20190911Comments.pdf

JOHN R. HAMMOND, JR.
EDWARD J. JEWELL
DEPUTY ATTORNEYS GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 3 34-03 s7 1334-03 | 4
IDAHO BAR NOS . 547 0110446
REC EIVED
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Street Address for Express Mail:
472W. WASHINGTON
BOISE, IDAHO 83702.5983
Attorneys for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITTES COMMISSION
IN THE MATTER OF THE POWER COST
ADJUSTMENT (PCA) ANNUAL RATE
ADJUSTMENT FILING OF AVISTA
CORPORATION
CASE NO. AVU.E-19.09
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission, submits the following comments
regarding the above referenced case.
OVERVIEW OF COMPANY APPLICATION
On July 30,2019, Avista Corporation dba Avista Utilities ("Avista" or the "Comparry")
filed its annual Power Cost Adjustment ("PCA") Application.
The PCA is an annual cost adjustment mechanism that tracks changes in the Company's
hydropower generation, fuel costs, power market purchases and sales, transmission revenue and
expenses, Renewable Energy Credit ("REC") revenue, power contract revenue and expenses, and
other miscellaneous revenue and expenses. It ensures that customers do not pay more or less than
the Company's prudently incurred actual net power costs ("NPC"). When the actual NPC are
greater than that recovered through base rates, customers are surcharged the difference. When the
actual NPC are lower, customers receive a rebate. The annual PCA rate is combined with the
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ISTAFF COMMENTS SEPTEMBER I1, 2019
Company's base rate to produce aratepayer's overall energy rate. The money collected from
ratepayers through the PCA can only be used to pay approved NPC, and the Company's earnings
are not increased by the PCA mechanism.
The Company asks the Commission to approve a PCA rebate of 0.058 cents per kilowatt-
hour ("kWh") to be effective October 1,2019, in place of the current rebate rate of 0.326 cents
per kWh approved by Order No. 34159. This will be a reduction of 0.268 cents per kWh for all
customers. Since the PCA rate adjustments are spread on a uniform cents-per-kWh basis, the
resulting percentage increase varies by rate schedule. The overall increase is 3.3oh. The table
below shows the percentage change on billed revenue for each customer group.
Percent on Billed Revenue for Each of Service
STAFF RE,VIEW AND ANALYSIS
Staff has thoroughly examined the Company's PCA Application by reviewing: (l) actual
and authorized expenses included in the deferral; (2) the deferral calculation method; (3) the
prudence of actual NPC incuned during the deferral period; (4) the calculation of balancing
accounts and interest used to determine the final PCA rate; and (5) the calculation of the PCA
rate. Based on this review, Staff concludes:
l. The Company correctly booked actual NPC amounts and amortization for the PCA
period (July 201 8 through June 2019) and utilized proper loads and NPC amounts
embedded in base rates to calculate the deferral.
2. The Company properly calculated the deferral using the methods approved by the
Commission.
2
Types of Service Schedule Numbers Percent Change on
Billed Revenue
Residential I 2.9%
General Service I I I 2)2.7%
Large General Service 21,22 3.3%
Extra Large General Service 25 5.0%
Clearwater 25P s.3%
2.8%Pumping Service 31,32
0.8%Street and Area Lights 4t-49
Total 3.3%
STAFF COMMENTS SEPTEMBER I1 ,2019
3. The Company properly calculated the amount to be refunded to customers in the
balancing account.
4. The amount of actual NPC incurred to serve the customer load was reasonable and
prudent.
5. The Company calculated PCA rates using methods approved by the Commission
providing a rebate to customers ensuring they will pay no more or no less than actual
costs minus sharing.
Details of Staff s conclusions are provided in the sections below.
Review of Actual and Authorized Amounts
Staff conducted an on-site audit during the week of August 19,2019, and confirmed the
Company correctly booked the current deferral balance and the amortization of the prior year's
PCA deferral. Staff examined transactions included in the Purchased Power account (FERC
Account 555), Thermal Fuel account (FERC Account 501), Combustion Turbine Fuel account
(FERC Account 547), and Sales for Resale account (FERC Account 447). Based on review of the
transactions, Staff is reasonably assured that the various power cost transactions are reasonable
and prudently incurred based on information known at the time they were made and that all
transactions comply with Avista Utilities Energy Resources Risk Policy. Staff also audited and
confirmed that Avista's booked amounts and other calculations have been correctly reflected in
the deferral.
