20190913Comments.pdf

MATT HUNTER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BARNO. 10655
IN THE MATTER OT'THE APPLICATION OF
INTERMOUNTAIN GAS COMPANY FOR
AUTHORTTY TO CHANGE ITS PRTCES (2019
PURCHASED GAS ADJUSTMENT).
Street Address for Express Mail
472W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
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CASE NO. INT.G.19.O6
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
attorney of record, Matt Hunter, Deputy Attorney General, and in response to the Notice of
Application and Notice of Modified Procedure issued in Order No. 34429 on August 28,2019, in
Case No. INT-G-19-06, submits the following comments. The Company proposes that the new
rates take effect October 1,2019. The changes to the rates will decrease the Company's
annualized revenues by approximately $l.l million, but will not impact earnings. Id. at2.
BACKGROUND
On August 15,2019,Intermountain Gas Company ("Intermountain or "the Company")
applied to the Commission for authority to change its rates, effective October 1,2019,to reflect
changes in gas-related costs. Application at 2.
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
ISTAFF COMMENTS SEPTEMBER 13,2019
historically rarely changes. The current base rates were approved in Order No. 33757, Case No.
rNT-G-16-02.
The gas-related cost component of the Company's rates is at issue here. Specifically, the
Company seeks to change its rates to pass through to customers changes in gas-related costs
resulting from: (l) costs billed to the Company from firm transportation providers (including
Northwest Pipeline LLC); (2) replacement of long-term segmented pipeline capacity; (3) a
decrease in the Company's Weighted Average Cost of Gas (WACOG); (4) an updated customer
allocation of gas-related costs under the Company's Purchased Gas Cost Adjustment (PGA)
provision; (5) the inclusion of temporary surcharges and credits for one year relating to natural
gas purchases and interstate transportation costs from the Company's deferred gas cost accounts;
(6) benefits resulting from the Company's management of its storage and firm capacity rights on
various pipeline systems; (7) benefits from the sale of LNG; (8) a portion of costs accrued in
case INT-G-16-02; and (9) recovery of deferred customer payment fees. Id. at 4. 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-18-02.
If approved, the Company's proposal would decrease the average residential customer's
rates by 0.78% or $0.29 per month, decrease rates for Schedule T-3 (lnterruptible Distribution
Transportation Service) customers by 0.15Yo, and decrease the demand charge rate for Schedule
T-4 (Firm Distribution Transportation Service) customers by 0.94%. The proposal would
increase rates for Schedule GS-l (General Service) customers by 0.l6Yo, and increase rates for
Schedule LV-l (Large Volume) customers by 0.10%.
STAFF ANALYSIS
Staff examined the Company's Application, workpapers, and exhibits for this case and
believes the PGA proposal would not impact the Company's earnings, that the deferred costs are
prudent and properly calculated, and that the Company's WACOG request is reasonable. Staff
recommends that the Company's Application be approved.
Table I summarizes the impact of the Application's proposed changes on customer
classes.
2STAFF COMMENTS SEPTEMBER 13,20I9
Table 1: Summary of proposed changes on customer classes
Proposed Proposed
Change in Average
Class Change in
Customer Class: Revenue $/Therm
Proposed
Average
o//o
Change
Proposed
Average
Price
$/Therm
RS Residential $(1,124,106) $(0.00466) -0.78% $0.58990
GS-l General Service $104,800 $0.00085 0.16% $0.51872
LV-l Large Volume $2,813 $0.00032 0.10% 9032765
T-3 Transportation $(675) $(0.00002) -0.15% $0.01334
T-4 Transportation (Demand Only) $(47.029) $(0.00270) -0.94% $0.28469TOTAL Sfl.064.197
The overall effect of the Company's proposed changes is a decrease in annual revenues
of approximately $l.l million. The decrease of $1.1 million is comprised of the following items
detailed in Table 2 below.
