20180918Comments.pdf

BRANDON KARPEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
(208) 334-03s7
BAR NO. 7956
RECEIVED
?HE SIP lB Pt{ l: 28
i;1;i8u'o*
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF
INTERMOUNTAIN GAS COMPANY FOR
AUTHORITY TO CHANGE ITS PRICES.
CASE NO. INT-G.I8-02
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
attomey of record, Brandon Karpen, Deputy Attorney General, and in response to the Notice of
Application and Notice of Modified Procedure, OrderNo. 34137, issued on September 4,2018,
submits the following comments.
BACKGROUND
On August I0,2018, Intermountain Gas Company ("Intermountain or "the Company")
applied to the Commission for authority to change its rates, effective October 1,2018, 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 rarely
change. The current base rates were approved in Order No. 33887, Case No. INT-G-17-05. See
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1STAFF COMMENTS SEPTEMBER 18,2018
The gas-related cost component of the Company's rates is at issue here. Specifically,
with this Application, the Company seeks to change its rates resulting from: (1) costs billed to
the Company from firm transportation providers (including Northwest Pipeline LLC); (2) a
decrease in the Company's Weighted Average Cost of Gas (WACOG); (3) an updated customer
allocation of gas-related costs under 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 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) a portion of the costs accrued related to the Company's general rate
case; and (7) customer benefits generated by changes to the federal and state income tax codes.
Id. at3-4. 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-17-05. Id.
The changes will decrease rates for the Company's Residential (RS), General Service
(GS-1), and Large Volume (LV-1) customers, and increase rates for its Transportation (T-3 and
T-4) customers. Id. at 4. The current gas-related cost component of the Company's rates was
approved in Order No. 33887, Case No. INT-G-17-05. See Id. The Company proposes to pass
through to customers gas-related cost changes that would decrease the average bill of residential
customers by $a.I2lmonth (10%) and commercial customers by $21.89/month (l1.9%). The
Company proposes that the new rates take effect October 1,2018. The Company's annualized
revenues will decrease by approximately $24.5 million, but will not impact earnings. Id. at2.
STAFF ANALYSIS
Staff examined the Company's Application, workpapers, and exhibits for this case and
believes the PGA proposal would not impact earnings, that the deferred costs are prudent and
properly calculated, and that the Company's WACOG request is reasonable. Staff thus
recommends that the Company's Application be approved.
Table I summarizes the impact of the Application's proposed changes on customer
classes.
STAFF COMMENTS SEPTEMBER 18,20182
Table 1: Summary of proposed changes on customer classes
Proposed Proposed Proposed Proposed
Change in Average Average Average
Class Change in oh Price
Customer Class: Revenue $/Therm Change $/Therm
RS Residential $(15,632,398) $(0.06675) -10.00% $0.60080
GS-l General Service $ (8,539,654) $(0.07049) -11.9% $0.52163
LV-l Large Volume $ (505,240) $(0.06852) -17.25% $0.32868
T-3 Transportation $ 36,155 $ 0.00083 6.84% $0.01297
TOTAL $(24.529.33
The overall effect of the Company's proposed changes is a decrease in annual revenues
of approximately 524.5 million. The decrease is comprised of the following items detailed in
Table 2 below.
Table 2: Proposed Changes to Annual Revenue
Deferrals:
Removal of INT-G-I7-05 Temporary Credits and Charge
Additional INT-G-17-05 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
Tax Reform Deferral
Total Additional Temporary Credits and Surcharges
Total Deferrals
Fixed Cost Changes:
NWP Full Rate Reservation
NWP Discounted Reservation
Upstream Full Rate
Upstream Discounted
Storage Capacity Fixed 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
J
$20,840,697
$(20,553,645)
(5,040,072)
786,421
(529,445)
66,986
(2,731,841)
$(.28.002.226\
$ (7,161,529)
$(619,134)
(44,126)
2,913,851
(1,598,162)
(31,648)
$620,781
$(1 1,955,049)
$(6,034,110)
$(17,368,378)
x24,529,9u)
STAFF COMMENTS SEPTEMBER I8,20I8
The Company eliminated temporary credits and surcharges of $20,840,697, that were part
of last year's PGA, Case No. INT-G-17-05. The temporary credits and surcharges proposed for
the current PGA case total $28,002,226 in the rebate direction. These consist of 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 benefits from the Tax Cuts and Jobs Act passed earlier this year, along with
surcharges for expenses associated with the Company's general rate case and Lost and
Unaccounted for Gas are included in the request. The Company included a fixed-cost collection
adjustment that credits $6,034,1 10 back to customers pursuant to the provisions of its PGA tariff,
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
$0.22724 per therm which is a 12.7o/o decrease from the WACOG of $0.26020 per therm
established in the 2017 PGA. The proposed decrease in the WACOG represents an approximate
$l 1.9 million decrease in the Company's billed revenues. Chart I shows the Company's
historical WACOG and illustrates how the cost of natural gas has continued to trend downward
since its peak in 2008.
STAFF COMMENTS SEPTEMBER 18,20184
lcc WAC0G {$/rherm}
fr
o
.ua
0.9000
0.8000
0.7000
0.6000
0.5000
0.4000
0.3000
0"2000
0.1000
0.0000
1
$0.785 $0.49{)$0.4e?$o.as:l $0.335
201 I
Year
$0.373 $o.3es $0,328 $0.297 $0.260 $0.227
2m8 200$2010 2011 2013 ?014 2fil5 t016 ?017 2018
Chart 1: Weighted Average Cost of Gas (Per Therm)
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 ratepayers. 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.
5STAFF COMMENTS SEPTEMBER 18,20I8
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.
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 30Yo of
the Company's total throughput is purchased at index or spot prices. The Company's hedged
supply is slightly lower than last year (49Yo) at 45Yo of total throughput. Staff believes the
Company's hedging ratio adjustments complement current market conditions, particularly since
natural gas prices are at historical lows.
The Company continues to use index or spot purchases, allowing it to react to upward
price risk. Including the Company's storage gas, about 70%o is essentially locked-in gas which is
slightly lower than last year. Since natural gas prices typically decline following non-summer
months it could be economically advantageous to have a lower percentage locked-in during the
summer months. Table 3 shows the Company's seasonal locked-in ratios over the last six years.
Table 3: Seasonal Locked-in Ratiosl:
Natural Gas Underground Storage and Interstate Transportation
Permanent transportation and storage costs reflect a net increase totaling $620,781
relative to costs in Case No. INT-G-17-05. 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
I Locked-in gas includes storage volumes that are both hedged and index purchases.
6
2013 2014 2016 2017 201 8
Non-Summer Months (Oct.-Mar.)79 74 78 82 80 77
Summer Months (Apr.-Sept.)48 63 62 55 49 49
Full Year 7t 72 74 76 73 70
STAFF COMMENTS SEPTEMBER 18,20I8
2015
added to storage is 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
Gas Transmission Northwest, TransCanada's Foothills Pipeline system, and TransCanada's
Alberta system known as Nova Gas Transmission. The cost of gas from upstream transportation
providers increased by $ 1.3M. This is primarily driven by a discounted contract that expired and
was renewed as a full rate contract, and a short-term seasonal contract that was replaced by a
long-term firm contract.
Management of Pipeline Capacity
Staff analyzed the procedures for maintaining and releasing pipeline capacity, and
believes that 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 $4.33 million credit to customers
embedded in its forecast. The Company's capacity release revenue for the current PGA is
forecasted to be $5.45 million, which will be credited back to customers over the coming PGA
year. If capacity release revenues exceed the $5.45 million embedded in the forecast, customers
will receive an additional credit in the 2019 PGA. These credits are included in the Fixed
Deferred Gas Costs listed in Table l.
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 operations
7STAFF COMMENTS SEPTEMBER 18,2018
& maintenance related expenses, as well as a2.5 cents per every gallon of LNG sold for future
capital projects that may be impacted by non-utility sales. 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 $571,1082 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
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 deferral.
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 from base rates, resulting in recovery of the LAUF solely in the PGA.