Staff confirmed the authorized NPC amounts used to calculate the deferral were the same
used to determine base rates that were authorized during the deferral period. Base rates that were
in effect during the deferral were authorized in Case No. AVU-E-17-01for the entire deferral
period. The Company used the correct Load Change Adjustment Rate ("LCAR") of $24.73lMWh
for the months of July through December 2018 and $24.84/MWh for the months of January
through June 2019. The LCAR amounts were also authorized in Case No. AVU-E-17-01.
Calculation of the Deferral
The power cost deferral captures the difference between actual NPC and the revenue that
recovers NPC through base rates for the twelve months ending June 30, 2019. It is then adjusted
by other miscellaneous expenses, the REC revenue adjustment, and interest. The table below
shows the final deferral balance calculations is a $1,505,903 rebate to customers.
aJSTAFF COMMENTS SEPTEMBER I I ,2019
Under Avista's PCA, the Company and its ratepayers share the difference between actual
NPC and NPC embedded in base rates. The sharing percentage is 90% for ratepayers and l0%
for the Company. When actual costs are higher than those recovered through base rates, Idaho
customers pay 90o/o of the difference. When actual costs are lower, customers are credited 90%
of the difference allowing the Company to keep 10%. This provides an incentive for the
Company to lower NPC by operating their system more efficiently.
Staff examined each account that contributes to the final deferral balance and reviewed the
method used in the Company's calculations. Staff believes that the amount of the deferral
balance is accurate, and the method used to derive it complies with past Commission orders. The
amount represents the over-recovery of NPC through base rates during the deferral period and
thus is a refund to customers.
4STAFF COMMENTS SEPTEMBER 11, 2019
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Deferral Activity (after sharing)
FERC Account 555 - Purchased Power
FERC Account 447 - Sale for Resale
FERC Account 501 - Thermal Fuel
FERC Account 547 - CT Fuel
Net Transmission Revenue and Expense
FERC Account 557 - Resource Optimrzation
FERC Account 537 - Montana Invasive Species Expense
Idaho Load Change Adjustment
Other Expense
Renewable Energy Credits Revenue
REC Revenue for Washington Renewable Portfolio Standards
Net Deferral Balance
Interest on the Deferral Balance
Total Deferral Balance
$ 13,398,734
(12,406,172)
(141,253)
2,043,032
(1,373,426)
(2,242,063)
479,093
(1,584,270)
93,960
223,706
0
$(1.508.6s9)
2,756
$(1,505,903)
5STAFF COMMENTS SEPTEMBER I1 ,2079
l. FERC Account 555 - Purchased Power. Purchased power costs reflect90% of the
Idaho jurisdiction share of the difference in costs the Company incuned for power purchases
during the deferral period and the authorized power costs included in base rates.
Palouse Wind Project ("Palouse Wind") expenses are included in the Purchased Power
costs. In the most recent general rate case (Case No. AVU-E-17-01), Palouse Wind expenses
were not included in base rates and the expenses continue to be recovered through the PCA. This
expense treatment requires Avista to share l0% of the Idaho jurisdictional costs of Palouse Wind.
Had the costs been included in base rates, customers would have paid up to l00oZ of the costs
associated with Palouse Wind.
2. FERC Account 447 - Sale for Resale. The Company routinely makes long-term and
short-term off-system sales to balance load. In the deferral period, the Company had greater off-
system sales than are included in base rates, which benefits customers.
3. FERC Account 501 - Thermal Fuel. Thermal Fuel, primarily coal, is used to produce
electricity. During the deferral period, the Company incurred slightly lower costs than are
currently included in base rates, providing a benefit to customers.
4. FERC Account 547 - CT Fuel. Combustion Turbine ("CT") Fuel is natural gas burned
in the Company's gas-fired generators. During the deferral period, the Company incurred higher
costs than are currently included in base rates.
5. FERC Account 456 - Transmission Revenue and FERC Account 565 - Transmission
Expense. In Case No. AVU-E-09-01, the Commission approved a multi-party settlement that
authorized the Company to include transmission revenues and expenses in the PCA. Avista
incurs third party transmission costs when it purchases power and it is wheeled or delivered to its
service area by a third party. Third party transmission revenues occur when Avista is the third
party and is delivering power for others. Including transmission revenues and expenses in the
PCA tracks the variability of these items. Avista's actual transmission revenue was higher than
what was included in the base rates, while its actual transmission expense was slightly higher than
the amount included in base rates. The net of the transmission revenue and expense is a benefit to
customers.