Table 2: Proposed Changes to Annual Revenue
Deferrals:
Removal of INT-G-I8-02 Temporary Credits and Charges
Additional INT-G-18-02 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
True-Ups of Prior Year Deferrals
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
Other Storage Costs
Total Fixed Cost Changes
Changes in WACOG
Reallocation and True-Up of Fixed Costs
Total WACOG and True-Up Changes
Total Annual Revenue Change
Total Company Proposed Revenue Change
$(24,967,380)
4,557,004
171,054
(1,129,239)
75,723
213,183
93.2rr
$3,536
1,053,477
(53,486)
556,459
13.535
$1,573,521
$(6,794,231)
$(3.638.36s)
$28,780,148
s(.20.986.444\
$7,793,704
$(8.859.075)
$(1.065.321)
$(1.064.197)t
I The Annual Revenue Change calculated in Table 2 is $ I ,174 different than the Company proposed revenue
change. This difference is attributed to rounding differences that occur when the per therm rates are multiplied by
the forecasted normalized gas throughput.
aJSTAFF COMMENTS SEPTEMBER 13,2019
The Company eliminated temporary credits and surcharges of $28,780,148 that were part
of last year's PGA, Case No. INT-G-18-02. The temporary credits and surcharges proposed for
the current PGA case total $20,986,444 in the rebate direction. These consist of in-person
payment fees deferral, market segmentation and capacity release revenues, interest, and 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 over refunding of benehts
from the Tax Cuts and Jobs Act are included in this request. The Company included a fixed-cost
collection adjustment of $1,573,521 to customers pursuant to the provisions of its PGA tarifl
which provides that proposed prices will be adjusted for the updated customer class sales
volumes and purchased gas cost allocations.
Weighted Average Cost of Gas (WACOG)
The WACOG is the Company's average variable cost to buy and transport gas to satisfy
its customers' estimated annual gas requirements. The WACOG includes the volumetric
interstate transportation rate, city gate costs, IGI Resources administrative fees, and Gas
Technology Institute (GTI) charges. It does not include fixed capacity costs for interstate
transportation, liquid storage, and underground storage. The WACOG proposed price is
$0.20904 per therm, which is an 8olo decrease from the WACOG of $0.22724 per therm
established in the 2018 PGA filing and currently included in rates. The proposed decrease in the
WACOG represents an approximate $6.8 million decrease in the Company's billed revenues.
Chart I shows the Company's historical WACOG and illustrates how the cost of natural gas has
continued to trend downward.
4STAFF COMMENTS SEPTEMBER 13,2019
Chart 1: Weighted Average Cost of Gas (Per Therm)
tcc PGA v\rAcoc ($,/Therrn)
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Year
Market Fundamentals & Price Analysis
Although the Company has hedged or stored most of its forecasted throughput at fixed
prices, market fluctuations can impact the WACOG. Staff thus analyzed the Company's
projected cost to purchase natural gas. Staff compared the Company's forecast to forecasts from
national and regional organizations, including the Energy Information Administration ("EIA")
and the Northwest Gas Association ("NWGA"). Staff believes the Company's projected gas
costs are reasonable.
Risk Management
Staff scrutinized 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 gas and minimized risk to customers. The Company's approach is
flexible, which allows it to opportunistically buy gas, manage storage, and utilize interstate
transportation capacity as market conditions change. Overall, the Company's strategy and
practices associated with managing its resource portfolio provide price stability for customers.
The Company fulfills its mainline requirement with hedges, spot market purchases,
underground storage, and LNG storage. Underground storage enables the Company to purchase
gas for the upcoming heating season during the summer when natural gas prices are typically
lower. When opportunities are present, the Company manages its interstate transportation
capacity, selling surplus in the market.
5STAFF COMMENTS SEPTEMBER 13,2019
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Purchasing
Staff analyzedthe Company's purchasing practices to determine if the Company
reasonably adapted them to meet current market conditions. Similar to last year, about 22Yo of
the Company's total throughput is purchased at index or spot prices. Staff believes the
Company's hedging ratios complement current market conditions, particularly since natural gas
prices are at historical lows.
During the 2019 PGA year, the Company essentially locked-in2 gas purchases of ab.-rut
78%, which is slightly higher than last year. This year the Company locked-in a higher
percentage during summer months due to low prices and availability of gas. Table 3 shows the
Company's seasonal hedges over the last seven years.
Table 3: Hedging Ratios:
Natural Gas Underground Storage and Interstate Transportation
Permanent transportation and storage costs reflect a net increase totaling $10,200 relative
to costs in Case No. INT-G-18-02. According to the Company, its management of storage assets
benefits customers. Management of the Company's storage assets at Northwest Pipeline's
Jackson Prairie and Questar's Clay Basin result in $1.8 million savings. Because gas added to
storage is typically procured during the summer season when prices are typically lower than
during 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.
The Company delivers domestically produced natural gas to its city gates through
Northwest Pipeline. The Company also delivers natural gas from Canada by using capacity on
2 o/o Locked-in gas includes storage volumes that are both hedged and index purchases
3 Id.
6
% Locked-in Gas by PGA Year3
2013 2014 2015 2016 2017 201 8 2019
Non-Summer Months (Oct.-Mar.)79 74 78 82 80 77 77
Summer Months (Apr.-Sept.)48 63 62 55 49 49 82
Full Year l1 72 74 76 73 70 78
STAFF COMMENTS SEPTEMBER 13,2019
Gas Transmission Northwest (GTN), TransCanada's Foothills Pipeline system (Foothills), and
TransCanada's Alberta system known as Nova Gas Transmission (NOVA). The cost of gas
from upstream transportation providers increased by $556,459 (see Work Paper #2,line 9). This
change is primarily driven by increases in both annual therms and prices.
Management of Pipeline Capacity
Staff analyzed the procedures for maintaining and releasing pipeline capacity, and
believes that the Company's capacity planning is prudent at this time. The Northwest Pipeline is
fully subscribed and additional capacity may not be available when needed as identified in the
Integrated Resource Plan. Therefore, the Company holds excess capacity in order to be
prudently prepared for future growth. The Company mitigates the cost of this excess capacity by
releasing it on the market and passing the revenues gained by selling excess capacity to
customers through the PGA.
In last year's PGA filing, the Company included a $5.45 million credit to customers
embedded in its forecast. The Company's capacity release revenue for the current PGA is
forecasted to be $7.1 million, which will be credited back to customers over the coming PGA
year. If capacity release revenues exceed the $7.1 million embedded in the forecast, customers
will receive an additional credit in the 2020 PGA. These credits are included in the Fixed
Deferred Gas Costs listed in Table 2.
LNG Storage
In Order No. 32793, the Commission authorized the Company to sell LNG from its
excess capacity at the Nampa LNG facility to non-utility customers. Pursuant to that Order, the
Company provides a credit to ratepayers of 2.5 cents per every gallon of LNG sold for O&M
related expenses. Additionally, 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 70Yo on any
amounts greater than $1.5 million. In this Application, the Company proposes to credit
ratepayers $1,129,239 for their share of the revenues from the non-utility sale of LNG. Staff
reviewed the Company's non-utility sales of LNG, and verified that the credit to ratepayers has
been calculated correctly.
Staff reviewed the capital project deferral as well as the process for vetting projects to be
funded by that deferral and agrees that the deferral is being recorded properly and that the vetting
7STAFF COMMENTS SEPTEMBE,R 13,20I9
process is effective in ensuring that the capital projects funded by the deferral balance are for
repairs and maintenance likely impacted by the additional use of the LNG facility for non-utility
sales. In 2017 there was only one project partially funded from the deferral: a paving project for
a new asphalt road. Most of the additional traffic on the road is due to non-utility sales. Staff
agrees that this project was a proper use of the capital project defenal.
Lost and Unaccounted for Gas and Line Break Rate
Lost and Unaccounted for Gas (LAUF) is the difference between the volumes 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 was removed resulting in recovery of the LAUF solely in the PGA.
This year, the Company's estimated LAUF Gas rate of 0.03l2oh is below the maximum
allowable level 0.85% specified in Commission Order No. 30649. The Company allocates
LAUF Gas credits 75ohto the core customers (Residential and General Service) and25o/o to the
industrial customers (Large Volume and Transportation) through a per therm credit.
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 current (2018 PGA)
Line Break Rate is $0.41625 per therm. The Company proposes to decrease the Line Break Rate
from $0.41625 per therm to $0.38991 per therm. The proposed Line Break Rate includes a
$0.18087 Fixed-Cost Component (Transportation Cost) per therm and a $0.20904 Variable-Cost
Component (WACOG) per therm for a total of $0.38991. Both components of the Line Break
Rate are determined annually with the PGA filing. Staff concluded that the Company calculated
the proposed Line Break Rate consistent with Order No. 33139.
True-Up of Deferred Tax Liability
In Order No. 34073, the Commission approved a Settlement Stipulation that reduced the
Company's rates to account for the benefits of the Tax Cuts and Jobs Act. Additionally, the
stipulation required the Company to record on its books a regulatory liability for the benefits of
the TCJA from January 1,2018 through May 3 1,2018 and to return that deferred liability to
8STAFF COMMENTS SEPTEMBER 13,2019
customers in the 2018 PGA. In last year's PGA, the Company proposed and the Commission
approved the return of $2,731,841 to customers. Because loads were higher than expected, the
Company over-refunded the benefit, and is now requesting to true-up the amounts by collecting
$217,492 in the upcoming PGA year. Staff audited and confirmed that the Company over-
credited customers the benefits from the Tax Cuts and Jobs Act of 2017 (TCJA), and the
amounts were properly accrued and reported in this filing. This amount is included with other
true-ups of prior year deferrals in Table 2 above.
Rate Case Expenses
Previously, the Commission found that the Company demonstrated the prudency of
$378,614 in extemal rate case expenses, and an annual PGA recovery over five years ($75,723
per year) is just and reasonable. Staff confirmed that the annual recovery of the rate case
expenses authorized in the previous PGA were properly amortized and that this year's recovery
amount was properly calculated and recorded in this filing.
Payment Fees Deferral
Pursuant to Commission Order No. 34099, Case No.INT-G-18-01, the Company was
directed to defer and later collect through the PGA the fees associated with In-Person Customer
Payments at third party vendors. As of June 30,2019, the balance of the total deferred In-Person
payment fees amounted to $93,21 l. Staff had the opportunity to verify this balance and
confirmed that this is correct.
CUSTOMER NOTICE AND PRESS RELEASE
The Company's press release and customer notice were included with its Application.
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, or will be, included
with bills mailed to customers beginning August 19,2019, and ending September 16,2019.
For this case, the Commission set a comment deadline of September 13, 2019. Because
the last customer notices will not be inserted in bills until September 16, and the final comment
date is September 13, some customers in the last billing cycles will not have received their
notices 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
9STAFF COMMENTS SEPTEMBER I3,2019
recommends that the Commission accept late-hled comments from customers. As of
September 12,2019, no customer comments had been filed.
STAFF RECOMMENDATIONS
Staff recommends the Commission approve a decrease in revenues of $1,064,197 as
calculated in Table 2. Staff also recommends the Commission approve the Company's proposed
WACOG of $0.20904 per therm and approve tariffs as filed. Staff encourages the Company to
return to the Commission if gas prices deviate from projections significantly. Additionally, Staff
recommends the Commission order the Company to continue filing quarterly updates reflecting
the deferred gas costs and WACOG projections.
Respectfully submitted this ilil dayof September 2org.
Hunter
Deputy Attorney General
Technical Staff: Johan Kalala-Kasanda
Jolene Bossard
Kevin Keyt
STAFF COMMENTS 10 SEPTEMBER 13,2019
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS l3th DAY OF SEPTEMBER 2019,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT-G-I9-06, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
LORI BLATTNER
DIR _ REGULATORY AFFAIRS
INTERMOLINTAIN GAS CO
PO BOX 7608
BOISE ID 83707
E-MAIL: [e-mail]
PRESTON N CARTER
GIVENS PURSLEY LLP
601 W BANNOCK ST
BOISE ID 83702
E-MAIL: [e-mail]
kendrah@ givenspursley. com
a
CERTIFICATE OF SERVICE