20220908Comments.pdf

CLAIRE SHARP
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720.0074
(208) 334-03s7
IDAHO BAR NO. 8026
Street Address for Express Mail:
I 133I W CHINDEN BLVD, BLDG 8, SUITE 2OI-A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF INTERMOUNTAIN GAS
COMPANY'S APPLICATION FOR
AUTHORITY TO CHANGE ITS PRICES
CASE NO. INT-G.22-04
COMMENTS OF THE
COMMISSION STAFF
Staff of the Idaho Public Utilities Commission ("Staff'), by and through its attorney of
record, Claire Sharp, Deputy Attorney General, and submits the following comments.
BACKGROUND
On August l},2|2z,lntermountain Gas Company ("Company"), applied for authority to
change the WACOG to $0.39216 per therm, and implement new rate schedules that will reduce
the Company's annualized revenues by approximately $7.7 million or approximately 2.2yo,
effective October 1,2022. Application at2. If approved, the typical residential customer would
have a monthly decrease of $ 1.36 or 2.5o/o. 1d at News Release.
The Company's Purchased Gas Adjustment ("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
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ISTAFF COMMENTS SEPTEMBER8,2022
Company defers these costs into its PGA account and then passes them on to customers through
an increase or decrease in rates.
The Company's rates include a base-rate component and a gas-related cost component.
The base-rate component is intended to cover the Company's fixed costs to serve its customers;
for example, the Company's costs for equipment and facilities to provide service-and rarely
change. The Commission approved the Company's base rates in Order No. 33757, Case No.
INT-G-16-02. The Commission approved the Company's current temporary gas-related rates in
Case No. INT-G-22-02, Order No. 35479.
With this Application, the Company seeks to pass through to each of its customer classes
changes in gas-related costs resulting from: l) costs billed to the Company from firm
transportation providers;2) a decrease in the Company's Weighted Average Cost of Gas
("WACOG"); 3) an updated customer allocation of gas-related costs pursuant to the Company's
PGA; 4) the inclusion of temporary surcharges and credits for one year related to natural gas
purchases and interstate transportation costs from the Company's deferred gas cost accounts; 5)
benefits resulting from the Company's management of its storage and firm capacity rights on
various pipeline systems; 6) benefits associated with the sale of liquefied natural gas from the
Company's Nampa, Idaho facility; 7) the recovery of deferred in-person customer payment fees;
and 8) a refund of over-collected Residential Energy Efficiency funds. The Company also seeks
to eliminate the temporary surcharges and credits included in its current prices during the past 12
months, pursuant to Case No. INT-G-21-04. If approved, these changes would result in a price
decrease to all of the Company's customers. The proposed changes to the rates will decrease the
Company's annualized revenues by about $7.7 million but will not impact earnings.
STAFF ANALYSIS
Staff examined the Company's Application, workpapers, and exhibits for this case and
confirmed: l) the PGA proposal would not affect the Company's earnings;2) the deferred costs
are prudently incurred, and properly calculated; and 3) the Company's WACOG request is
reasonable. Staff recommends that the Company's Application be approved.
2STAFF COMMENTS SEPTEMBER 8,2022
Table No. I summarizes the impact of the proposed changes on customer classes.
Table No. 1: Pronosed Chanse bv Customer Class
Change in Average Average AverageClass Change in ' Price
Customer Class: Revenue $/Therm Chanse $/Therm
RS Residential $(5,836,881) $(0.02152) -2.54% $0.82633
GS-l General Service $(1,796,935) $(0.01363) -1.76% $0.75930
LV-l Large Volume $ (23,31l) $(0.00188) -0.33% $0.56196
T-3 Transportation Volumetric $ (25,543) $(0.00045) -4.14% $0.01043
T-4 Transportation Volumetric $ - $ 0.00% $0.01356
T-4 Transportation Demand Charge$ (25.159) $(0.00014) -0.56% $0.28032TOTAr S(7.707,824) S(0.00o87) -2.210 S0.4358o
Overall, the Company's proposal decreases annual revenue by approximately $7.7
million which is detailed in Table No. 2 below.