6. FERC Account 557 - Resource Optimization. Resource Optimization results in a cost
or benefit to customers when natural gas is purchased in advance for use in generating electricity,
then is later sold because it was more cost effective to sell the gas and purchase electricity than to
generate electricity. The gain during the review period is a benefit to Idaho customers.
7. FERC Account 537 - MT Invasive Species Expense. The Company included the fees
imposed under Montana Senate Bill 363 which assist with preventing and controlling invasive
species.
8. Idaho Load Change Adjustment (Retail Revenue Adjustment). This adjustment
captures the over or under recovery of net power supply expense through base rates attributable to
the difference between actual sales and sales used to set base rates. During the deferral period,
the Company experienced greater sales than were used to set base rates and the adjustment is a
benefit to customers.
6STAFF COMMENTS SEPTEMBER 11 ,2019
9. Other Expense. This represents the Merchandise Processing Fees associated with U.S.
Customs and Border Protection. Avista maintains that all of its natural gas imports should qualify
for preferential treatment and not be assessed a merchandise processing fee. Other natural gas
importers in the Northwest and across the United States have either been through, or are in the
midst of investigations similar to this issue. The industry, working through the American Gas
Association, has requested reconsideration that requires proof of Canadian origin. Staff agrees
that the approximately $94,000 included in actual NPC is reasonable, but will continue to monitor
this issue as more information becomes available.
10. Renewable Energy Credit Revenue. The Company continues to book REC revenue in
Account No. 557 along with Resource Optimizatron. Based on Order No. 33605, the Company
has separately reported actual and authorized REC revenue and expenses in its PCA filing. l'he
revenue generated from Avista's sales of RECs was less than the amounts authorized in base
rates, and is a line item deferral increase to customers.
I 1. REC Revenue Credit for Washineton Renewable Energy Poftfolio Standards. The
REC Retirement Benefits for RECs used to meet Washington Renewable Portfolio Standards are
tracked 100% through the PCA. It is based on the Idaho allocation of RECs that were retired to
meet Washington RPS requirements that would have otherwise been sold. In this deferral period,
the Company did not record a credit; however, in July 2019, the Company recorded a credit of
$857,010 that benefits Idaho customers. This credit is a result of the retirement of hydro RECs
from 2017 as well as a true up for RECs from 2016. This credit will be reflected in Avista's 2020
PCA rate adjustment filing.
12. Interest durins Deferral Period. The Company calculates interest on the deferral
balance using the Customer Deposit Rate. On January 1,2019, the customer deposit rate
increased ftom lo/o to 2o/o. Due to the nature of the monthly calculation of interest, the interest on
the deferral balance is a cost to customers, although the overall ending balance of the deferral is a
benefit to customers.
Calculation of the Balancing Account and Proposed Rebate Amount
The balancing account includes the deferral balance, and incorporates the amortization of
the previous year's deferral balance. The unamortized balance from previous deferrals (prior to
July 1 ,2018, the start of the current deferral period) is netted with the amortization of that
balance. The amortization is either a surcharge or a refund to customers. After accounting for
7STAFF COMMENTS SEPTEMBER 11,2019
interest, there remains an unamortized balance. This amount is added to the current year's
deferral amount for collection beginning October 1't of each calendar year. The Company
includes a projection of the amortization (for the months of July through September) and
calculates the interest on those projections. The total balance for amortization is then used in the
calculation of the PCA rate that will take effect on October l, 2019. The following table shows
the calculation for the current period.
Prudency of Net Power Cost
From an overall perspective, Staff determined that the Company prudently dispatched its
available resources and transacted sales and purchases that resulted in reasonable net power costs
during the PCA year (July 2018 through June 2019) given fuel prices, availability of hydro
generation, and market prices of electricity. However, the Company has incurred significant
forced outages at both the Colstrip Power Plant ("Colstrip") and Coyote Springs Power Plant Unit
2 ("Coyote Springs 2"). Staff s main concern is with the operation of the Coyote Springs 2 plant
which has already negatively impacted NPC by about $2.5 to $2.6 million (Johnson, Di, p. 9)
during this past year. The facility is currently operating at reduced output and because of the
nature of the problems and the lack of a permanent solution, the facility has the possibility cf
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Balancing Account Activity
Total Deferral Balance
Unamortized Balance from Previous Deferrals (prior to July l, 2018)
Amortization July 201 8 - June 2019
Interest through June 2019
Total Remaining Unamortized Balance
Projected Amortizatron and Interest (July 20l9-September 2019)
Total Rebate Amount (Line I + Line 5 + Line 6)
$GJ05J03)
$(1 1,488,758)
$9,040,814
$(.t02.726\
$pJ_s@
u32A,511
$GJ359eO
STAFF COMMENTS SEPTEMBER 1I ,2019
continuing to impact NPC and capital costs into the future if not addressed appropriately and in a
timely manner.
Analysis of Dispatch
In analyzing the Company's NPC, Staff compared base and actual amounts of generation,
the cost of the generation by type, and the unit cost used in determining authorized rates. Based
on its analysis, Staff believes that the Company dispatched its available resources, purchased
power from the wholesale market, and transacted off-system sales to serve customer load in a
prudent manner. The table below summarizes the results:
2018 PCA Actual versus Authorized Net Power Supply Expense Differences
Major drivers affecting net power costs within this year's PCA were (1) lower hydro
generation, (2) low natural gas prices, and (3) outages at the Colstrip Units 3 and 4 and Coyote
Springs 2.
Hydro generation overall accounts for 50o/o of Company-owned generation. During this
past PCA year, actual hydro generation was lower by 200,681 MWh or 5.2%o relative to
generation amounts used in determining base rates. Staff believes the reduction in hydro
generation was the primary driver that is increasing overall net power costs, requiring the
Company to make additional market purchases and dispatch the Company's other fueled
resources that operate at a higher cost. This is reflected in Account 501 Thermal Fuel in the table
above. Kettle Falls Generating Station and Colstrip Units 3 and 4 saw a 6.0%o increase in the
amount of generation compared to the amount predicted in base rates. However, increased
utilization of these facilities likely contributed to more efficient operations indicated by a7.0Y,
reduction in their unit cost during the PCA year.
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Expense Category MWh
Change
MWh
Yo Change
$/MWh
Change
$/MWh
Yo Change
Avista Hydro (200.681 )(s.2%)N/A N/A
Acct 555 Purchases 1,066,63 8 47.0%($o.t t1 0.0%
Acct 447 Sales 1,371,462 86.001o ($2.2t;12.0%
Acct 501 Thermal Fuel (Coal & Wood)97,520 6.0%($ I .1e)(7.0%)
Acct 547 CT Fuel (Natural Gas)527,457 18.0%($ I .2e)(6.0%)
STAFF COMMENTS SEPTEMBER I1, 2OI9
Lower wholesale natural gas prices at the AECO trading hub allowed the Company to
economically dispatch increased generation from its gas fired plants especially given reduced
hydro generation.l During the PCA year, gas fired generation increased by 527,457 MWh or
18.0% compared to the assumptions used to determine base rates. However, due to downtime at
the Coyote Springs 2 plant discussed below, the amount of generation could have been higher.
The lower natural gas prices reduced the average unit cost of gas generation by 6.0o/oto
$19.91/MWh.
Generator Facility Forced Outages
Outages at two of the Company's largest generating resources negatively impacted net
power costs during the PCA year. The Company experienced the first significant plant outage in
late June of 2018 at the Colstrip thermal plant. Units 3 & 4 of the plant failed to meet Mercury &
Air Toxics Standards ("MATS") emissions compliance but after investigation, repair and
regulatory approval, reliable dispatch resumed in August 2018. Company estimates indicate lost
generation during the plant outage negatively impacted power supply expense by $0.4 to $1.5
million (Johnson, Di, p. 1l). Staff believes that the Company adequately worked through the
issues with Talen Energy, the owner-operator of the facility, and has come to full resolution of the
causes of the downtime.
The second major plant outage occurred in September 2018 at the Coyote Springs 2
combined cycle plant. Coyote Springs 2 experienced a fault and trip of the generator step-up
("GSU") transformer which electrically ties the plant to the transmission grid. The transformer
experienced a high energy internal arc that damaged the transformer windings. The plant's GSU
transformer configuration is a single point failure design that prevents the plant from operating
when the transformer is out of service. The downtime lasted into October, costing the Company
approximately $2.5 to $2.6 million in additional net power cost by not having availability of the
facility during that time (Johnson, Di, p. 9). In October of 2018, an onsite spare replacement was
placed into service following the GSU failure, but the replacement experienced elevated oil
temperatures forcing the plant to now operate at reduced capacity. The Company is evaluating its
I Values used in Account 547 include the Lancaster combined cycle power plant operated through a purchase power
agreement with Avista.
