Analysis
The Company's PCA true-up primarily reflects the difference between NPSE collected
through base rates and actual NPSE incurred during the deferral period of April 1,2016, through
March 31,2017. The ending balance also includes collections through the current forecast PCA
rate and monthly accrued interest. Table 5, below, summarizes the $33,953,028 true-up amount
that forms the Company's proposed true-up revenue requirement for Idaho.
Staff s review of the true-up included: (1) an on-site audit of the various components
included in the true-up or deferral balance; (2) an analysis of the methods and basis used to
calculate the cost deferrals and account balances; and (3) a review of actual NPSE including
monthly Risk Management Committee minutes, operating plans, and other reports that were
presented to the Risk Management Committee. As a result of its review, Staff concludes the
7STAFF COMMENTS MAY 12,2017
Company's proposed true-up amount is accurate. The methods used conform to past
Commission Orders and actual costs incurred are reasonable and prudent.
Table 5: PCA True-Up Summary
Positive numbers are a cost to customers negative numbers are a benefit to customers
Net Power Supply Expense Differential
Water Leases
Fuel Expense - Coal
Fuel Expense - Gas
Surplus Sales
Non-Firm Purchases
Third Party Transmission Expense
Deferral Amount
$ (2,148,489)
30,531,554
4,147,759
23,379,392
14,954,520
77,805
Subtotal - Net Power Supply Expense
Renewable Energy Credit (REC) Sales
Sales Based Adjustment
Qualiffing Facilities
Demand Response lncentive Payments
40942570
(1,293,025)
(6,843,374)
20,619,776
(4,192,841)
Total Expense Items
Revenue from PCA Forecast
79,233,076
45,487,126
Deferral Balance (Expense Items less PCA Forecast Revenue)
Interest on the Deferral Balance
33,745,949
207,079
Total True-Up Deferral s33.9s3.028
Details of the different components in the PCA true-up, as shown in Table 5, are
described below.
Net Power Supply Expense Differential
Staff believes the Company prudently incurred NPSE to meet customer load. The
Company's NPSE primarily consist of costs related to coal and other fuels, non-PURPA
purchased power, and surplus sales. During the 201612017 PCA year, reduced availability of
hydro generation required the Company to increase power generation from coal and other fuels,
and to increase purchases from other non-PURPA sources. Further, surplus sales declined as a
result of reduced hydro generation, and lower overall market prices. The main NPSE
components are described below.
8STAFF COMMENTS MAY 12,2017
l. Water Leases. The Company occasionally leases water to produce hydro power.
There is $2,380,597 included in base NPSE for water leases. Any deviation from the
amount included in base rates either increases or decreases the PCA defenal. This
year the Company did not incur any water lease expenses. After jurisdictional
allocation and sharing, $2,148,489 is returned to customers as an offset to the deferral
balance.
2. Fuel Expense - CoaL The Company owns an interest in and receives electricity from
three coal plants: Bridger, Valmy and Boardman. The Company includes the
increase or decrease in coal expense from base rates in the PCA for recovery from or
a credit to customers. From April2016 through March 2017, the total coal expense
for the three plants was $141,879,874. The total coal expense included in base rates
is $108,503,180. This year's PCA defenal balance, after jurisdictional allocation and
sharing, includes a difference of $30,53 1,554 for recovery.
Coal expenses during the PCA period increased for several reasons. There
was a reduction of coal deliveries from the Bridger Coal Company mine to the
Bridger power plant. The original budget included 5.9 million tons of deliveries to
Bridger for calendar year 2016. Due to lower market prices, natural gas prices, and
the abundance of renewable generation, the total budgeted output from Bridger was
reduced in the first quarter of 2016. This reduction in the planned output from the
Bridger power plant translated into a reduction in the delivery of coal from a
budgeted 5.9 tons to 4.2 million tons, thus reducing the delivered tons to the plant and
increasing the cost per ton. In other words, the fixed costs of the coal were spread
over a lower tonnage which increased the unit price for fuel at the plant.