Table No.2: Proposed Change to Annual Revenue
J
Deferrals:
Removal of INT-G-21-04 Temporary Credits and Charges
Additional INT-G-20-05 Temporary Credits and Charges
Fixed Deferred Gas Costs
Variable Deferred Gas Costs
Lost and Unaccounted for Gas
LNG Sales Credit
In-Person Payment Fees Deferral
Residential Energy Efficiency Credit
Total Additional Temporary Credits and Surcharges
Total Deferrals
Fixed Cost Changes:
NWP Full Rate Reservation
NWP Discounted Reservation
Upstream Full Rate
Upstream Discounted
SGS-2F and LS-2F
Other Storage Costs
Total Fixed Cost Changes
Changes in WACOG
Reallocation and True-Up of Fixed Costs
Total Base Rate Price Changes
$(14,054,612)
22,075,600
(1,222,513)
(221,993)
70,370
(.4"8s0.000)
$ (158,420)
1,254,463
818,976
$4,255,584
1,796,852
$ 6,052,436
$ (13,755,022)
$ 6,052,436
$G702-586)$ srAt
$ 1,915,019
$ (13,249,234)
$ (2.420.807)
Total Deferral and Price Changes
Total Annual Revenue Change
Differences due to roundins
STAFF COMMENTS SEPTEMBER8,2022
The Company eliminated $14,054,612intemporary credits and surcharges that were part
of last year's PGA, Case No. INT-G-2I-04. The proposed temporary credits and surcharges in
this Application adds $1,796,852 in charges. This amount consists of in-person payment fee
deferral, market segmentation and capacity release revenues, interest, per therm amortization of
deferrals, and over collections from last year's PGA. Additionally, a credit for off-system sales
of Liquefied Natural Gas, and a Residential Energy Efficiency Creditr are included in this
request.
Weighted Average Cost of Gas - WACOG
The WACOG is the Company's average variable cost to buy and transport natural gas to
meet customer estimated annual requirements. The WACOG components include the volumetric
interstate transportation rate, the city gate costs, the IGI Resources administrative fees, and the
Gas Technology Institute (GTI) charges. The WACOG does not include fixed capacity costs for
interstate transportation, liquid storage, and underground storage. The proposed WACOG of
$0.39216 per therm is a decrease of 7 .5%o from the current WACOG of $0.42405 per therm.
This decrease in the WACOG represents an approximate $13.2 million decrease to the
Company's billed revenues. Chart No. I below shows the Company's historical WACOG price
trend.
Chart No. 1: Weiehted Averase Cost of Gas (Per Therm)
I See Case No. INT-G-22-05. This is a onetime residential-only refund.
4
lcc PGA WAcoG (S/Therml
E
o-trF
v!
0.450
0.400
0.3s0
0.300
0.250
0.200
0.r50
0.100
0.050
0.000
t'\r
-.-
s0.373
20L3
so.39s
2074
So.sze
20L5
5o.zgt
20L6
So.zoo
2077Year
$o.zzt
2018
s0.209
20L9
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2020
t;
$0.260 50.424 i So.sgz .
I
2O2L t2022*i 20222022* Order No. 35479
STAFF COMMENTS SEPTEMBER8,2022
Market Fundamentals & Price Analysis
Although the Company hedges or stores much of its forecasted supply at fixed prices,
market fluctuations can impact the WACOG. Staff analyzedthe Company's projected cost to
purchase natural gas by comparing the Company's price projection to forecasts from several
national and regional organizations, including the Energy [nformation Administration ("EIA")2
and the Northwest Gas Association ("NWGA"). Staff believes the Company's projected natural
gas costs are reasonable.
The EIA Short-Term Energy Natural Gas Outlook3 states:
In July, the Henry Hub spot price averaged $7.28 per million British thermal
units (MMBtu), down from $7.7OlMMBtu in June and $8.I4lMMBtu in May.
Average natural gas prices fell over the last two months primarily because of
additional supply in the domestic market following the shutdown of the
Freeport LNG export terminal on June 8. However, prices increased by almost
50%o, from $5.73lMMBtu on July I to $8.37lMMBtu on July 29, because of
continued high demand for natural gas from the electric power sector. We
expect the Henry Hub price to average $7.54lMMBtu in the second half of 2022
and then fall to an average of $5.10/MMBtu in 2023 amid rising natural gas
production.
