20210910Comments.pdf

DAYN HARDIE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-007 4
[phone]
BAR NO. 9917
Street Address for Express Mail:
I I33 I W CHINDEN BLVD, BLDG 8, SUITE 20 I -A
BOISE, ID 83714
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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IN THE MATTER OF INTERMOUNTAIN GAS
COMPANY'S APPLICATION FOR
AUTHORITY TO UPDATE RATES TO
REFLECT PURCHASED GAS COST
ADJUSTMENTS
CASE NO. INT.G-2I.04
COMMENTS OF THE
COMMISSION STAFF
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STAFF OF the ldaho Public Utilities Commission, by and through its Attorney of
record, Dayn Hardie, Deputy Attomey General, submits the following comments.
BACKGROUND
On August 6,2021, lntermountain Gas Company ("Intermountain" or o'Company")
requested authority to place into effect on October I,2021, new rate schedules that would
increase its annualized revenuesby $24.2 million, or approximately 9.6%o.
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
infrequently change. The Commission approved the Company's current base rates in Order
No. 33757, Case No. INT-G-16-02.
ISTAFF COMMENTS SEPTEMBER IO,2021
The gas-related cost component of the Company's rates is at issue in this case.
Specifically the Company seeks to change its rates to pass through to customers changes in gas-
related costs resulting from: (1) costs billed to the Company from firm transportation providers
(including Northwest Pipeline LLC); (2) anincrease in Intermountain's Weighted Average Cost
of Gas ("WACOG"); (3) an updated customer allocation of gas-related costs pursuant to the
Company's Purchased Gas Cost Adjustment ("PGA") provision; (4) the inclusion of temporary
surcharges and credits for one year relating to natural gas purchases and interstate transportation
costs from Intermountain's deferred gas accounts; (5) benefits generated 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) a
portion of the costs accrued related to the Company's latest general rate case, Case No. INT-G-
16-02; and (8) the recovery of deferred in-person customer payment fees. The Company seeks to
eliminate the temporary surcharges and credits included in its current prices during the past 12
months under Case No. INT-G-20-05.
STAFF ANALYSIS
Staffexamined the Company's Application, workpapers, and exhibits for this case and
confirmed: (1) the PGA proposal would not affect the Company's earnings; (2) the deferred costs
are prudent and properly calculated; and (3) the Company's WACOG request is reasonable.
Staff recommends that the Company's Application be approved.
Table No. 1 summarizes the impact of the proposed changes on customer classes.
Table No. 1: Proposed Chanse by Customer Class
Change in Average Average Average
Class Change in o/" Price
Customer Class: Revenue $/Therm Chanse $/Therm
RS Residential
GS-l General Service
LV-l Large Volume
T-3 Transportation Volumetric
T-4 Transportation Volumetric
$15,112,739 $0.05639
$ 8,410,901 $0.06502$ 620,980 $0.05521$ (t2,253) $(o.ooo22)$s
9.01%
11.96%
ts.99%
-t.95%
0.00%
s0.68219
$0.60855
$0.40041
$0.01104
$0.01368
T-4 Transportation Demand Charee$ 31.690 $0.00197 0.70% $0.28189TOTAr $24.164.05
2STAFF COMMENTS SEPTEMBER IO,2O2I
Overall, the Company's proposal increases annual revenue by approximately $24.2
million which is detailed in Table No. 2 below.
Table No. 2: Proposed Change to Annual Revenue
The Company eliminated $12,333,136 in temporary credits and surcharges that were part
of last year's PGA, Case No. INT-G-20-05. The proposed temporary credits and surcharges in
this Application return $4,201,016 to customers. 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 true-up of the of benefits from the Tax Cuts and Jobs Act are
included in this request.
3
Deferrals:
Removal of INT-G-20-05 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
Deferred General Rate Case Costs
In-Person Payment Fees Deferral
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 Price Changes
$(12,333,1 36)
9,257,693
(546,602)
(717,972)
74,194
64.8t7
$13,288,766
$(4.201"016)
$ 9,087,750
$15,077,827
$24,165,577
$4J64,057
$____-1.520
$ (16,583)
98,1 l 5
133,477
(585,455)
3157
100)
$ (387,389)
$ 17,574,322
s (2.109.106)
Total Deferral and Price Changes
Total Annual Revenue Change
nifft"ences due to r ine
STAFF COMMENTS SEPTEMBER 10,2O2I
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 (GTD charges. The WACOG does not include fixed capacity costs for
interstate transportation, liquid storage, and underground storage. The Company's proposed
WACOG of $0.26000 per therm is an increase of 19.82Yofromthe prior 2020 WACOG of
$0.21699 per therm. This increase in the WACOG represents about $17.5 million increase to the
Company's billed revenues. Chart No. 1 below shows the Company's historical WACOG price
trend.