In addition to lower production, coal costs also increased due the
abandonment of the Joy Longwall mining system by the Bridger Coal Company. The
Joy Longwall equipment was operational until December 2015 when it was halted by
soft incompetent clay floor and steep floor grades, a thinning coal seam, and
uncontrollable caving. Recovery attempts were halted in early October 2016, when
safety concerns prompted the Bridger Coal Company to abandon the equipment. The
costs for the attempted recovery and abandonment of the Joy Longwall equipment are
included in the fuel cost calculations. Staff reviewed the coal costs recorded in
9STAFF COMMENTS MAY t2,2017
September 2016 andtrued-up in October 2016 related to the Joy Longwall
abandonment and believes the net book value of $6.25 million (Idaho Power's share)
to be appropriate. The continuing recovery efforts in the amount of 53.64 million
(Idaho Power's share) from December 20 I 5 through October 20 I 6 were included in
the appropriate FERC account by the Bridger Coal Company, and end up included in
the monthly cost of coal burned.
Another driver of the increased fuel expense at Bridger is related to the
decreased coal production at the Bridger Coal Company underground mine. The Joy
Longwall equipment was not mining coal from January through the abandonment in
October. The DBT Longwall was put back into service in August 2016, but extracted
in November 2016. Because there was no Longwall production at the underground
mine for the majority of the year, fixed costs related to the underground mining
operations were spread over a relatively small amount of underground tons. The
2016 budgeted tonnage was 3,495,200 tons and actual tonnage was 1,718,300 tons.
Commission Staff, in its audit of the coal expenses, reviewed all months of coal
expenses, with an in-depth audit of the months of July 2016, September 2016, and
December 2016.
Staff met with Company officials to discuss the Joy Longwall abandonment
and impact on coal costs. As a result of the meeting, and after reviewing the response
to discovery, Staff believes that the Joy Longwall recovery efforts and subsequent
abandonment was an unforeseen event and that the costs were prudently incurred.
Staff notes that during the period of the Joy Longwall recovery and subsequent
abandonment, coal production at the surface mine continued and there was no
shortage of coal as a result of the incident. Staff is satisfied that the Company took
the necessary precautions to contain this incident, including the geologic steps
necessary to ascertain the conditions of the section of the mine that encompassed the
Joy Longwall failure.
Staff also evaluated establishing a regulatory account to amortize the
attempted recovery costs and abandonment costs for ratemaking purposes. The
Company's proposed treatment is in compliance with Generally Accepted
Accounting Principles, recovery through the PCA results in Idaho Power absorbing
STAFF COMMENTS 10 MAY 12,2017
5% of the cost, and it is consistent with the proposed treatment for PacifiCorp, the
operating partner of Bridger. Therefore, Staff believes the proposed treatment is
reasonable and does not propose an adjustment to the fuel expense for coal in this
PCA.
3. Fuel Expense - Gas. The Company owns and operates gas-fired combustion turbine
generating plants at the Evander Andrews Power Complex (3 Danskin units), Bennett
Mountain, and Langley Gulch. Staff reviewed the natural gas purchases in
conjunction with the Company's Operating Plan. Staff reviewed all months of the
natural gas expenses included in the PCA period and performed an in-depth audit of
the months of September 2016 and January 2017 . The transactions appear reasonable
and follow the Risk Management Committee's recommendations.
From April 2016 through March 2017, the total variable gas and gas
transportation expense for all the gas plants was $37,820,518. The total gas and gas
transportation expense included in base rates is $33,367,563. This year's PCA
deferral balance, afterjurisdictional allocation and sharing, is an increase of
$4,147,758.
Notably, the Langley Gulch facility experienced a longer than anticipated
maintenance outage - from October 24,2016, through December 15, 2016. The
scheduled maintenance outage was planned for a hot gas path inspection on the gas
turbine and to replace the steam turbine seal and set to end on November 30, 2016.