Risk Management
Staff examined how the Company manages price and risk given the Company's market
purchases, storage, and interstate transportation capacity to determine whether the Company
reasonably purchased natural gas to minimize risk to ratepayers. The Company's approach is
flexible, allowing it to opportunistically buy gas, manage storage, and utilize interstate
transportation capacity as market conditions change. Overall, Staff believes the Company's
practices associated with managing its resource portfolio provides reasonable price stability for
customers.
The Company fulfills its mainline requirement with hedges, spot market purchases,
underground storage, and liquified natural gas ("LNG") storage. Underground storage enables
the Company to purchase natural gas for the upcoming heating season during the summer when
prices are typically lower. When opportunities arise, the Company manages its interstate
2 EIA Natural Gas Weekly https:/iwr.l'rv.e ia. gov/natural gas/
3 EIA STEO link https:1/wwrv.eia.eov/outlooks/steo/repoftinatgas.php
5STAFF COMMENTS SEPTEMBER8,2022
transportation capacity, selling surplus capacity into the market. Table No. 3 shows the
Company's seasonal hedges over the last seven years.
Table No. 3: Hedeins Ratios
Purchasing
Staff analyzed the Company's purchasing practices confirming that the Company
reasonably adapted them to meet current market conditions. In recent years, about 30% of the
Company's total throughput is purchased at index or spot prices. This year, the Company
purchased more gas at index or spot prices to minimize locked-in gas at higher prices. Staff
believes the Company's hedging ratios complement current market conditions.
The Company continues to utilize index or spot purchases, allowing it to take advantage
of low prices for real-time needs, while hedging against upward price risk by purchasing gas
while prices are low and storing it for future consumption. The Company has locked-in the price
of about 57o/o of its gas purchases for 2022 by depositing it into storage. This amount is about
13% lower than last year.
Staff reviewed the Company's natural gas purchases during the PGA period by
examining a 7-month sample of invoices. Staff confirmed that the natural gas purchases
reconciled with the amount of natural gas purchases reported in the monthly deferral reports.
Natural Gas Underground Storage and Interstate Transportation
The Company delivers domestically produced natural gas to its city gates through
Northwest Pipeline. The Company also delivers natural gas from Canada by using pipeline
capacity on Gas Transmission Northwest (GTN), TransCanada's Foothills Pipeline system
(Foothills), and TransCanada's Alberta system known as Nova Gas Transmission (NOVA).
a % Locked-in gas includes storage volumes that are both hedged and index purchases.
6
% Locked-in Gas by PGA Yeara
2016 2017 201 8 20t9 2020 2021 2022
Non-Summer Months (Oct.-Mar.)82 80 77 17 74 67 66
Summer Months (Apr.-Sept.)55 49 49 82 72 46 28
Full Year 76 73 70 78 74 t0 57
STAFF COMMENTS SEPTEMBER8,2022
Permanent transportation and storage costs reflect a savings of $2.3 million for customers
as shown in Exhibit No. l, Line20, Column E. Normally, natural gas added to storage is
procured during the summer season when prices are typically lower than in winter. However,
prices have not been lower this summer. The Company has been purchasing storage as needed
to meet peak demand in the winter, but the Company is now using it as insurance of supply for
winter peak. Price curves into the fall may benefit the Company and allow them to purchase
some gas for storage to hedge against winter prices. The Company has also entered into various
fixed price agreements for portions of underground storage and other winter flowing supplies to
further stabilize prices.
Management of Pipeline Capacity
Staff reviewed the Company's procedures for maintaining and releasing pipeline capacity
and believes that the Company's capacity planning is reasonable. The Company holds excess
capacity in case of increased demand and mitigates the cost of this excess by selling it back into
the market, thus benefitting customers through the PGA.
ln last year's PGA filing, the Company included a $6.3 million credit to customers
embedded in its forecast. The Company's capacity release revenue for the current PGA is
forecasted to be $6.6 million which will be credited back to customers over the coming PGA
year. If capacity release revenues exceed the $6.6 million embedded in the forecast, customers
will receive an additional credit in the 2023 PGA. These credits are included in the Fixed
Deferred Gas Costs listed in Table No. 2. The Company's historical capacity releases are shown
below in Chart No. 2.