STAFF COMMENTS SEPTEMBER 11, 2019l0
options, but a follow-on GSU replacement is not available due to long lead procurement times
and the Company has not yet identified a more permanent resolution.
Complicating the situation, the GSU has been replaced four times since 2002. In those
past cases, the Commission found that the actions taken by the Company to replace the GSUs
were prudent with the Company reporting that the causes were related to manufacturing defects.
However, given the benefit of hindsight and the fact that Avista continues to see failures that
seem to be heat-related regardless of sourcing from different vendors, it is likely that the
Company did not fully identify the root cause of the GSU failures. Therefore, Staff believes the
Company's investigations were insufficient to prevent failures from happening again.
Staff reviewed both the recent outage as well as the history of several prior incidents of
failed GSU transformers at the Coyote Springs 2 plant. Generally, GSU transformers have a
design life equivalent to the life of the plant. In March of 2002, prior to the plant being
commissioned, the first GSU transformer was energized for service. On May 6th the transformer
experienced a catastrophic failure resulting in the rupture of the transformer oil tank.
A replacement GSU transformer was procured and placed into service ayear later in May
2003, delaying plant commissioning until July of 2003. On January 15th of 2004,the replacement
or second GSU transformer was de-energized due to an alarm tied to off gassing of the
transformer oil which occurs due to overheating. Damage was so severe that this second
transformer was returned to the manufacturer in Gebeze, Turkey to be rebuilt. After rebuilding,
the second GSU transformer was returned and placed into service in August of 2004. As a result
of this outage the plant was unable to operate for 7 months. The rebuilt GSU transformer
operated until March of 2007, when it was removed from service due to alarms showing a buildup
of gases in the transformer oil, again due to overheating.
The third GSU transformer, previously purchased as a spare, was placed into service on
May 2 1 't of 2007 and has operated until recent events in September of 20 I 8. In November of
2007 the Company purchased a fourth GSU transformer as a spare. Following the event in
September 2018, the fourth GSU transformer was placed into service on October 28,2018. On
November 2Oth of 2018, the fourth GSU transformer oil analyzer indicated there may be an issue
showing a sharp increase in combustible gasses in the transformer oil suggesting elevated metal
temperature internal to the transformer (Dempsey, Di, p. 12). The current situation with the
fourth GSU transformer has forced the Company to de-rate the plant to 200 MW leaving the
STAFF COMMENTS l1 SEPTEMBER 1I,2OI9
Coyote Springs 2 plant without an immediate available replacement. The current status leaves the
plant exposed to a potential extended outage should the situation get worse.
Staff s main concern is that the transformer continues to experience heat-related issues
putting the plant at risk. Instead of purchasing a spare of the same design or continuing to replace
transformers that cost over five million dollars each, the Company is investigating changing the
configuration of the GSU transformer from a combined three-phase transformer to three separate
single phase transformers. However, this will require major modifications requiring significant
capital investment to a plant that is more than halfway through its useful life. Staff believes that
the Company could choose to operate the facility in its current configuration at a reduced level
potentially being required to replace additional GSU transformers, or it could reconfigure the
facility. Regardless of the choice, Staff encourages the Company to fully investigate and verify
the root causes of the failures and to determine a least cost and reliable resolution to the problem
as timely as possible.
Staff s second concern is whether or not customers should be required to pay increased
costs due to the downtime and reduced output of the plant. Given the circumstances, Staff
believes that a clear recommendation is not easily ascertained. Looking at the history and
judgments rendered by the Commission for past failures, it is easy to understand how the cause of
the failures could have been attributed to manufacturing defects. However, when the first
transformer failed in2002, the Company also investigated the multi-transformer configuration
that the Company is now currently re-evaluating. If the heat problems were attributed to the
current transformer configuration rather than a manufacturing defect had been changed at that
time after doing a more extensive root cause analysis and verification, subsequent failures may
not have occurred.
Determining if the Company acted prudently in addressing the series of GSU failures at
the plant is an issue. Avista tried to identify the causes that led to the GSU failures, but Staff
believes that the Company did not go far enough. In every instance, the Company employed
experts to do forensic examinations of the failed units. Through those examinations, the
Company saw consistent evidence of a heat-related problem across the history of failures,
regardless of vendor. After the units were replaced, Staff could not find any evidence that the
Company performed the extra steps necessary beyond gathering forensic evidence to identify
what was causing the excessive heat related to the failures.
STAFF COMMENTS t2 SEPTEMBER 11,2079
Although Staff believes that Avista could have done more, it does not believe that actions
or lack of actions by the Company constituted imprudent action to justify a disallowance in this
year's PCA. Staff does not believe the Company was negligent in its actions and without any
verification of the true cause, it is difficult to know with any certainty if any additional
investigation could have prevented downtime and the additional costs incurred.
Because Staff believes that the priority is for Avista to have a cost-effective and reliable
resource in the future, Staff recommends that the Company conduct the necessary investigation
and studies so that it can make decisions that will ultimately be in the best interests of customers.
As a result of its investigation, Staff recommends that the Company provide a comprehensive
report detailing the history of these failures and actions it has or will take to contain the situation
so that there are no further impacts to reliability or cost. It is essential for the Company to
complete a thorough identification, verification, and mitigation of potential root causes to prevent
this type of failure from occurring again.
Analysis of PCA Rates
Based on its review of the Company's calculation of its proposed PCA rate, Staff verified
that the result is accurate and will fairly reimburse customers for over-collection of actual net
power costs embedded in base rates. Using the Company-proposed PCA rate of 0.058 cents per
kWh, residential customers with monthly average energy usage of 898 kWh would see their
monthly bills increase by $2.40 (2.91%) from $82.57 to $84.97. Bills increase because a larger
current rebate rate (0.360 cents per kwh) is being replaced by a lower proposed rebate rate (0.058
cents per kwh).
Staff verified the PCA rate calculation where the amortization and deferral balance of
negative $1.736 million grossed up to a revenue target of negative $1.746 million, and the target
is divided by forecasted energy consumption of 3,008,379,000 kwh to obtain the proposed rebate
rate of 0.058 cents per kWh (Brandon Exhibit AMB-1, page l). This procedure conforms to
approved methodology.
CUSTOMER NOTICE AND PRESS RELEASE
The Company's press release and customer notice were included with its Application.
Each document addresses two cases: this case (AVU-E-19-09) and the Residential and Farm
Energy Rate Adjustment (AVU-E-19-08). Staff reviewed the documents and determined both
13 SEPTEMBER 1I,2OI9STAFF COMMENTS
meet the requirements of Rule 125 of the Commission's Rules of Procedure (IDAPA 31.01.01).
The notice was included with bills mailed to customers beginning August 16,2019.
For this case, the Commission set a comment deadline of September I 1, 2019. Because
the customer notices were not inserted into the bills until August 16,2019, some customers in the
last billing cycles will not have received their notices or had adequate time to submit comments
before the deadline. Customers must have the opportunity to file comments and have those
comments considered by the Commission. Staff recommends that the Commission accept late-
filed comments from customers. As of September 10,2019, no comments had been filed.
STAFF RECOMMENDATION
Staff recommends the following:
l. The Commission authorize the total deferral balance in the amount of negative
$1,505,903 to be refunded to customers.
2. Approve Schedule 66 as filed in Exhibit A of the Company's Application effective
October 1,2019.
3. The Commission order the Company to continue to report PCA expenses in their
monthly reports by the PCA year.
4. The Commission accept late-filed comments from customers.
5. The Company provide a comprehensive report to the Commission detailing its
investigation and studies of outages at the Coyote Springs 2 Plant and its plans to
mitigate future outages.
Technical Staff: Travis Culbertson
Jolene Bossard
Bentley Erdwurm
Rick Keller
Kathy Stockton
i :umisc:comments/avue I 9.9jhejklstncrkjbbe comments
J.-
day of September 2019tt
J Hammond Jr.
Attorney General
STAFF COMMENTS t4 SEPTEMBER I I ,2019
Respectfully submitted this
CERTIFICATB OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS I lTH DAY OF SEPTEMBER 2019,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO, AVU-E-19-09, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
PATRICK EHRBAR
DIRECTOR REGULATORY AFFAIRS
AVISTA CORPORATION
PO BOX3727
SPoKANE W A 99220-3727
E-mail: [e-mail]
DAVID J MEYER
VP & CHIEF COLTNSEL
AVISTA CORPORATION
PO BOX3727
SPOKANE WA99220-3727
E-mail: [e-mail]
CERTIFICATE OF SERVICE