The outage was extended due to turbine rotor seal weax, found during inspection.
After the routine fall outage was extended, there were three additional unplanned
outages in December, in part due to additional maintenance that was required and
complications from the cold weather.
Upon Staff s request, the Company estimates that the incremental cost of the
replacement power for the Langley Gulch outage was $733,532. This estimate
reflects Langley Gulch generation being replaced with approximately 16,507 MW of
generation at its Danskin facility and 105,692 MW of purchased power from the
market. Staff believes that the Company took appropriate actions to mitigate the
length and the cost ofthe outage, and therefore does not propose to exclude any costs
in the PCA period as a result of the extended Langley outage.
STAFF COMMENTS 11 MAY 12,2017
Although Staff does not believe the extended outage was preventable, the
Company was not able to provide the root cause of the unplanned outage associated
with the steam turbine rotor seal wear or the cold weather complications. The
Company indicated that the results of its root cause analysis will not be available until
after this case is settled. Staff recommends that the Company provide the
Commission with a copy of its root cause analyses as a subsequent compliance filing
to this case.
4. Surplus Power Sales. To supplement its own generation, the Company purchases
power in the wholesale market based on the Energy Risk Management Policy
requirements, operating reserve margins, unit availability and economics. When the
Company has excess power or generating capacity and economics dictate, the
Company also sells power into the wholesale markets. During the PCA period, the
Company made wholesale market purchases at an average price of $38.05 per MWh,
and surplus sales at an average price of $17.98 per MWh. Base rates include
wholesale market purchases at an average price of $50.64 per MWh, and surplus sales
at an average price of $22.41per MWh.
Market purchases and sales are influenced by many things. Economic
conditions and regulations can affect the market price of natural gas and coal, which
may then impact market prices for power. Natural gas prices have been, and continue
to be, low relative to years past, and strongly influences the price of power on the
wholesale market. Decreased hydro generation can also decrease the amount of
surplus sales.
Staff reviewed the Company's power sales and purchases in conjunction with
the Company's Operating Plan. Staff reviewed all the sales and purchases, and
performed an in-depth audit of select transactions for each PCA month. Staff
compared the term purchase or sale price to the forward market prices from the
monthly Operating Plans and compared the day-ahead and real-time market prices to
the ICE (Intercontinental Exchange) Mid-C daily price index. The transactions
appear reasonable and follow the Risk Management Committee's recommendations.
These transactions were made with an assortment of credit-worthy partners on a
timely basis.
STAFF COMMENTS t2 MAY 12,20t7
During the PCA year ending March 31,2017, the Company's off-system sales
of surplus power totaled $25,768,277. The total surplus sales included in base rates is
$51,735,153. After jurisdictional allocation and sharing, actual surplus sales were
less than base amounts by $23,379,392, which increases the deferral balance to be
recovered from customers.
5. Non-Firm Power Purchases. Excluding PURPA purchases during the PCA year
ending March 31,2016, the Company bought $79,009,662 of power on the market.
The power purchases included the output from the Neal Hot Springs Power Purchase
Agreement, with a25-year levelized contract price of approximately $l 17.56/lvlWh;
and the Elkhorn (Telocaset Wind Power Partners, LLC) Power Purchase Agreement,
with a 2}-year levelized contract price of approximately $62.38/MWh. Base rates
included $62,606,593 in non-PURPA power purchases. After jurisdictional
allocation and sharing, actual non-PURPA power purchases exceeded base amounts
by $14,954,520. This increases the deferral balance to be recovered from customers.
6. Third-Party Transmission. InOrder No. 30715 , the Commission directed the
Company to track third-party transmission costs associated with market purchases
and off-system sales through the PCA like other variable power supply costs.
