20180510Comments.pdf

BRANDON KARPEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03s7
IDAHO BAR NO. 7956
IN THE MATTER OF THE APPLICATION OF
IDAHO POWER COMPANY FOR AUTHORITY
TO IMPLEMENT POWER COST
ADJUSTMENT (PCA) RATES FOR ELECTRIC
SERVICE FROM JUNE 1,2018, THROUGH
MAY 31,2019.
ft[C E IVED
?iil$ i{:1Y l0 Pl{ 12: lr3
,,.c(-J,,,_ri i
Street Address for Express Mail
472W, WASHINGTON
BOISE, IDAHO 83702.5918
Attomey for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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CASE NO. IPC.E.18.O6
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
Application and Notice of Modified Procedure issued in Order No. 34040 on April 23,2018,in
Case No. IPC-E-I8-06 to submit the following comments.
BACKGROUND
On April l2,20l8,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 decrease overall revenue collected from Customers by about
522.6 million or 1.90o/o. The Company requested that the new rates take effect on June I,2018.
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 Qrlet 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 annual
ISTAFF COMMENTS MAY 10,2018
differences between actual NPSE and NPSE recovered through base rates. The PCA is also used
to provide revenue sharing benef,rts resulting from the revenue sharing mechanism approved in
Order No. 33149. In this year's PCA, earnings were not sufficient to provide customers with a
revenue sharing credit.
STAFF REVIEW
Summary
The Company's Schedule 55 Power Cost Adjustment tariff allows the Company to pass
changes in fuel and purchased power costs, relative to costs established in the last rate case, to its
customers.
The traditional annual PCA mechanism consists of three components: (1) a forecast of
the difference between the NPSE embedded in base rates and the 2018-2019 projected NPSE; (2)
a "true-up" that captures the difference between actual NPSE and base NPSE that was actually
collected in that year and credits the revenue from the previous year's forecast rate; and (3) a
reconciliation of the 2016-2017 true-up that captures any under-recovered or under-refunded
amounts. This reconciliation is also called the "true-up of the true-up."
The Company proposes a 2018-2019 PCA rate of 0.4854 l/kwh using a forecast of
0.63 l5 d/kwh, a true-up of -0.1398 l/kwh, and a -0.0063 l/kwh true-up of the true-up.
Overall, the proposed20l8-2019 PCA rate is 0.2507 p/kwh less than the20ll-2018
PCA rate. Most of this decrease is due to a $20 million dollar credit for better than expected
hydro generation sales realized during the2017-2018 PCA year. Current Schedule 55 PCA rates
are designed to collect approximately $90.1 million above the $305.7 million fuel and purchased
power costs incorporated in base rates. However, last year's hydro generation was greater than
forecast, resulting in higher-than-forecast surplus energy sales, and a $20 million credit to
customers. After applying this credit to the results of its 201 8-2019 fuel and purchased power
forecasts, the Company will only need to collect $69.4 million via the Schedule 55 PCA
mechanism.
Last year's Schedule 55 PCA rate included an Energy Efficiency Rider Transfer and a
refund from the Rider balancing account. The transfer and refund were removed from the
Schedule 55 PCA mechanism via Commission Order Nos. 33736 and33775. This year's PCA
includes only the three traditional components (forecast, true-up, and true-up of the true-up),
2STAFF COMMENTS MAY 10,2018
resulting in a uniform 0.4854 d,lkWh rate applied across all rate classes. The percentage change
by rate class is summarized in Table l:
Table 1: Overall Rate Impact (Excerpted from Company's Application, Attachment 2)
Class Description
Residential
Master Metered Mobile Home Park
Residential Service Time of Day
SmallGeneral Service
Large General Service
Large Power Service
Irrigation
Micron
JR Simplot
DOE
Unmetered General Service
Street Lighting
Traffic Control Lighting
Change
-1.29%
-1.40%
-1.38%
-0.80%
-2.23%
-3.10%
-r.91%
-3.66%
-3.80%
-3.74%
-1.66%
-0.65%
-2.73%
I
J
5
7
9
l9
24
26
29
30
40
41
42
System Average Decrease -1.90y,
Staff audited the Company's sales and costs for the 2017-2018 PCA year, and reviewed
the Company's sales and cost forecasting methodologies for the upcoming20lS-2019 PCA year
Staff also reviewed the Company's filing and methodologies for conformity with previous
Commission orders. Staff s major findings are:
1. Actual loads, fuel consumption, fuel costs, purchased power costs, and kilowatt hour
sales for the current PCA year (2017 -2018) are accurate.