Chart No.2: Historical Canacity Releases
7
IGC H istorical Transportation Capacity Release
S8,ooo,ooo
s6,000,000
s4,000,000
S2,ooo,ooo
So
Series
20t2PGA 2013 PGA 2014 PGA 2015 PGA 2016 PGA 2OT7 PGA 2018 PGA 2019 PGA 2O2O PGA 2O2IPGA 2022PGA
L s3,726,26 s3,886,16 S3,940,oo S6,410,00 s5,3s1,oo s6,629,00S3,94o,oo S3,886,15 s3,940,00 Ss,4s3,oo 57,L2s,oo
STAFF COMMENTS SEPTEMBER8,2022
LNG Storage
In Order No. 32793, the Commission authorized the Company to sell excess LNG
capacity from its Nampa LNG facility to non-utility customers. Pursuant to that Order, the
Company provides a credit to ratepayers of 2.5 cents per gallon of LNG sold for costs related to
O&M expenses. The Company is required to share 50% of the total net margin from non-utility
sale of LNG with ratepayers, up to $1.5 million, and then 70Yo on any amounts greater than $1.5
million.
Historical LNG benefits to customers, including benefits in this PGA, are shown below in
Chart No. 3. As seen in the chart, the Company proposes to credit ratepayers $22L,993 for their
share of revenues for non-utility sale of LNG. LNG sales declined because the Nampa LNG
facility was offline for a significant portion of the year for maintenance and repairs. Staff
reviewed the Company's non-utility sales of LNG and verified that the credit to ratepayers has
been calculated correctly.
Chart No.3: LNG Sales Ratepaver Benefits
Lost and Unaccounted for Gas and Line Break Rate - LAUF
Lost and Unaccounted for ("LAUF") Gas is essentially the difference between the
volume of natural gas delivered to the distribution system at the city gate and volume of gas
billed to customers at the meter. During the period from the Company's 1985 General Rate Case
until conclusion of the 2016 General Rate Case, the Company recovered a portion of LAUF Gas
amounts through a $0.00182 per therm charge embedded in base rates. Any additional cost or
8
lGC Historical LNG Benefit
s1,200,000
s1,000,000
Ssoo,ooo
Sooo,om
s400,000
Szoo,ooo
so
Seriesl
2014 PGA 2015 PGA 2016 PGA
S236,80s
2OL7 PGA 2018 PGA 2019 PGA 2O2O PGA 2O2IPGA 2022PGA
54os,44r s689,367 S49s,418 5s29,44s 5t,r29,239 S1,oos,o60 57L7,972 $22t,993
-4.
-/\
STAFF COMMENTS SEPTEMBER8,2022
credit was administered annually in the PGA. In the 2016 General Rate Case, the embedded rate
of $0.00182 was removed resulting in recovery of LAUF Gas solely in the PGA.
This year, the Company's LAUF Gas rate is -0.6954% (found gas). The Company's
LAUF rate continues to be below the maximum allowable level of 0.85% specified in
Commission OrderNo.30649. The Company allocates LAUF Gas at 75Yoto core customers
(Residential and General Service) and25%o to industrial customers (Large Volume and
Transportation) through a per therm surcharge or credit. In this PGA, the total credit for LAUF
is $1,222,513 of which $91 1,260 is credited to core customers and $3 11,253 is credited to
industrial customers.
The Company charges a Line Break Rate to contractors or other parties who are
responsible for damage to the distribution system causing a gas leak. The Company proposes to
increase the Line Break Rate from the current rate of $0.42443 per therm to $0.55580 per therm.
The proposed Line Break Rate includes a $0.16364 Fixed-Cost Component (Transportation
Cost) per therm and a $0.39216 Variable-Cost Component (WACOG) per therm for a total of
$0.55580. Both Line Break Rate components are determined annually with the PGA filing.
Staff concludes that the Company calculated the proposed Line Break Rate consistent with Order
No. 33139.