Including transmission expenses in the PCA is a straightforward treatment of power
supply costs that fluctuate with power purchases and sales. For the April 2016
through March 2017 PCA period, the actual third-party transmission expense is
55,522,758. The third-party transmission expense included in base rates is
$5,455,955. After jurisdictional allocation and sharing, third-party transmission
expense increases the deferral balance by $77,805.
Other PCA Expense Items
7. Renewable Enerqt Credit Sales. In Order No. 30818, the Commission ordered that
revenues from the sale of renewable energy credits ("RECs") should benefit
customers. The deferral balance includes $1,293,075 in revenue from REC sales,
after allocation and sharing. This increase in revenues decreases the defenal balance
recovered from customers.
STAFF COMMENTS l3 MAY 12,2017
Staff reviewed the REC transactions included in the PCA defenal period and
verified that the amount included in the deferral period is accurate. During Staff s
audit of the wholesale market purchases and sales, Staff discovered a wholesale
market purchase and off-setting wholesale market sale that included a sale of RECs.
Although the wholesale market purchase and sale occurred within the current PCA
deferral period, the RECs did not settle until after the current PCA period had ended.
The REC revenue from this transaction will be included in next year's deferral period.
Staff recommends that the REC revenue be recorded with the corresponding
wholesale market sale in future PCA periods.
8. Sales-Based Adjustment The Company calculates a $6,843,374 Sales Based
Adjustment (SBA) credit to customers from the Company's over-recovery of actual
NPSE collected through base rates due to differences in base versus actual sales. The
SBA replaced the Load Change Adjustment used in previous PCAs. The SBA uses
the $26.721MWh SBA rate established in Order No. 33307 (Case No. IPC-E- 1 5- 1 5).
When multiplied by the difference in actual and base rate sales, it calculates the over
or under recovery of actual NPSE due to sales that are higher or lower than sales used
to determine base rates (subjectto 95o/o customer sharing). During the April 2016
through March 2017 PCA deferral period, actual sales were 269,594 MWh higher
than sales used to set base rates, resulting in a credit back to customers. Staff audited
and analyzed the Company's SBA calculations by: (l) auditing actual sales; (2)
confirming the SBA rate and sales used to set base rates; and (3) verifying the
Company's method for calculating the SBA was consistent with the Commission's
prior orders. Staff believes the Company calculated the SBA adjustment consistently
with past Commission orders, and that the adjustment is reasonably accurate in
calculating over-recovery of NPSE due to increased sales.
9. Ouali.fuing Facilitlt/PURPA Exoense. For the April 2016 through March 2017 PCA
period, the actual Idaho Jurisdictional PURPA expense is $147,780,952. The Idaho
Jurisdictional PURPA expense included in base rates is $127,161,176. In this year's
PCA deferral balance, the actual Idaho jurisdictional PURPA expense exceeded the
PURPA expense included in base rates by $20,619,776. PURPA contracts are not
subject to sharing, but they are subject to jurisdictional allocation. Staff audited the
STAFF COMMENTS t4 MAY t2,20t7
actual monthly PURPA expense during the deferral period and believes the amount
reported is accurate.
10. Demand Response Incentive Payments. Staff reviewed the Company's actual
Demand Response Incentive payments included in the PCA defenal balance. Staff
confirms there were $7,059,424 in actual DR Incentive expenditures in the current
PCA defenal, which is $4,192,841 less than the $11,252,265 included in Base NPSE.
Demand Response Incentive payments are allocated 100% to Idaho and are not
subject to sharing. The prudency of the DR incentive payments will be determined in
Idaho Power's annual DSM prudency filing currently before the Commission (Case
No. IPC-E-17-03). Any disallowance as a result of that case will be reflected in next
year's PCA defenal balance. This reduced level of DR incentive payments reduces
the deferral balance to be recovered from customers.