2. The Company's methodologies for forecasting kilowatt hour sales, loads, fuel
consumption, fuel costs, and purchased power costs for the upcoming PCA year
(2018-2019) are sound.
3. The Company's calculation of the incremental change in the upcoming year's PCA
rates are consistent with Commission Order Nos. 30715 , 30978, 32206, 32424,
33149, and33307.
aJSTAFF COMMENTS MAY 10,2018
Rate Schedule No.
4. The Company's Idaho jurisdictional year-end Return on Equity (ROE) fell below the
10.0 percent ROE threshold for revenue sharing (Order No. 33149), so the 2018-2019
PCA does not include a revenue sharing component.
Forecast Analysis
System-wide monthly energy sales are forecast using the Company's predictions of load
growth and weather. The Company predicts sales of approximately 14.3 billion kWh from its
Idaho customers (Blackwell di, p l4).
Monthly load, fuel consumption, fuel costs, and purchased power costs were obtained
from the Company's March 29,2018 Operating Plan. Monthly load is determined using the
Company's sales forecast, predicted PURPA power production, Purchased Power Agreements
(PPAs), and the impact of the Company's demand response initiatives. For each month, the
Company then determines the most economical way to dispatch its hydro, natural gas, and coal
generation resources to meet its system-wide monthly load.
Under the Commission approved methodology, 100% of the difference between forecast
and actual PURPA and Demand Response Initiative expenses are included in the PCA; however,
only 95oh of fuel and non-PURPA purchased power expenses are included in the calculation.
The Company predicts that the costs of meeting the requirements of its Idaho customers will be
approximately $90.3 Million greater than the costs used to establish base rates in the Company's
last rate case (Blackwell di, p. l5). The forecast component of the Company's 2018-2019 PCA
is thus $90.3 Million - 14.3 Billion kWh : 0.6315 P/kWh, compared to the $0.4176 p/kWh used
in the 2017-2018 PCA.
The Company explained that the factors contributing to forecast increases include the
following: a decrease in hydro generation and reduced surplus sales, a significant increase in
non-PURPA market purchases and expense, and a slight 1 percent increase in natural gas fuel
expense. Large impacts to the 2018-2019 PCA forecast resulted from a 26 percent decrease of
surplus sales revenue and the related 29 percent increase in market purchases and related expense
(Blackwell di, p. 9). The forecast average market purchase price for energy is expected to drop
almost l5 percent from the previous year's price, from $25.52 to $21.83 per MWh. Staff
explains that although that drop in price helps mitigate the increase in planned market purchases,
4STAFF COMMENTS MAY 10,2018
it also reduces surplus sales revenue for the Company and increases market purchase power
expense.
Forecast energy production for coal, natural gas, and non-PURPA Purchased Power is
predicted to decrease 26 percent due to the impact of reduced hydro generation and increased
reliance on market purchased power. PURPA energy purchases are expected to remain the same
or drop slightly; however, the costs of PURPA energy purchases are expected to increase $3.3
million (2%) as a result of maturing PURPA contract payments (Blackwell, di. p. 10).
With the forecast drop in natural gas and energy market price, the Company expects a 12
percent decrease in coal generation and a I percent decrease in coal fuel expense (Blackwell di,
p.l2). The Company predicts that lower projected snowpack and inflow into the Brownlee
reservoir will result in a l0 percent reduction in hydro generation. The Company plans to
replace the loss of coal and hydro generation with a 23 percent increase in natural gas generation
(Blackwell di,p.12)-
Staff thoroughly reviewed the Company's Operating Plan assumptions and methodology,
and believes that the Company's forecast provided a reasonable basis for determining 2018-2019
Schedule 55 PCA rates.
