20210817Comments.pdf

JOHN R. HAMMOND, JR.
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03s7
IDAHO BAR NO. 5470
IN THE MATTER OF THE APPLICATION OF
AVISTA UTILITIES FOR AN ORDER
APPROVING A CHANGE IN RATES FOR
PURCHASED GAS COSTS AND
AMORTIZATION OF GAS.RELATED
DEFERRAL BALANCES
Street Address for Express Mail:
1I33I W CHINDEN BVLD, BLDG 8, SUITE 2OI.A
BOISE, tD 837I4
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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CASE NO. AVU-G.2I.04
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission submits the following comments
regarding the above referenced case.
BACKGROUND
On July 2,2021, Avista Corporation dba Avista Utilities ("Company") filed its annual
Purchased Gas Cost Adjustment ("PGA") Application. 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-including changes in transportation, storage, and other related costs. The
Company defers these costs into its PGA account and then passes them on to customers through an
increase or decrease in rates. The Company states its proposal will increase rates for an average
residential or small commercial customer by $6.00 per month (12.1%). The Company requested
that the new rates take effect September 1,202I.
The Company is filing this Application earlier than the typical August-September
timeframe to limit the bill impact to customers from the accumulated deferral and amortization
1STAFF COMMENTS AUGUST 77,2021
surcharge balances that have increased due to rising natural gas costs in recent months since the
Company's last filing. 1d.
Concurrent with the PGA filing, the Company filed a Deferred Balances Credit Case
No. AVU-G-21-03. That case, if approved, would return to customers deferred balances related to
Natural Gas Deferred Depreciation Expense of $894,000, Accumulated Funds Used During
Construction ("AFUDC") of $393,000, and Coronavirus Aid, Relief, and Economic Security
("CARES") Act benefits of $648,000.
Overview of Proposed Rates
In this PGA Application, the Company proposes to: (1) pass any change in the estimated
cost of natural gas for the next 12 months to customers (Tariff Schedule 150); and (2) revise the
amortization rates to refund or collect the balance of deferred gas costs (Tariff Schedule 155).
The Company's PGA proposal would increase the Company's annual revenue by
approximately $9.0 million or about 135%. If approved, residential customers using an average of
63 therms per month would see rates increase by $4.56 or 9.2%o per month. The Company's
proposed changes to Schedules 150 and 155 and the Company's rates are further explained below.
The Company proposes to change its PGA per therm rates for its customer classes as
follows:
Table No. 1: Summarv of Pronosed PGA Rate Chanees bv Class
Service Sche
dule
No.
Commodity
Change per
Therm (a)
Demand
Change
per
Therm
(b)
Total
Sch.150
Change
(c=a+b)
Amortization
Change per
Therm (d)
Total
Rate
Change
per
Therm
(e=c*d)
General 101 $0.04022 $0.00238 $0.04260 $0.052se $0.09519
Lg. General lll $0.04022 $0.00238 $0.04260 $0.05259 $0.09s 19
Lg. General tt2 $0.04022 $0.00238 $0.04260 $0.04260
Intemrptible 131 $0.04022 $0.04022 s0.4022
Transportation 146
2STAFF COMMENTS AUGUST I7,2O2I
STAFF ANALYSIS
Staff reviewed the Company's PGA Application and accompanying workpapers and
supports the Company's proposal to increase natural gas revenues in Idaho by approximately $9.04
million or 13.5Yo. 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
jurisdictional allocation and the reasonableness of the Company's Lost and Unaccounted for Gas
("LAUF") volumes. Staff verif,red that the Company's filing will not change the Company's
earnings. Staff also confirmed that the proposed changes to 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.
Schedule 150 - Purchased Gas Cost Adjustment
The Tariff Schedule 150 portion of the PGA 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 increase by $0.04022 per therm, from the
currently approved $0.16283 per therm to $0.20305 per therm.
The Company's demand costs are the costs for interstate transportation and underground
storage. The demand portion of Schedule 150 also includes some benefits from the Deferred
Exchange Contract that are credited back to customers. The Company proposes an overall demand
rate of $0.00238 per therm. The proposed increase is primarily related to changes in exchange
rates between Canadian and U.S. dollars, updated demand forecasts, and new Canadian Pipeline
rates that went into effect June l, 2021. Id.