11. Revenue from the PCA Forecast The previous year's PCA forecast rates generated
$45,487,126 in revenue. The forecast rate changes each June when the new PCA
rates are established. Therefore, the deferral period reflects the rate set in the two
previous PCA periods. This amount is credited to customers in the calculation of the
overall deferral balance for the April 2016 through March 2017 defenal period. Staff
verified the revenue collected during the PCA period.
12. Interest on the Deferral Balance. The deferral balance accrues interest at the
customer deposit rate, currently l%. The interest accrued during the current deferral
period is $207,079. Staff verified the interest calculations and agrees with the
Company.
Reconciliation of the True-up Analysis
As discussed earlier, the reconciliation of the true-up amount is the difference between
what was approved to be collected or refunded when the PCA rate for the previous year was set,
and what was actually collected or refunded. The reconciliation of the true-up assures that the
amount approved for recovery is the amount actually recovered. Table 6, below, summarizes the
reconciliation of the true-up for the 2016-2017 PCA period. The $2,257,651 ending balance
amount is the revenue requirement used to form the reconciliation of the true-up portion of the
overall PCA rate.
STAFF COMMENTS 15 MAY 12,2017
Staff audited the amounts booked to the reconciliation of the true-up, verified the
Company's calculations, and reviewed the method used to ensure it complies with past
Commission orders. As a result of its review, Staff believes the Company correctly reconciled
the true-up. The specifics of Staff s review are discussed below.
Table 6: True-Up Reconciliation
2015-2016 True-Up Defenal (Order No. 33526)
2015-2016 True-Up of the True-Up Ending Balance
Revenue Sharing (Order No. 33526)
DSM Rider Funds (Order 33526)
$ 43,661,193
(5,073,137)
(3,171,340)
(3,970,036)
Net Amount Set for Recovery/(Refund)
Collections from True-Up Rates
Interest
37,446,680
(29,38r,9r1)
t92,882
Subtotal (29,189,029)
True-Up Reconciliation v251-65L
1. 2015-2016 Forecast True-up Balance. The ending true-up deferral balance from the
April 2015 through March 2016 PCA period was approved in Order No. 33526; Case
No. IPC-E-16-08. The ending deferral balance in last year's PCA was $43,661,193.
This amount is added to the beginning balance of the reconciliation of the true-up,
with recovery set to start in June 2017 when new PCA rates are implemented. This
amount has been properly recorded in the month of April 2016 in the reconciliation of
the true-up for recovery.
2. 2015-2016 Reconciliation of the True-Up Balance. The remaining balance in the
reconciliation of the true-up that was under-recovered in the previous PCA period is
the beginning balance of the reconciliation of the true-up for this PCA period. The
amount of $5,073,137 was over-recovered in the previous period, and has been
properly recorded in the reconciliation of the true-up as the beginning balance.
3. Revenue Sharing. The Revenue Sharing benefit of $3,171,340 was approved in the
previous PCA, Order No. 33526, Case No. IPC-E-16-08. Staff has verified that this
Revenue Sharing amount is properly reflected in the reconciliation of the true-up.
STAFF COMMENTS T6 MAY t2,2017
4. DSM Rider Funds. The DSM Rider Transfer was approved in Order No. 33000 and
current DSM Rider rates approved in Order No. 33526. The $3,970,036 amount on
Line 104 of Company ExhibitNo. I represents the collections of the DSM Rider
portion of current Schedule 55 rates over the 2015-2016 PCA period. Staff has
verified that the reconciliation of the true-up properly reflects this amount. Order No
33736 eliminated this annual transfer of DSM Rider funds to the PCA, however this
amount from previous PCA is included in the reconciliation of the true-up.
5. Collections from True-Up Rates and Interest. Staff reviewed and verified the
collections from customers and the interest calculations. Staff has also verified that
the collections and interest are properly reflected in the reconciliation of the true-up.