Staff notes that the primary purpose of the forecasting mechanism is to provide real time
recovery of next year's base-to-actual deferral balance. Any over or under-collected amounts
due to forecast variance will be trued-up in subsequent years.
STAFF COMMENTS MAY 10,20185
True-Up Analysis
The true-up deferral balance as shown on the line labeled "Ending True-up Balance" in
Company Exhibit 2 is primarily made up of the differences between actual NPSE and NPSE
recovered through base rates, and forecast revenues. It also includes Renewable Energy Credit
(REC) sales and the difference between actual demand response incentive payments and amount
recovered in base rates. The ending balance of the true-up also includes collections through the
current forecast PCA rate and monthly accrued interest.
The Company converts the true-up amount to a p/kWh rate by dividing it by projected
energy sales. The Company calculates Idaho ratepayers' share of the true-up amount for a
refund of approximately $20 million, and expects to refund that amount through a true-up rate of
-0.1398 f,kWh as compared to last year's rate of 0.3129$lkwh. Table 2, below, summarizes the
$19,993,280 true-up refund amount proposed by the Company
Staff s review of the true-up includes: (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 Energy 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
that the Company's proposed true-up amount is accurate, that the methods used conform to past
Commission Orders, and that actual costs incurred are reasonable and prudent.
Although there is no effect in this year's PCA, the Company will be including operation
and maintenance expenses directly related to its participation in the Western Energy Imbalance
Market (EIM) in next year's PCA. The Idaho Power recovery method for costs associated with
participating in the EIM, has been filed in Case No. IPC-E-17-16. The benefits of the EIM
market will automatically flow through the PCA, matching costs with benefits until the next
general rate case, at which point the costs and benefits will be built into rates.
STAFF COMMENTS MAY 10,20186
Table 2z PCA True-Up Summary
Net Power Supply Expense Differential
Fuel Expense - Coal
Fuel Expense - Gas
Non-Firm Purchases
Surplus Sales
Third Party Transmission Expense
Water for Power (Leases)
Deferral Amount
$ (4,341,371)
363,728
1,978,910
9,951,964
(1,229,653)
(2,149,499)
Subtotal - Net Power Supply Expense
Other PCA Items
Emission Allowances & Renewable Energy Credit (REC) Sales
Sales Based Adjustment
Qualifying Facilities
Demand Response Incentive Payments
$4,575,089
$(3,355,103)
(5,116,501)
50,124,959
(4,268,958)
Subtotal - Other PCA Items
Total Expense Items
Revenue from PCA Forecast
$37.384.398
$41,959,488
$(61,918,793)
Deferral Balance (Expense Items less PCA Forecast Revenue)
Interest on the Deferral Balance
Total True-Up Deferral 09J93280)
Details of the different components in the PCA true-up, as shown in Table 2, are
described below. Positive numbers represent a customer cost (recovery from customers), and
negative numbers represent a customer benefit (credit to customers). All amounts are shown
after jurisdictional allocation and sharing.
Net Power Supply Expense Differential
Staff believes the Company prudently incurred NPSE to meet customer load. The
Company's NPSE primarily consists of costs related to coal and other fuels, non-PURPA
purchased power, and surplus sales. During the 201712018 PCA year, increased availability of
hydro generation allowed the Company to decrease power generation from coal and other fuels,
and allowed the Company to increase surplus sales over what had been forecast. There was also
an increase in market power purchases, displacing generation at the Company's coal and natural
gas plants. Actual hydro-generation was higher than forecast and as a result the volume of
7STAFF COMMENTS MAY 10,2018
$(19,959,306)
(33,975)
surplus sales was 14 percent higher than expected. Actual coal and natural gas generation were
lower than forecast. Market purchases were higher than forecast, and these market purchases
partially offset generation from the coal and natural gas plants. The main NPSE components are
described below.