Chart No. 1: Weiehted Averase Cost of Gas (Per Therm)
IGC PGAWAcoG ($/Therm)
E
o.CF
<ti
0.4500
0.4000
0.3s00
0.3000
0.2s00
0.2000
0.1500
0.1000
0.0s00
0.0000
So.:ss s0.373 So.sss So.:za So.zsz jso.zeo jso.r, iso.ro, jso.r, iso.ruo
' 2OL7 I ZOra i ZOrS 2O2O i ZOZL20L220L320L420152016
Year
Market Fundamentals & Price Analysis
Although the Company hedges or stores much of its forecasted supply at fixed prices,
market fluctuations can impact the WACOG. Staffanalyzed the Company's projected cost to
purchase nafural gas by comparing the Company's price projection to forecasts from several
national and regional organizations, including the Energy Information Administration ("EIA")I
and the Northwest Gas Association ('NWGA"). Staff believes the Company's projected natural
I EIA Natural Gas Weekly https://www.eia. gov/natural gas/
4STAFF COMMENTS SEPTEMBER IO,2021
gas costs are reasonable. The EIA Short-Term Energy Natural Gas Outlook2 states:
In July, the natural gas spot price at Henry Hub averaged $3.84 per million
British thern-ral units (MMBtu), which is up from the June average of
$3.26lMMBtu. We expect the Henry Hub spot price will average
$3.71lMMBtu in 3Q21 and $3.42lMMBtu for all of 2021, which is up
from the 2020 averuge of $2.03/MMBtu. Higher natural gas prices this year
primarily reflect two factors: growth in liquefied natural gas (LNG) exports
and rising domestic natural gas consumption for sectors other than electric
power. 1n2022, we expect the Henry Hub price will average $3.08/MMBtu
amid rising U.S. 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, by allowing it to opportunistically buy gas, manage storage, and utilize interstate
transportation capacity as market conditions change. Overall, Staff believes the Company's
strategy and 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
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: Hedeine Ratios
2 EIA STEO link https:i/www.eia. gov/outlooks/steo/reoort/natgas.ph p
3 %, Locked-in gas includes storage volumes that are both hedged and index purchases.
5
% Locked-in Gas by PGA Yeat'
20ts 2016 2017 2018 20t9 2020 2021
Non-Summer Months (Oct.-Mar.)78 82 80 77 77 74 67
Summer Months (Apr.-Sept.)62 55 49 49 82 72 46
Full Year 74 76 l)70 78 74 70
STAFF COMMENTS SEPTEMBER 10,2021
Purchasing
Staff confirmed the Company's purchasing practices were reasonably adapted to meet
current market conditions. As in recent years, about 30% of the Company's total throughput is
purchased at index or spot 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 70%o of its gas purchases for 2021by depositing it into storage. This amount is about
4Yo 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 the natural gas purchases reconciled
with the amount of natural gas purchases reported in the monthly deferral reports.
Natural Gas Underground Storage and Interstote Transportqtion
The Company delivers domestically produced natural gas to its city gates through the
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).
Permanent transportation and storage costs reflect a decrease of $1,083,191, which is a
net reduction of $695,3 89 from the decrease of $3 87,3 89 in Case No. INT-G -20-05 as shown in
Exhibit No. 1, Line20 column, E. Because natural gas added to storage is procured during the
summer season when prices are typically lower than the winter, the Company's cost of storage
gas is typically lower than what could be procured in winter months. 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 the Company's capacity planning was prudently conducted. The Company holds
6STAFF COMMENTS SEPTEMBER 1O,2O2I
excess capacity for increased demand and mitigates the additional costs of this practice by selling
it back into the market, benefitting customers through the PGA.
In last year's PGA filing, the Company included a $6.4 million credit to customers
embedded in its forecast. The Company's capacity release revenue for the current PGA is
forecasted to be $6.3 million, which will be credited back to customers over the coming PGA
year. If capacity release revenues exceed the $6.3 million embedded in the forecast, customers
will receive an additional credit in the 2022PGA. These credits are included in the Fixed
Deferred Gas Costs listed in Table No. 2.
Chart No. 2: Historical Capacitv Releases
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. Further, the Company is required to share 50% of the total net margin from the
non-utility sale of LNG with ratepayers, up to $1.5 million, and then 70%o on any amounts
greater than $L5 million. The Company proposes to credit ratepayers $7l7,972 for revenues
earned from the non-utility sale of LNG. See Chart No. 3. Staff verified the Company's credit
to ratepayers for non-utility sales of LNG was calculated conectly.