Revenue Sharing
The Commission established a mechanism in 2010 that required the Company to share
revenue with customers based on the Company's actual Idaho jurisdictional year-end ROE. See
Order No. 30978. The Commission subsequently modified the Revenue-Sharing mechanism and
extended it in Order Nos. 32424 and 33149. The terms are currently effective through 2019, or
until otherwise modified or terminated by Commission Order, or the full $45 million of
Accumulated Deferred Investment Tax Credits (ADITC) are amortized.
The Company's 2016 year-end Idaho jurisdictional ROE was9.53o/o. Since the ROE was
between 9.5Yo and l}Yqthere is no revenue sharing for 2016. Staff has reviewed the work
papers, source documents, and supporting documentation and agrees with the Revenue Sharing
calculations.
DSM Rider
In Case No. IPC-E-16-33,ldaho Power filed an Application requesting that the
Commission approve a decrease in the Energy Efficiency Rider rate, and a $13 million refund of
previously collected Rider funds to be included in the 201712018 PCA mechanism, and the
elimination of the annual transfer of $4 million of Rider funds through the PCA. In Order No.
33736, the Commission found it fair just and reasonable to refund $13 million of previously
collected Rider funds to customers, and to eliminate the annual transfer of $4 million of Rider
funds through the PCA. In this Application, the Company has excluded the annual $4 million
STAFF COMMENTS 17 MAY 12,2017
Rider transfer through PCA. The Company has also included the $13 million refund of
previously collected Rider funds in this PCA filing.
Rate Calculations
Staff thoroughly reviewed the components that make up this year's Schedule 55 PCA
rates and have concluded that they are fair,just, and reasonable. Stafls review ofthe rates for
the traditional PCA components and of the DSM Rider refund included verification that: (1) the
rates were calculated accurately; (2) the methods used to spread the rates across the customer
classes provided a fair allocation; and (3) the methods complied with past Commission orders.
Included is a copy of the combined PCA rate for both the traditional PCA and the DSM Rider
refund for each customer class as Attachment C to these Comments.
As noted previously, the Company calculated the overall PCA rate of 0.7361 f/kWh by
summing the rates of the three traditional components: the forecast, the true-up, and the
reconciliation of the true-up. Staff confrrmed that the method used to allocate the revenue
requirement across the customer classes was done on an equal cents per kilowatt-hour basis.
This ensures that customers share the PCA revenue requirement based on the amount of energy
consumed which is how NPSE is allocated in customer base rates.
The only other additional rate component in this year's PCA is the DSM Rider refund.
The Company allocated the $13 million refund using each class's proportional share of
forecasted base revenues for the2017-2018 PCA collection period. Staff agrees with the
Company that this method approximates the proportion of the initial DSM Rider collected from
each class and that the refund is allocated back to customers in approximately the same way.
CUSTOMER NOTICE AND PRESS RELEASE
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined that both meet the requirements of Rule 125 of the
Commission's Rules of Procedure (IDAPA 31.01.01).
The notice was included with customer bills. Customers who would receive their bill
(with the enclosed notice) toward the end of the processing time for this case were also sent a
postcard by direct mail. All customers will be mailed a notice (by bill insert or postcard) no later
than May 19,2017, which will allow some but not all customers a reasonable opportunity to file
STAFF COMMENTS l8 MAY T2,2OI7
timely comments with the Commission by the May 12,2017 deadline. Staff recommends that
the Commission accept late-filed comments, recognizing the probability that the Commission
will be unable to take into consideration comments filed by customers whose bills are issued at
the end of the billing cycle. As of May 11,2017, the Commission had received one comment
that is opposed to the proposed increase.
RECOMMENDATIONS
Staff recommends the following:
1. The Commission approve a total defenal amount of $33,953,028 ($33,745,950
without interest) for recovery through Schedule 55 rates as shown in Staff
Attachment C, effective June 1,2017.
2. The Commission accept late filed customer comments.
3. The Company to provide a copy of all reports analyzing the root cause of failures
and downtime that occurred at the Langley Gulch facility during the October
through December 2016 timeframe.
Respecttully submitted this lZ+\ day of May 2017.
General
Technical Staff: Daniel Klein
Kathy Stockton
Rachelle Farnsworth
Mike Louis
Yao Yin
STAFF COMMENTS t9 MAY 12,2017
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Case No. IPC-E-I7-06
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Attachment B
Case No. IPC-E-I7-06
Staff Comments
05ltzlt7
ldaho Power Company
Total PCA Rate Calculation
Class Allocated EE Rider Refund
State of ldaho
Sales Based Adjustment Rate Methodology
(A)(B)(c)(D)
PCA per kwh EE Rider Refund +
Rate PCA Rate
Rate
Sch.
No.
Allocated EE Rider
Refund
EE Rider Refund
Dollars per kWh
RateLine
No Tariff Descriotion
Uniform Tariff Rates:
1 Residential Service
2 Master Metered Mobile Home Park
3 Residential Service Energy Watch
4 Residential Service Time-of-Day
5 Small General Service
6 Large General Service - Secondary
7 Large General Service - Primary
8 Large General Service - Transmission
9 Dusk to Dawn Lighting
10 Large Power Service - Secondary
11 Large Power Service - Primary
72 Large Power Service - Transmission
13 AgriculturallrrigationService
1,4 Unmetered General Service
15 Street Lighting
16 Traffic Control Lighting
17 Total Uniform Tariffs
1
3
4
5
7
95
9P
9T
15
19S
19P
197
24
40
4L
42
26
29
30
(Ss,7s8,844)
(s+,soa1
So
(S2s,oo7)
$184,762],
$2,837,237)
(53ss,186)
(S2,so8)
(s1s,932)
$4,74s)
(S1,433,307)
1520,443)
(51,754,074)
(S11,6ss)
(543,800)
(S1,997)
(0.001148)
(c.0010e7)
0.000000
(0.001107)
(0.001463)
(0.000864)
(0.0007s0)
(0.000846)
(0.002486)
(0.000746)
(o.ooo66l,)
(c.00062s)
(0.00093e)
(0.001032)
(0.001633)
(0.000730)
So.oo7361
So.oo7361
s0.007351
s0.007361
So.oo7361
So.oozaor
s0.007361
s0.007361
s0.007361
s0.007361
s0.007361
So.oo7361
s0.007361
50.007361
s0.007351
50.007361
So.oo5213
s0.006264
s0.007351
So.oo62s4
s0.00s898
s0.006497
So.oo6511
So.oo6s1s
s0.004875
s0.00661s
50.005700
So.oo5736
s0.006422
s0.005329
s0.005728
s0.006631
18
19
20
27
23
Soecial Contracts
Micron
J R Simplot
DOE
Total Special Contracts
(S12,4s8,400)
(S318,418)
(s104,s89)
(5118,s93)
(o.oo0s79)
(0.000s43)
(0.000s6s)
s0,007361
s0.007351
50.007361
50.006782
s0.006818
So.oo67s6
(Ss41,6oo)
(513,000,000)24 Total ldaho Retail Sales
Note:
June 1, 20L7 -May 37,2018 Forecasted Test Year
Attachment C
Case No. IPC-E-17-06
Staff Comments
05lt2lt7
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS l2th DAY OF MAY 20T7,
SERVED THE FOREGOING COMMENTS OT THE COMMISSION STAFF IN
CASE NO. IPC.E-17-06, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
LISA D NORDSTROM
LEAD COUNSEL
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-mail: lnordstro{[e-mail]
4o ckets @ i 4+hop o-wer. co t4
TAMI WHITE
TIMOTHY E TATUM
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-mail : [e-mail]
ttalu{n@ idahopowel. ggrq
PETER J RICHARDSON
RICHARDSON ADAMS PLLC
515 N 27TH STREET
PO BOX 7218
BOISE ID 83702
E-mail : [e-mail]
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-mail: [e-mail]
ARY
CERTIFICATE OF SERVICE