l. Fuel Expense - CoaL The Company owns an interest in, and receives electricity
from, three coal plants: Bridger, Valmy, and Boardman. Staff reviewed all months
of the coal expenses and performed an in-depth audit for the months of July and
August 2017. The Company includes the increase or decrease in coal expense from
base rates in the PCA for recovery from, or a credit to, customers. The Company
included expenses of the 2015 test burn of Powder River Basin coal. The Company
previously deferred this in conjunction with the ongoing evaluation of long-term
fueling strategies. The company concluded that significant plant investments would
be required to burn PRB coal. These deferred expenses are appropriately recorded in
FERC account 501 as these costs reflect net fuel costs for providing generation to
customers, as well as being used for evaluation of PRB as a fuel source. From April
2017 t}rot:gh March 2018, the total coal expense for the three plants was
$103,318,634. The total coal expense included in base rates is $108,503,180. This
year's PCA deferral balance, after jurisdictional allocation and sharing, includes a
difference of $4,341 ,371 and is a credit to customers.
2. Fuel Expense - Gas. The Company owns and operates gas-fired combustion turbine
generating plants at the Evander Andrews Power Complex (Danskin), Bennett
Mountain, and Langley Gulch. Staff reviewed all months of the natural gas expenses
and performed an in-depth audit for October and December 2017. The transactions
appear reasonable and follow the Idaho Power Energy Risk Management
Committee's policies and standards.
The Company includes the increase or decrease in natural gas expense from
base rates in the PCA for recovery from, or a credit to, customers. For the2017-2018
defenal period, the total variable gas and gas transportation expense for all the gas
plants was $33,654,349. The total gas and gas transportation expense included in
base rates is $33,367,563. This year's PCA deferral balance, after jurisdictional
8STAFF COMMENTS MAY 10,2018
allocation and sharing, includes a difference of $363,728 for recovery from
customers.
3. Non-firm Purchases. To supplement its own generation, the Company purchases
power in the wholesale market based on its Energy Risk Management Policy and
Standards, operating reserve margins, unit availability, and economics. Excluding
PURPA purchases during the 2017-2018 PCA year, the Company bought
$64,633,258 of power on the market. 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 $ I ,978,910.
The approximate $2 million of additional purchase power expense compared
to the expense embedded in base rates is primarily driven by increased amounts of
market purchases and lower electricity prices. The average unit cost of wholesale
purchases in base rates was $50.65 per MWh compared to $43.57 per MWh in the
deferral period. Although long-term contracts still reflect higher than spot market
prices, the Company was able to take advantage of lower electricity prices overall to
fulfill customer demand.
Staff reviewed the purchases, and performed an in-depth audit of select
transactions during the PCA deferral period. Staff compared the term purchase price
to the forward market prices from the monthly Operating Plans and compared the
day-ahead and real-time market prices to the Intercontinental Exchange Mid-C daily
price index. The transactions appear reasonable and follow the Risk Management
Committee's recommendations. These transactions were made with an assortment of
credit-worthy partners on a timely basis.
4. Off-$tstem Sales. During the2017-2018 PCA year, the Company's off-system sales
of surplus power totaled $40,633,415. The total surplus sales included in base rates is
$51,735,153. The reduction in the amount of surplus sales compared to base amounts
is driven primarily by lower market electricity prices. After jurisdictional allocation
and sharing, actual surplus sales were less than base amounts by $9,951,964; this
increases the deferral balance to be recovered from customers.
5. Third-Partv Transmission In Order No. 3071 5, the Commission directed the
Company to track third-party transmission costs associated with market purchases
9STAFF COMMENTS MAY 10,2018
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 2017-2018 PCA
period, the actual third-party transmission expense is $4,077,351. The third-party
transmission expense included in base rates is $5,455,955. After jurisdictional
allocation and sharing, third-party transmission expense decreases the deferral
balance by $1,229,653 and is a credit to customers.
6. 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 deferral. 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.
Other PCA Expense Items
7. Emission Sales & Renewable Enerw Credit Sales. In Order No. 3081 8, the
Commission at that time required the sale of RECs with the benefits flowing to
customers. The deferral balance includes $3,355,103 in revenue from Emission and
REC sales, after allocation and sharing. This increase in revenues decreases the
deferral balance recovered from customers.
Staff reviewed the Emission and REC transactions included in the PCA
deferral period and verified that the amount included in the deferral period is
accurate. Staff notes that the only Emissions Sales of $37.62 occurred in the month
of August 2017. In recent years Idaho Power has not had any emission sales.
8. Sales-Based Adjustment The Company calculates a $5,166,501 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 uses the $26.721MWh SBA rate established in Order No. 33307 (Case No.
IPC-E-15-15). 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 (subject to 95Yo customer sharing).
STAFF COMMENTS 10 MAY 10,2018
During the2017-2018 PCA deferral year, actual sales were 201,564 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: (1) 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 accurate.
9. Ouahrtting Facilin/PURPA Expense. For the 2017-2018 PCA deferral period, the
actual Idaho Jurisdictional PURPA expense is $177,286,136. The Idaho
Jurisdictional PURPA expense included in base rates is 5127,161,176. In this year's
PCA deferral balance, the actual Idaho jurisdictional PURPA expense exceeded the
PURPA expense included in base rates by $50,124,959. PURPA contracts are not
subject to sharing, but they are subject to jurisdictional allocation. Staff audited the
actual monthly PURPA expense during the deferral period and believes the amount
reported is accurate.
10. Demand Response Incentive Pqtments. Staff reviewed the Company's actual
Demand Response (DR) incentive payments included in the 2017-2018 PCA defenal
balance. Staff confirms there were $6,983,307 in actual DR Incentive expenditures in
the deferral, which is $4,268,958 less than the $11,252,265 included in Base NPSE.
DR incentive payments are allocated l00Yo 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-18-
03). Any DSM prudency disallowance as a result of that case will be reflected in next
year's PCA deferral balance. This reduced level of DR incentive payments reduces
the deferral balance to be recovered from customers.
ll. Revenue _from the PCA Forecast The Company's forecast rates generated
$61,918,793 in revenue during the deferral period. 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 defenal balance for the 2017-2018 defenal period. Staff
verified the revenue collected during the PCA period.
STAFF COMMENTS l1 MAY 10,2018
12. Interest on the Deferral Balance. The deferral balance accrues interest at the
customer deposit rate, currently l%. The interest accrued during the current defenal
period is a credit to customers of $33,975. Staff verified the interest calculations and
agrees with the Company.
Reconciliation of the True-up (True-up of the True-up) Analysis
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 any other line items collected in
the PCA such as revenue-sharing, 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 over-collected by about $0.9 million, resulting in a proposed
reconciliation of the true-up rate of -0.0063 l/kwh as compared to a rate of 0.161 1 l/kwh in last
year's PCA.
Table 3, below, summarizes the reconciliation of the true-up for the 2016-2017 PCA
period. The $(898,592) ending balance amount is the revenue requirement used to form the
reconciliation of the true-up portion of the overall PCA rate. The reconciliation is shown on the
line labeled "Ending True-Up of the True-Up Balance" in Company Exhibit 2.
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 3: True-Up Reconciliation
2015-2016 True-Up Deferral (Order No. 33775)
2015-2016 True-Up of the True-Up Ending Balance
DSM Rider Funds (Order 33526)
$ 33,953,029
2,257,657
(13,000,000)
Net Amount Set for Recovery/(Refund)
Collections from True-Up Rates
Interest
$23,210,680
$(24,234,497)
125,225
Subtotal
True-Up Reconciliation
(24,109,272)
s(898.592)
STAFF COMMENTS t2 MAY 10,2018
1 . 2016-2017 True-up Defenal Balance. The ending true-up deferral balance from the
2016-2017 PCA period was approved in Order No. 33775; Case No. IPC-E-I7-06.
The ending deferral balance in last year's PCA was $33,953,029. This amount is
added to the beginning balance of the reconciliation of the true-up. This amount has
been properly recorded in the month of April 2017 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 $2,257 ,651 was under-recovered in the previous period, and has been
properly recorded in the reconciliation of the true-up as the beginning balance.
3. DSM Rider Funds. In OrderNo. 33736, the Commission approved a $13 million
refund of previously collected Rider funds to customers through the PCA. This
amount from last year's PCA filing is correctly recorded in May 2017 inthe
reconciliation of the true-up.
4. 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 are amortized.
The Company's2016 year-end Idaho jurisdictional ROE was9.94%o. Since the ROE was
less than l\Yo, there is no revenue sharing for 201 7. Staff has reviewed the work papers, source
documents, and supporting documentation and agrees with the Revenue Sharing calculations.
STAFF COMMENTS l3 MAY 10,2018
Rate Calculations
Staff reviewed the components of this year's Schedule 55 PCA rates and concluded 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.
As noted previously, the Company calculated the overall PCA rate of 0.48541/kwh by
summing the rates of the three traditional components: the forecast, the true-up, and the
reconciliation of the true-up. Staff confirmed 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.
Langley Gulch Investigation
Prior to this filing, the Company had not provided a report of its conclusions regarding
the outage experienced by the Langley Gulch generating plant between October 24,2076, and
December 15,2016. The Langley Gulch outage resulted in incremental replacement power costs
of $733,532, and was a significant issue discussed by Staff in the Company's last PCA case
(rPC-E-17-06).
Previously, the Commission has stated, "[w]e look forward to the Company providing
reports and conclusions regarding the root cause of the failures and why the extended downtime
occurred." Order No. 33775 at 4. At Staff s request, the Company summarized its findings in its
response to Stafls Production Request No. 2. This is included as Attachment A to Staff s
Comments. Staff has not had sufficient time to review the Company's report.
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 or will be included with
bills mailed to customers beginning April 23 and ending May 22,2018. Customers whose bills
will be mailed on May 2l or May 22 were sent a direct mail postcard outlining the Company's
filing on April 23. Unfortunately, even with the Company's attempt to provide earlier notice to
STAFF COMMENTS t4 MAY 10,2018
some customers, many will not have a reasonable opportunity to file timely comments with the
Commission by the May 1Oth comment deadline.
Because the Company is proposing a rate decrease, it is less likely that customers will not
object to the proposed rate changes. However, all customers should have an opportunity to file
comments and have their comments considered by the Commission. In this instance, Staff
encourages the Commission to accept and consider late-filed customer comments. As of
May 10, 2018, the Commission has not received any customer comments for this case.
STAF'F RECOMMENDATIONS
Staff recommends the following:
l. That the Commission approve the Company's proposed PCA rates as filed.
2. That the Commission accept late filed customer comments.
Respectfully submitted this [0"! day of May 2018.
General
Technical Staff: Mike Morrison
Kathy Stockton
Johan Kalala-Kasanda
Johnathan Farley
Michael Eldred
Rachelle Farnsworth
STAFF COMMENTS l5 MAY 10,2018
BFOUEST NO. 2: On page 4 of Commission Order No. 33775, the Commission
discussed the December 2016 outage at Langly Gulch, and stated, 'We look forward to
the Company providing reports and conclusions regarding the root cause of the failures
and why the extended downtime occurred." Has the Company completed its
investigation? lf so, please provide a copy of the Company's final repo(. lf not, please
explain why the Company has not completed its investigation.
RESPONSE TO REQUESJ NO. 2: ldaho Power recently completed its
investigation of the root cause analysis of the 2016 extended outage at Langley Gulch,
the details of which are explained below. Although the Company devoted a significant
amount of time to the investigation and reviewed a vast amount of data, a definitive root
cause was not discovered.
During the planned fall outage for Langley Gulch, scheduled for October 24,
2016, through November 30, 2016, work was planned to replace the seals on the high-
pressure steam turbine. This was being done in conjunction with the normal
maintenance cycle for the gas turbine as part of the service provided in the Long-Term
Service Agreement with Siemens. During inspections, additional wear and cracking
was found on the blade roots, blade tip seals, and inter-stage seals on the turbine rotor.
Due to these findings, the turbine rotor had to be shipped to the manufacturer's
recommended maintenance facility located in Seattle, Washington, for repairs. Repairs
for the turbine rotor occurred between November 11,2A16, and December 1, 2016.
The high-pressure steam turbine was reassembled and plant maintenance was
completed on December 15, 2016. Due to the turbine rotor seal wear found during
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE COMMISSION STAFF - 5 Attachment A
Case No. IPC-E-18-06
Staff Comments
05ll0ll8 Page 1 of 3
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I
inspection, the October 2016 scheduled outage was extended approximately two weeks
beyond the target completion date of November 30, 2016, to December 15, 2016.
During last year's PCA proceeding, ldaho Power committed to determine the root
cause of the turbine rotor seal wear. The Company's efforts to determine the root
cause entailed reviewing plant operating data to pinpoint any conditions of excessive
heating or cooling that may have occurred on the steam turbine seals.
ln its efforts to deterrnine the root cause, ldaho Power began working to retrieve
historical plant operating data from the plant Distributive Control System ("DCS")
historian. This process began in May 2A17, and involved installing a new onsite
computer, which was synched with Siemens' system, to retrieve historical operating
data for Langley Gulch from 2011 through 2016. The data captured in the DCS
historian includes numerous operating parameters, such as temperature, pressure, and
steam flow readings for the steam turbine.
Embrittlement of seals or seal rubs, like those found during the extended outage,
are typically caused by over-heating or cooling events. As a result, the Company
examined the data for events or causes that could have resulted in an over-heating or
cooling event on the steam turbine case or rotor, including wet insulation, temperature
stratification within the steam turbine enclosure, and steam admitted to the turbine case.
ldaho Power reviewed plant data and maintenance records to determine if there
were any instances in which the turbine operated with partial insulation installed or if
there were any events that may have led to wetting of insulation on top or bottom of the
turbine casing. A review of plant records showed no evidence of running the turbine
under any of these conditions.
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE COMMISSION STAFF.6
Attachment A
Case No. IPC-E-18-06
Staff Comments
05ll0l18 Page 2 of 3
ldaho Power also reviewed the data for changes to the steam turbine room
enclosure, such as removal/replacement of the roof or wall panels, to determine if the
turbine case may have been exposed to an externaltemperature event. There were no
recorded events of changes to the room enclosure from 2011 through 2016.
Finally, the Company inspected the Thermal Stress Evaluator ('TSE') program
for any operational issues. The TSE program is designed to help limit and protect the
steam turbine from any excessive heating or cooling events. The TSE program data is
stored in the DCS historian. ln reviewing the data, ldaho Power determined there were
no instances in which the TSE experienced operational issues or loss of protection
functionality, The Company also examined the TSE program's operational settings that
admit steam into the turbine case. There were no findings or evidence that the settings
would have allowed the turbine to operate outside the range of the TSE program
parameters during commissioning activities prior to ldaho Power operating the plant or
following turnover of the plant to ldaho Power through 2A16.
Over the past several months, the Company spent a significant amount of time
and reviewed a voluminous amount of data to find a root cause for the extended outage
at Langley Gulch; however, a definitive root cause was not discovered nor did the
Company find any evidence that the steam turbine operated beyond Original Equipment
Manufactu rer recommendations.
' The response to this Request is sponsored by Mike Williams, Power Production
Manager, ldaho Power Company.
DATED at Boise, ldaho, this lstday of May 2018.
ISA D. NO
Attorney for ldaho Power Company
IDAHO POWER COMPANY'S RESPONSE TO THE FIRST
PRODUCTION REQUEST OF THE COMMISSION STAFF. T
Attachment A
Case No. IPC-E-18-06
Staff Comrnents
05ll0l18 Page 3 of 3
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS IOTH DAY OF MAY 2018,
SERVED THE FOREGOING COMMENTS OF' THE COMMISSION STAFF, IN
CASE NO. IPC-E-I8-06, BY MAILING A COPY THE,REOF, POSTAGE PREPAID,
TO THE FOLLOWING:
LISA D NORDSTROM
REGULATORY DOCKETS
IDAHO POWER COMPANY
PO BOX 70
BOrSE ID 83707-0070
E-mail : lnordstrom@,idahopower.com
dockets@ idahopower. com
MATTHEW T LARKIN
TIMOTHY E TATUM
IDAHO POWER COMPANY
PO BOX 70
BOrSE rD 83707-0070
E-mail : [e-mail]
ttatum@idahopower. com
Y
CERTIFICATE OF SERVICE