7
IGC Historical Transportation Capacity Release
s16,000,000
S14,ooo,ooo
s12,000,000
Slo,ooo,ooo
s8,000,000
S6,ooo,ooo
S4,ooo,ooo
S2,ooo,ooo
So
Seriesl
2012 PGA
Sg,+s9,84
2016 PGA
S10,s11,3
2017 PGA
S8,o4o,oo
2018 PGA
Ss,4s3,oo
2019 PGA
S7,12s,00
2013 PGA 2014 PGA 2015 PGA
5L4,37r,4 iLL,546,2 Ss,25s,s3
2O2O PGA 2021 PGA
s6,410,0o S6,3s1,oo
STAFF COMMENTS SEPTEMBER IO,2021
IGC Historical LNG Benefit
S1,2oo,ooo
s1,000,000
s800,000
Sooo,ooo
S4oo,ooo
s200,000
So 2014 PGA
Seriesl 5405,441
2015 PGA
s689,367
2016 PGA
S236,80s
2OL7 PGA
S49s,418
2018 PGA
$szg,++s
2019 PGA
5r,129,239
2O2O PGA
S1,oos,060
202tPGA
57L7,972
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
credit was administered annually in the PGA. In the 2016 General Rate Case, the embedded rate
of $0.00182 per therm was removed resulting in recovery of LAUF Gas solely in the PGA.
This year, the Company's LAUF Gas rate is -0.2096% (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 the core customers
(Residential and General Service) and25%o to the industrial customers (Large Volume and
Transportation) through a per therm surcharge or credit. In this PGA, the total credit for LAUF
is $547,588 of which $410,691 is credited to core customers and $136,897 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 $0.39010 per therm to $0.42443 per therm.
The proposed Line Break Rate includes a $0.16443 Fixed-Cost Component (Transportation
Cost) per therm and a $0.26000 Variable-Cost Component (WACOG) per therm for a total of
$0.42443. Both components of the Line Break Rate are determined annually with the PGA
8STAFF COMMENTS SEPTEMBER IO,2O2I
filing. Staff believes the Company's calculation of the proposed Line Break Rate is consistent
with Order No. 33139.
Rate Case Expenses
In Order No. 33887, Case No. INT-G-17-05, 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 $74,194-$1,529 under the authorizedrate case amortization rate of
$75,723. Staff verified the annual calculations and confirmed that the expenses were properly
amortized, and this year's recovery amount was properly calculated.
Payment Fees Deferral
In Order No. 34099, Case No. INT-G-18-01, the Company was directed to create a
regulatory asset to capture the costs associated with in-person customer pay station transactions
handled by Western Union. Further, the Company was authorized to seek recovery of those
costs in the Company's PGA beginning in 2019-until February 1,2021, or until the Company
files its next general rate case, whichever comes first. This authorization was extended in Order
No. 35047, Case No. INT-G-21-02. As of June 30,2021, the balance of the total deferred In-
Person payment fees was $64,817. This is composed of $46,285 for Residential Service (RS)
customers and $18,532 for General Service (GS-l) customers. Staff verified that this balance is
correct.
Quarterly Reports
ln Order No. 34448, the Commission found that quarterly WACOG and monthly defened
cost reports provide useful information, assist Staff with determining whether to audit earlier
than planned, and 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 notifuing the Commission if an interim filing might be needed. Staff
9STAFF COMMENTS SEPTEMBER IO,2O21
believes quarterly reporting is reasonable given the Company's commitment to notify the
Commission.
CUSTOMER NOTICE AND PRESS RELEASE
The Company's press release and customer notice were included with its Application.
Staff reviewed thq 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 ll,202l and ending September 9,2021.
The Commission set a comment deadline of September 10, 2021. 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 September 9,2021, one comment had been filed in opposition
to the Company's proposed increase.
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 Application, increasing revenues by $24.2 million as
shown in Table No. 2, and approve the proposed WACOG amount of $0.26000
per therm;
2. Approve the Company's proposed Tariff Rate Schedules RS, GS-l, 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.
STAFF COMMENTS 10 SEPTEMBER 10,2021
uftRespeotfully submitted this day of September 2021.
Deputy Attomey General
Technie-al Staff: Kevin Keyt
Johan Kalala-Kasanda
Curtis Thaden
i:umisd'commenu/ing2 t.4dhk*jkct commmft
STAFF COMMENTS 1l SEPTEMBER 10,2021
CERTIFICATE OF SERYICE
I HEREBY CERTIFY THAT I HAVE THIS IOfl' DAY OF SEPTEMBER 2021,
SERVED THE FOREGOING COMMENTS OF TI{E COMMISSION STAFF, IN
CASE NO. INT.G-21-04, 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
hannonywri ght@ eivenspursley.com
b/lb,-
SECRETRY
CERTIFICATE OF SERVICE