Weighted Average Cost of Gas ("WACOG")
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. [n this case, the
Company proposes a WACOG of $0.20305 per therm. This is an increase of approximately 25Yo
from the current approved WACOG of $0.16238 per therm. Staff encourages the Company to
JSTAFF COMMENTS AUGUST I7,2O2I
update its WACOG if gas prices materially deviate. Chart No. I shows the Company's historical
WACOG.
Chart No. 1: Historical WACOG
Avista PGA WACOG (S/Therm)
E
o.CF
vD
0.4500
0.4000
0.3s00
0.3000
0.2500
0.2000
0.1s00
0.1000
0.0s00
0.0000
so.3s2 So.sze s0.38s So.zsz So.z+o So.zrg So.req So.rzo So.rs:So.roz s0.203
20t2 2013 20L4 20L5 20t5 20t7 20!7*2018 20L9 2020 202L
Year ' AVU-G-17-06
Schedule 155 - Amortization of the Deferral Account
Tariff Schedule 155 reflects the amortization of the Company's deferral account. The
Company's proposed amortization rate change for Schedule 101 and Schedule 111 is an inuease
in revenue (or expiration of the existing rebate and replacing it with a surcharge) of $0.05259 per
therm. The current rate applicable to Schedule 101 and Schedule 111 is $0.03754 per therm in the
rebate direction; the proposed rate is $0.01505 per therm in the surcharge direction.
The defenal consists of the difference in the price the Company paid for natural gas and the
WACOG established in the previous PGA. The deferral also includes the monthly interest charges
on the deferred balances. Included in the deferral activity are two items that benefit customers:
excess capacity releases totaling $1,679,915 - discussed in detail in the Risk Management section
below, and the benefits from the Deferred Exchange Contract totaling $1,089,713.
The Company has a Deferred Exchange Contract under which it receives natural gas during
the summer and redelivers that natural gas in the winter. The Company charges a fixed per therm
price for this service and flows all the benefits through Schedules 150 and 155. Customers
received a benefit of $1,089,713 during the PGA year from the Deferred Exchange Contract, and
4STAFF COMMENTS AUGUST I7,2O2I
these benefits, along with the excess capacity releases, are included in the deferral activity shown
in Table No. 2 below.
In the past, the Company has included forecasted natural gas deferrals and amortization
amounts until the time when the new rates are in effect. This year the Company did not include a
forecast in its Application to mitigate a large rate increase. The Company also filed this
Application with a shortened deferral period to mitigate the increasing deferral balance and to time
the increase with the proposed rate decrease in Case No. AVU-G-21-01. Staff supports the
Company's rate mitigation efforts to prevent rate shock to customers.
The Company calculated the balance for amortization as of May 3l,202l,tobe
$4,363,943. On a per therm basis, the net impact of the expiring amortization rebate and the new
amortization surcharge is a change in the amortization rate of $0.05259.
In an effort to reduce the impact on customer bills, the Company is proposing to amortize
the surcharge balance of approximately $4.4 million to be received from customers over a 38-
month period, rather than the normal 12-month period. This will allow the Company to re-
evaluate the amortization period during the next PGA filing and adjust the recovery period as
appropriate. Staff believes that this is a reasonable approach to mitigating the increase in customer
rates.
A reconciliation of the Schedule 155 deferral and amortization is shown in Table No. 2:
Table No. 2: PGA Deferral and Amortization Reconciliation
Amortization Balance as of October 31,2020
Amortization Activity
lnterest on Unamortized Balance
Total Unam ortized Balance
Current Year Deferral Activity
Deferral Balance as of October 31,2020
Deferral of Demand Costs
Deferral of Commodity Price Differences
Interest on Deferrals
Excess Capacity Releases
Deferred Exchange Contract
Total Amortization Balance
Total Balance to be amortized via Rate Schedule 155
s 747,614
2,711,448
ls.460
$ 3,474,522
$
79,639
3,579,622
789
(1,679,915)
(1.089.713)
$ 889,421
s 4.363.943
5STAFF COMMENTS AUGUST I7,2O2I
Market Fundamentals & Price Analysis
Because a large portion of the Company's annual throughput consists of market index
purchases (approximately 600/o), Staff routinely scrutinizes the Company's projected monthly cost
of purchased gas. The Company continues to use a 30-day historical average of forward prices to
forecast the volume-weighted average annual index price and forecasts a cost of $2.34 per
dekatherm ($0.234 per therm), which is an increase of $0.57 per dekatherm ($0.057 per therm)
over the 2020 PGA forecast of $ I .77 per dekatherm ($0. 1 77 per therm). Staff reviewed Futures
prices at each of the three hubs where the Company purchases gasl and believes the Company's
cost forecasts to be reasonable.
