20231017Comments of the Commission Staff.pdf

CHRIS BURDIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE,IDAHO 83720-0074
[phone] MSSi N
IDAHO BAR NO.9810
Street Address for Express Mail:
11331 W CHINDEN BVLD,BLDG 8,SUITE 201-A
BOISE,ID 83714
Attorneyfor the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )AVISTA UTILITIES FOR AN ORDER )CASE NO.AVU-G-23-06
APPROVING A CHANGE IN RATES FOR )PURCHASED GAS COSTS AND )AMORTIZATION OF GAS-RELATED )COMMENTS OF THEDEFERRALBALANCES)COMMISSION STAFF
COMMISSION STAFF ("STAFF")OF the Idaho Public Utilities Commission
("Commission"),by and through its Attorneyof record,Chris Burdin,Deputy Attorney General,
submits the followingcomments.
BACKGROUND
On September 1,2023,Avista Corporation d/b/a/Avista Utilities ("Company")filed its
annual Purchased Gas Cost Adjustment ("PGA")application ("Application")with the Commission
requesting a change in rates for purchased gas costs and amortization of gas-related deferral
balances.The Company represents that,if approved,the Company's annual revenue will increase
by approximately $5.4 million,or about 5.0%.
The PGA is a Commission-approved mechanism that adjusts rates up or down to reflect
changes in the Company's costs to buy natural gas from suppliers includingchanges in
transportation,storage,and other related costs.The Company defers these costs into its PGA
STAFF COMMENTS 1 OCTOBER 17,2023
account and then passes them on to customers throughan increase or decrease in rates.The
Company requested that the proposed rates take effect November 1,2023.
Overview of Proposed Rates
The Company proposes to:(1)pass any change in the estimated cost of natural gas for the
period of November 2023 throughOctober 2024 (Tariff Schedule 150);and (2)revise the
amortization rate(s)to refund or collect the balance of deferred gas costs (TariffSchedule 155).If
the filing is approved,residential customers using an average of 64 therms per month would see
rates increase by $3.54,or 4.7%per month.Id at 5.The Company's proposed changes to
Schedules 150 and 155 and the Company's rates are further explained below.
Table No.1 summarizes the impact of the proposed changes on customer classes.
Table No.1:Summary of Proposed PGA Rate Changes by Class
Service Schedule Commodity Demand Total Amortization Total Rate
No.Change per Change per Sch.150 Change per Change
Therm (a)Therm (b)Change Therm (d)per Therm(c=a+b)(e=c+d)
General 101 $(0.06236)$(0.00354)$(0.06590)$0.12118 $0.05528
Lg.General 111 $(0.06236)$(0.00354)$(0.06590)$0.12118 $0.05528
Lg.General 112 $(0.06236)$(0.00354)$(0.06590)-$(0.06590)
Interruptible 131 $(0.06236)-$(0.06236)-$(0.06236)
Transportation 146 -----
STAFF ANALYSIS
Staff reviewed the Company's Application and accompanying workpapers and
recommends approval of the Company's Applicationto increase natural gas revenues in Idaho by
approximately $5.4 million,or about 5.0%.Staff examined the Company's gas purchases for the
year,its fixed price hedges,pipeline transportation and storage costs,and estimates of future
commodity prices,to assess the reasonableness of the proposed changes.Staff also reviewed the
Company's jurisdictionalallocation and the reasonableness of the Company's Lost and
Unaccountedfor ("LAUF")Gas volumes.Staff verified that the Company's filing will not change
the Company's earnings.Staff also confirmed that the proposed changes to Tariff Schedules 150
and 155 accurately capture the Company's fixed (demand)and variable (commodity)costs given
the coming year's forecasted gas purchases,and properly amortizes the deferral balance from the
prior year.
STAFF COMMENTS 2 OCTOBER 17,2023
Schedule 150 -Purchased Gas Cost Adjustment
Tariff Schedule 150 is a portion of the PGA which consists of commodity costs and
demand costs.The Company's commodity costs are the variable costs that the Company incurs to
buy natural gas.The Weighted Average Cost of Gas ("WACOG")is an estimate of those costs.In
this case,the Company estimates its commodity costs will decrease by $0.06236 per therm,from
the currentlyapproved $0.35070 per therm to $0.28834 per therm.Id at 3.The proposed decrease
of $0.06236 per therm for residential customers is primarily related to lower forward prices
compared to the prior PGA.
The Company's demand costs are the costs for interstate transportation and underground
storage.Id.at 4.The demand portion of Schedule 150 also includes some benefits from the
Deferred Exchange Contract that are credited back to customers.The Company proposes a
decrease in the overall demand rate of $0.00354 per therm.
Weighted Average Cost of Gas
The WACOG includes fuel charges to move gas at the city gate,some variable transport
costs,Gas Research Institute ("GRI")funding,and some benefits associated with the Deferred
Exchange Contract.It does not include third party gas management fees.In this case,the
Company proposes a WACOG of $0.28834 per therm.This is a decrease of approximately
17.78%from the current approved WACOG of $0.35070 per therm.Staff encourages the
Company to update its WACOG if gas prices materiallydeviate.
Chart No.1 illustrates the changes in WACOG over time.
Chart No.1:Historical WACOG
0.500 Avista PGA WACOG ($/Therm)
0.400 --
E
g 0.300
-0.200
0.100
0.000
$0.352$0.373$0.385$0.252 0.240 0.219 0.16450.170$0.153$0.1620.203$0.265 0.352$0.288
2012 2013 2014 2015 2016 2017 2017*2018 2019 2020 2021 021*2022 2023
Year *AVU-G-17-06 **AVU-G-21-07
STAFF COMMENTS 3 OCTOBER 17,2023
Schedule 155 -Amortization of the Deferral Account
Tariff Schedule 155 reflects the amortization of the Company's deferral account.The
deferral consists of the difference in the price the Company paid for natural gas and the WACOG
established in the previous PGA.The Company's proposed amortization rate change for Schedule
101 and Schedule 111 is an increase in revenue of $0.12118 per therm.The current rate for
Schedule 101 and Schedule 111 is $0.13163 per therm in the surcharge direction and the proposed
rate is $0.25281 per therm in the surcharge direction reflecting the $0.12118 increase.
Included in the deferral activity are two items that benefit customers:excess capacity
releases totaling $3,168,499,discussed in detail in the Procurement Plan section below,and the
benefits from the Deferred Exchange Contract totaling$2,062,688.The associated benefits,along
with the excess capacity releases,are included in the deferral activity shown in Table No.2.The
deferral also includes the monthlyinterest charges on the deferred balances.
The Company calculated the balance for amortization to be $24,470,532.On a per therm
basis,the net impact of the expiring amortization rebate and the proposed amortization surcharge
of $0.25281 is a change of $0.12118.
A reconciliation of Tariff Schedule 155 deferral and amortization is shown in Table No.2:
Table No.2:PGA Deferral and Amortization Reconciliation
Amortization Balance as of June 30,2022 $3,279,449
Amortization Activity (11,725,636)
True-Up (November 1,2022)8,271,428
Interest on Unamortized Balance 52,686
Total Unamortized Balance $(122,073)
Current Year Deferral Activity
Deferral Balance as of June 30,2023 $9,441,439
Deferral of Demand Costs 1,094,493
Deferral of Commodity Price Differences 28,919,857
Interest on Deferrals 325,502
Excess Capacity Releases (3,168,499)
Deferred Exchange Contract (2,062,688)
Total Amortization Balance $26,315,368
Total Balance to be amortized via Rate Schedule 155 $24,470,532
STAFF COMMENTS 4 OCTOBER 17,2023
Market Fundamentals &Price Analysis
The Company hedged natural gas throughoutthe previous thirty-six months for the
forthcoming PGA year.Approximately58%of the annual load requirements for this year's PGA
period (November 2023 throughOctober 2024)have been hedged at a fixed price derived from the
Company's Procurement Plan.ThroughJune,the hedged volumes for the PGA period have been
executed at a weighted average price of $3.66 per dekatherm,or $0.3660 per therm.
The Company used a 30-day historical average of AECO forward prices (ending July 31,
2023)to develop an estimated cost associated with index purchases.The index purchases
represent approximately 19%of estimated annual load requirements for the coming year.The
annual weighted average price for the volumes is $2.25 per dekatherm or $0.2247 per therm.Last
year the annual weighted average price was $2.90 per dekatherm,or $0.290 per therm.
Staff also examined the forecasts of national and regional organizationsto see how
perceived market conditions might vary from the NYMEX/NGX futures prices.Specifically,Staff
reviewed the forecasts from the Energy Information Administration ("EIA").I The EIA Short-
Term Energy Natural Gas Outlook2 SÍnÍCT
Natural gas production
We forecast U.S.dry natural gas production to remain relativelyflat for the rest
of 2023 and 2024.Dry natural gas production averaged more than 102 billion
cubic feet per day (Bef/d)in the first half of 2023 (1H23),which is a 6 Bef/d
increase compared with the same period in 2022.We expect dry natural gas
production will average about 104 Bef/d throughthe end of the forecast in 2024.
Production has remained at relatively high levels throughout 2023 despite a
decline in U.S.natural gas prices.The U.S.benchmark Henry Hub spot price
averaged $2.41 per million British thermal units (MMBtu)in lH23,compared
with an annual average of $6.42/MMBtuin 2022.
Natural gas inventories
U.S.workingnatural gas inventories totalled 3,051 billion cubic feet (Bcf)at the
end of July,12%above the five-year (2018-2022)average and 22%above the
same period last year.Net injections of natural gas into storage have exceeded the
five-year average by 3%so far this refill season (April 1-October 31),in part due
to high natural gas production.The increased surplus of natural gas storage
inventories reduced natural gas prices throughoutlH23 compared with 2022.We
forecast working natural gas inventories to end the refill season at nearly 3.9
trillion cubic feet (Tcf)which is 7%,or 250 Bef,higher than the five-year
average.We expect storage inventories to remain above the five-year average
'EIA website https://www.eia.gov/outlooks/steo/report/natgas.php
2 Source https://www.eia.goy/outlooks/steo/report/nateas.php 9/23/2022
STAFF COMMENTS 5 OCTOBER 17,2023
throughout 2024 as natural gas production remains high and natural gas
consumption declines by 2%in 2024 compared with 2023.
Based on Staff s review of the market fundamentals and trends,Staff believesthat the
Company's cost of its current hedges and estimated cost of forward-lookingindex purchases are
reasonable.
Procurement Plan
The Company uses a diversified approach to procure natural gas for the coming PGA year.
The Company's Procurement Plan uses a structured approach to execute its hedges that includes a
range of possible hedge windows with varyinglong-term and short-term trigger prices.However,
its Procurement Plan also allows it to make discretionary decisions so it can adjust to changes in
market conditions.
Capacity Release
The Company buys the right to transport gas throughseveral interstate pipelines.This
enables the Company to buy gas from a variety of supply basins,both in the U.S.and in Canada,
and then transport to its jurisdiction.As mentioned previously,whenever the Company has
surplus capacity on the pipelines that serve its jurisdictions,surplus capacity is sold to other
pipeline users.The Company's total excess capacity release revenue this year for Idaho was
$3,168,499.The Company's historical capacity releases are shown below in Chart No.2.
Chart No.2 Historical Capacity Releases
Avista Historical Transportation Capacity Release
$1,000,000
2014 PGA 2015 PGA 2016 PGA 2017 PGA 2018 PGA*2019 PGA 2020 PGA 2021 PGA 2022 PGA 2023 PGA
Series1 $2,700,000 $3,490,000 $2,709,578 $2,709,578 $2,198,130 $2,086,925 $1,938,269 $1,679,915 $3,230,427 $3,168,499
*2018 value restated in the 2019 PGA due to an error
STAFF COMMENTS 6 OCTOBER 17,2023
Lost and Unaccountedfor Gas3
Staff reviewed the Company's LAUF gas rate and compared it to previous years.The
Company reported a LAUF gas rate of (0.55)%found gas.Staff asked the Company to provide
supporting LAUF gas workpapers,a reconciliation of LAUF gas numbers used in the PGA Report,
and numbers reported to the Pipeline and Hazardous Material Safety Administration ("PHMSA").
Staff notes that the five-yearaverage is (0.03)%found gas.
The Company provided the followingtable showing a five-year view of LAUF gas
amounts.
Table No.3:LAUF Gas Amounts
Year Delivery Revenue Loss +/-Gain %Of Purchase
2019 143,375,963 141,549,516 1,826,447 1.29
2020 155,715,413 158,836,712 (3,121,299)(1.97)
2021 156,717,867 156,036,168 681,699 0.44
2022 155,409,201 154,210,102 1,199,099 0.78
2023 154,319,011 155,172,337 (853,326)(0.55)
5 Year Average 153,107,491 153,160,967 (53,476)(0.03)
Reporting
Currently,the Company submits two reports either monthly or quarterly.The monthly
report includes a summary of the deferred costs with a journal entry of the amounts booked.The
quarterly report is the WACOG report.Because review of the PGA filing happens within a short
time frame,Staff recommends that both reports be submitted quarterly and that the Company
submit two additional documents.The first document that Staff recommends to be submitted
quarterly is the gas accounting data download ("GADD")in Excel format with a reconciliation tab.
The GADD report will improve audit efficiencies,increase turnaround time of data requests,and
decrease the number of Staff's audit/production requests.
The second document that Staff recommends is the deferral calculation workbook
("DCW")in Excel format.The workbook summarizes the numbers in the GADD and ties them to
The American Gas Association describes unaccounted for natural gas in the utility system is defined as follows:At
a city gate,natural gas is transferred from an interstate or intrastate pipeline to a local natural gas utility.At that
moment,some utilities measure the volume of gas using highly sophisticated technology that can quickly and precisely
take into account a varietyof factors,including temperature and pressure.The utility reports the volume of gas sold to
customers as represented on their bills.The difference between the city-gate measurement and the volume of gas sold
is treated as unaccounted-for gas by regulators,who build a form of reimbursement for this gas into the utility's rate
structure.
STAFF COMMENTS 7 OCTOBER 17,2023
the PGA workpaper.The DCW workbook needs to be filed with the last quarterly report before
the PGA Application.Again,the DCW report will improve efficiencies for Staff.
Customer Comments,Notice,and Press Release
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determinedthat both meet the requirements of Rule 125 of the
Commission's Rules of Procedure,IDAPA 31.01.01.125.The notice was included with bills
mailed to customers beginning September 12,2023,and ending October 6,2023.
The Commission set a comment deadline of October 17,2023.Some customers in the last
billing cycles may not have received or had adequate time to submit comments before the
deadline.Customers must have the opportunityto file comments and have those comments
considered by the Commission.Staff recommends that the Commission consider late filed
comments from customers.As of October 16,2023,no customer comments had been filed.
STAFF RECOMMENDATIONS
After examining the Company's Application,natural gas purchases,and deferral activity
for the year,Staff recommends the Commission:
1.Approve the Company's proposed Tariff Schedule 150,includingthe proposed
WACOG of $0.28834 per therm and demand charge of $0.08884per therm,for a
total of $0.37718 per therm,as filed;
2.Approve the Company's proposed Tariff Schedule 155,with the proposed
amortization rate of $0.2528 1 per therm,as filed;
3.Direct the Company to continue filing quarterly WACOG reports and change the
monthly deferred cost reports to quarterlyand include two additional reports;the
GADD in Excel format,and DCW in Excel format filed with the last quarterly
report before the PGA filing;and
4.Consider late-filed comments from customers.
STAFF COMMENTS 8 OCTOBER 17,2023
Respectfullysubmitted this 17th day of October 2023.
Chris Burdin
Deputy AttorneyGeneral
Technical Staff:Kevin Keyt
Travis Culbertson
Leena Gilman
Curtis Thaden
Jon Kruck
i:umisc/comments/AVU-G-23-06 Comments
STAFF COMMENTS 9 OCTOBER 17,2023
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 17th DAY OF OCTOBER 2023,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF TO
AVISTA CORPORATION,IN CASE NO.AVU-G-23-06,BY E-MAILING A COPY
THEREOF TO THE FOLLOWING:
PATRICK EHRBAR DAVID J MEYER
DIR OF REGULATORY AFFAIRS VP &CHIEF COUNSEL
AVISTA CORPORATION AVISTA CORPORATION
PO BOX 3727 PO BOX 3727
SPOKANE WA 99220-3727 SPOKANE WA 99220-3727
E-mail:[e-mail] E-mail:david.meyer avistacorp.com
[e-mail]
SECRETARY
CERTIFICATE OF SERVICE