This year, the Company's estimated LAUF Gas rate of 0.0677% is below the maximum
allowable level of 0.85% specified in Commission Order No. 30649. The Company allocates
LAUF Gas 75Yo to core customers (Residential and General Service) and25o/o to industrial
customers (Large Volume and Transportation) on a per therm basis.
The Company charges a Line Break Rate to contractors or other parties who are
responsible for damage to the distribution system that causes a gas leak. The current (2017
2 The total LNG benefit consists of $571,108 from sales, plus $122 in interest, minus $41,785 from the previous
case's deferral for the net benefit of 5529,445 as shown on Table 2.
8STAFF COMMENTS SEPTEMBER 18,2018
PGA) Line Break Rate is $0.45984 per therm. The Company proposes to decrease the Line
Break Rate from $0.45984 per therm to $0.41625 per therm. The proposed Line Break Rate
includes a $0.18901 Fixed-Cost Component (Transportation Cost) per therm and a $0.22724
Variable-Cost Component (WACOG) per therm for a total of $0.41625. Both components of the
Line Break Rate are determined annually with the PGA filing. Staff verified that the Company
calculated the proposed Line Break Rate consistent with Order No. 33139.
Tax Changes
Staff audited and confirmed that the remaining amounts to be returned to Customers due
to the benefits from the Tax Cuts and Jobs Act of 2017 (TCJA) were properly accrued and
reported in this filing. In Case No. GNR-U-18-01 the Commission ordered an investigation of
the effects of the TCJA. In Order No. 34073, the Commission approved a multi-party settlement
in which the Company would include in the PGA the benefits of the TCJA that were accrued
during 2018 before the Company reduced rates on June 1,2018. In this filing, customers will
receive the deferred amount of benefits of the TCJA from January 1,2018, to May 31, 2018,
totaling $2,731,841.
Rate Case Expenses
Previously, the Commission found that the Company demonstrated the prudency of
$378,614 in external 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.
Intervenor Funding
The Commission also authorized the Company to recover intervenor funding costs from
the last rate case. Staff confirmed that those costs are no longer apart of the PGA filing.
Quarterly Reporting
In the 2017 PGA. the Commission ordered the Company to resume filing quarterly
Summary of Deferred Gas Cost Balances reports after they were discontinued in 20 I 5.
9STAFF COMMENTS SEPTEMBER I8,2018
Order No. 33887 at 6. Staff believes the Quarterly reports are useful, and therefore recommends
the Commission order the Company continue filing the quarterly reports.
Application, Workpaper, Exhibit Content and Structure
Over the past year, the Company and Staff worked together to create a format for PGA
filings, LAUF reporting, and work papers that is more comprehensive, well referenced, aligns
with the Company's accounting, satisfies Commission requirements, and easier to follow and
understand. Staff appreciates the Company's effort and cooperation in this endeavor.
CUSTOMER NOTICE AND PRESS RELEASE
The Company's press release and customer notice were included with its Application on
August 10,2018. Staff reviewed the documents and determined both meet the requirements of
Rule 125 of the Commission's Rules of Procedure (IDAPA 31.01.01). The notice was included
with bills mailed to customers beginning August 14, 2018, and ending September 1 1, 2018,
providing most customers with a reasonable opportunity to file timely comments with the
Commission by the September 1 8, 201 8, deadline. As of September 17 ,2018, no comments had
been filed.
STAFF RECOMMENDATIONS
Staff recommends the Commission approve a decrease in revenues of 524.5 million as
calculated in Table 2 and direct the Company to file tariffs representing the Commission's order
in this case. Staff also recommends the Commission approve the Company's proposed WACOG
of $0.22724 per therm. 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.
STAFF COMMENTS 10 SEPTEMBER 18,2018
Respectfully submitted this l6%u*of September 2o 1 8.
Karpen
Technical Staff: Joseph Terry
Johan Kalala-Kasanda
Kevin Keyt
Johnathan Farley
i : umisc/comments/intg1 8.2bkjkjtkkjf comments
General
STAFF COMMENTS ll SEPTEMBER 18,20I8
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 18th DAY OF SEPTEMBER 2018,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT-G-18-02, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWNG:
MICHAEL P McGRATH
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]
Y
CERTIFICATE OF SERVICE