Staff also examined the forecasts of national and regional organizations to see how
perceived market conditions might vary from the NYMEXAIGX Futures prices. Specifically,
Staff reviewed the forecasts from the Energy Information Administration (EIA).2 The EIA Short-
Term Energy Natural Gas Outlook3 states:
In May. the natural gas spot price at Henry Hub averaged $2.91 per million British
themal units (MMBtu). which is up from the April average of $2.66lMMBtu.
We expect the Henry Hub spot price will average $2.92lMMBtu in 3Q21 and
$3.O7lMMBtu for all of 2021. which is up from the 2020 average of
S2.03/MMBtu. Higher natural gas prices this year primarily ref'lect two lactors:
grouth in liquefied natural gas (LNG) exports and rising domestic natural gas
consumption outside of the power sector. Ln2022, we expect the Henry Hub price
r.vill average $2.93/MMBtu amid slowing growth in LNG exports and rising U.S.
natural gas production.
Based on Staff s review of the market fundamentals and trends, the202l-2022 forecasts
are consistent, predicting relatively stable near-term gas prices. Staff believes that the Company's
cost of its current hedges and estimated cost of forward-looking index purchases are reasonable.
Risk Management
The Company's 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 varying long-term and short-term trigger prices
I The Company is supplied by three natural gas hubs (Rockies, Sumas, and AECO). Future settlement prices are
reported daily as a price differential from the NYMEX Henry's Hub price.
2 EIA website https:i/wrvw.eia. gov/naturalsas/
3Source https:/irvrvr.r'.eia.sovioutlooks/steo/repofi/natgas.php 7/7/2021
6STAFF COMMENTS AUGUST I7,2O2I
However, its Procurement Plan also allows it to make discretionary decisions so it can adjust to
changes in market conditions.
The Company modified its Natural Gas Procurement Plan in mid-2015 to change how the
Company uses its portion of the Jackson Prairie storage facility. With the modified plan, storage
can be used to capture the economic benefits of purchasing lower cost natural gas throughout the
year and selling it later if not consumed by customers. For this year's PGA (September 2021
through May 31,2022), the Company's hedges were executed at a weighted average price of
$0.181 per therm, an increase of $0.01 per therm from the 2020 price of $0.171 per therm.
Capacity Release
The Company buys the right to transport gas through several 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 that gas 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 at the highest price available. The Company's total excess capacity release revenue
this year for Idaho was $1,679,915.
Lost and (Jnaccountedfor (LAUF)4 Gas
Staff reviewed the Company's LAUF gas rate and compared it to previous years. The
Company reported a LAUF gas rate of 0.44%. Staff asked the Company to provide supporting
LAUF workpapers, a reconciliation of LAUF numbers used in the PGA Report, and numbers
reported to the Pipeline andHazardous Material Safety Administration ("PHMSA"). The
Company provided the following table showing a five-year view of LAUF gas PGA and PHMSA
rates. Staff notes that the five-year average is 0.07o/o.
4 Th" Ar.rican Gas Association describes unaccounted for natural gas in the utility system is defined as follows: At
a city gate. natural gas is transferred fiom an interstate or intrastate pipeline to a local natural gas utility. At that
monrent, some utilities measure the volume of gas using highly sophisticated technology that can quickly and precisely
take into account a variety'of 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-fbr -qas by regulators. who build a fbrm of reimbursement for this gas into the utility's rate
structure.
7STAFF COMMENTS AUGUST I7,2O2I
Table No. 3: LAUF Rates and Reconciliation
SUMMARY OF CUSTOMER IMPACT (Deferred Balance Credit and PGA)
On July 2,2021, the Company filed two Applications: (l) the annual PGA, Case No.