Rate Case Expenses
In Order No. 33887, Case No INT-G-I7-05, the Commission authorized the Company to
establish a regulatory asset account to recover the external costs associated with the general rate
case, Case No. INT-G-16-02. These expenses totaled $378,614 and are to be amortized over five
years ($75,723 per year) through the annual PGA mechanism. During this deferral period, the
Company collected $79,243 which is $3,520 over the rate case amortization rate of $75,723.
Staff reviewed the amortization for the previous PGA period and confirmed that the amortization
was properly calculated and that the authorized amount for amortization is included in this PGA.
This is the last year that general rate case expenses will be included in the PGA.
Payment Fees Deferral
In Order No. 34099, Case No. INT-G- I 8-0 I , the Company was directed to create a
regulatory asset to capture costs associated with in-person customer pay station transactions
9STAFF COMMENTS SEPTEMBER8,2022
handled by Western Union. Furthermore, the Company was authorized to seek recovery of those
costs in the Company's PGA beginning in2019, until February I,2021, or until the Company
files a general rate case, whichever comes first. This authorization was extended in Order No.
35047, Case No. INT-G-21-02. As of June 30,2022, the balance of the total deferred in-person
payment fees was $72,542. This is composed of $53,190 for Residential Service (RS) customers
and $20,352 for General Service (GS-l) customers. Staff verified that this balance is correct.
Residential Energy Efficiency Credit
The Company has included a one-time $4,850,000 credit to the PGA from the over
funded Residential Energy Effrciency program. Staff recommended approval of the Company's
proposed credit in Case No. INT-G-22-05. Because this was collected from customer on a per
therm basis, it is appropriate to return this amount on a per therm basis through the PGA.
Quarterly Reports
In Order No. 34448, the Commission found that quarterly WACOG and monthly deferred
cost reports provide useful information, assist Staff with determining whether to audit earlier
than planned, and assess whether an interim filing might be needed. In its Application, the
Company requested that the Commission maintain the quarterly requirement of filing for the
Deferred Gas Cost Balance, LNG Sales Cost Benefit Analysis, and WACOG reports. The
Company stated that it is committed to notifring the Commission if an interim filing might be
needed. Staff believes quarterly reporting is reasonable given the Company's commitment to
notifr the Commission.
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 (INT-G-22-04) and the Residential Energy
Efficiency Charge (INT-G-22-05). 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 notice was included with bills mailed to customers beginning August II,2022, and ending
September 9,2022.
STAFF COMMENTS 10 SEPTEMBER 8,2022
The Commission set a comment deadline of September 8, 2022. Some customers in the
last billing cycles will not have received/and 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 Septemb er 7 , 2022, 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 Application, decreasing revenues by $7,702,586 as
shown in Table No. 2, and approve the proposed WACOG amount of $0.39216
per therm;
2. Approve the Company's proposed Tariff Rate Schedules RS, GS-I, IS-R, IS-C,
LV-I, T-3, and T-4 as filed with the Application;
3. Direct the Company to continue filing quarterly reports reflecting deferred gas
costs and WACOG projections;
4. Order the Company to file an adjustment to its PGA-related rates, if gas prices
significantly deviate from projections; and
5. Accept late-filed comments from customers.
f,Respectfully submitted this day of September 2022
@W
Claire Sharp
Deputy Attorney General
Technical Staff: Kevin Keyt
Cunis Thaden
Joseph Terry
Robin Maupin
Matt Suess
i: umisc/comments/intgg22.4cskkctjtrmms comments
STAFF COMMENTS l1 SEPTEMBER8,2022
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 8TH DAY OF SEPTEMBER 2022,
SERVED THE FOREGOING COMMENTS OF TIIE COMMISSION STAFF, IN
CASE NO. INT.G.22.O4, BY E-MAILING A COPY THEREOF, TO THE
FOLLOWING:
LORI BLATTNER
DIR _ REGULATORY AFFAIRS
INTERMOUNTAIN GAS CO
PO BOX 7608
BOISE ID 83707
E-MAIL: [e-mail]
PRESTON N CARTER
GIVENS PURSLEY LLP
60I W BANNOCK ST
BOISE ID 83702
E-MAIL : prestoncarter@ givenspursley.com
stephaniew@ g ivenspursley. com
CERTIFICATE OF SERVICE