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HomeMy WebLinkAbout20190911Comments.pdfJOHN 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 t0l9 StP I I P[1 2: 23 i*: r,!{(1 pt lSLlc i il, i ;.li-c';;,il,ilSstct{ 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 ) ) ) ) ) ) ) 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 I 2 aJ 4 5 6 7 8 9 10 11 ll 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 8 I 2 J 4 5 6 7 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. 9 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: patrick.ehrbar@avistacorp.com DAVID J MEYER VP & CHIEF COLTNSEL AVISTA CORPORATION PO BOX3727 SPOKANE WA99220-3727 E-mail: david.meyer@avistacorp.com CERTIFICATE OF SERVICE