AVU-G-2I-04; and (2) Defened Balance Credit, Case No. AVU-G-21-03. If the Commission
approves both Applications, the net effect on natural gas revenue is an increase of approximately
$7.1M or l0.6Yo as shown in Table No. 4.
Table No. 4 - PGA and Deferred Balances Credit Summarv
5 PUIT,TSR CALCULATION PART G - PERCENT OF UNACCOUNTED FOR GAS "UNACCOUNICd fOr gAS'' iS gAS
lost; that is, gas that the operator cannot account for as usage or through appropriate adjustment. Adjustments are
appropriately made for such factors as variations in temperature, pressure, meter-reading cycles, or heat content;
calculable losses from construction, purging, line breaks, etc., where specific data are available to allow reasonable
calculation or estimate; or other similar factors. State the amount of unaccounted for gas as a percent of total
consumption for the l2 months ending June 30 of the reporting year. [(Purchased gas + produced gas) minus
(customer use + company use + appropriate adjustments)] divided by (customer use + company use + appropriate
adjustments) times 100 equals percent unaccounted for.
8
Year Delivery Revenue Loss */-%of
Purchase
PGA
Report
PHMSA5
Report
2017 147,097,624 146,490,005 607,619 0.41 0.4r 0.4r
201 8 134,637,626 134,139,456 498,170 0.37 0.37 0.37
20t9 143,375,963 141,549,576 7,826,447 1.27 1.27 1.29
2020 155,715,413 158,836,712 (3,121,299)(r.e7)(1.e7)(t.e7)
2021 156,717,867 156,036,168 681,699 0.44 0.44 N/A
5 Year Average 147,508,899 147,410,371 98,527 0.07
Adjustment Revenue Impact $Revenue lmpact Vo
PGA $9.0M 13.5%
Deferred Balances Credit ($ I .eM)(2.e%)
Net Effect $7.1 10.6"h
STAFF COMMENTS AUGUST I7,2O2I
CUSTOMER COMMENTS, 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-G-21-04) and the Deferral Balances Credit
Filing (AVU-G-21-03). Staff reviewed the documents and determined that both meet the
requirements of Rule 125 of the Commission's Rules of Procedure,IDAPA 31.01.01.125.
The Commission set a comment deadline of August 17,2021. Because customer notices
were inserted into bills beginning July 8,2021, through August 5,2021, some customers in the last
billing cycle may not have adequate time to submit comments before the deadline. Customers
should 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 August 16,2021, the Commission had received four comments, which were all opposed to
raising rates.
STAFF RECOMMENDATIONS
After examining the Company's Application, natural gas purchases, and deferral activity
for the year, Staff recommends the Commission:
l. Approve the Company's proposed Tariff Schedule 150, including the proposed
WACOG of $0.20305 per therm and demand charge of $0.09243 per therm, for a
total of $0.29548 per therm;
2. Approve the Company's proposed Tariff Schedule 155, with the proposed
amortization rate of $0.01505 per therm;
3. Direct the Company to continue filing quarterly WACOG reports and monthly
deferred cost reports with the Commission on an ongoing basis; and
4. Accept late-filed comments from customers.
9STAFF COMMENTS AUGUST I7,2O2I
ResrBectfully submitted this tfuAuyof August 2A21,.
Attomoy General
Technical Staff: Kevin Keyt
Kathy Stsckton
Ttavis CulberBon
Curtis Thaden
i:umiso:€oemonUmrg2 1 Sjhke$sUtod oomm€nts
STA,FF COMMENTS 10 AUGUST I7,2O2T
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS ITth DAY OF AUGUST 2021,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. AVU-G-21.44, BY E.MAILING A COPY THEREOF, TO THE
FOLLOWING:
PATRICK EHRBAR
DIR OF REGULATORY AFFAIRS
AVISTA CORPORATION
PO BOX3727
SPoKANE WA99220-3727
E-MAIL : [e-mail]
avi stadockets @ avistacorp. com
DAVID J MEYER
VP & CHIEF COUNSEL
AVISTA CORPORATION
PO BOX3727
SPOKANE WA99220-3727
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE