20170914Comments.pdf

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3CAMILLE CHRISTEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BAR NO. r0r77
Street Address for Express Mail:
472W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BBFORE 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-17.05
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
attorney of record, Camille Christen, Deputy Attorney General, and in response to the Notice of
Application and Notice of Modified Procedure issued in Order No. 33859 on August 28,2077,
submits the following comments.
BACKGROUND
On August 74,2017,Intermountain Gas Company ("Intermountain" or "the Company")
applied to the Commission for authority to change its rates, effective October 1,2017, 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 f,rxed costs to serve its customers -
for example, the Company's costs for equipment and facilities to provide service - and change
less frequently. The current base rates were approved in Order No. 33757, Case No.
INT-G-I6-02. See Id.
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1STAFF COMMENTS SEPTEMBEP.14,2OIT
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 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) a deuease 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;
and (6) costs accrued related to the Company's general rate case. 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-16-03. Id.
The changes in the Company's gas-related costs will decrease rates for the Company's
RS (Residential) and GS-1 (General Service) customers, and inuease rates for its LV-1 (Large
Volume), T-3, and T-4 (Transportation) customers. Id. at 4. The current gas-related cost
component of the Company's rates was approved in Order No. 33604, Case No. INT-G-16-03.
See id.
The changes to the rates will decrease the Company's annualized revenues by
approximately $19.2 million, but will not impact earnings. Id. at2. The Company proposes to
pass through to customers gas-related cost changes that would decrease the average bill of
residential customers by $332lmonth (8.1%) and commercial customers by $16.42lmonth
(9.2%). The Company explains that the proposed rate changes would be allocated to customer
classes through its PGA provision. Id. at 7.
The Company provides additional detail on the changes it is seeking to incorporate into
rates. See id. at 4-8. For example, the permanent transportation and storage costs in this
Application reflect a decrease of $1.3 million compared to those same costs in Case No.
INT-G- 1 6- 03 . Id. at 4 . The WACOG reflected in the proposed prices is $0.26020 per therm,
compared with the WACOG of $0.29695 currently included in rates. Id, at 5. This decrease of
$0.03675 per therm reflects robust natural gas supplies, significant storage balances, and the
Company's efforts to manage its natural gas storage assets. Id. The Application further explains
other adjustments and treatment of various deferred costs. Id. at 4-8.
2STAFF COMMENTS SEPTEMBERT4,2OIT
The Company specif,rcally explains adjustments to the LV-1, T-3, and T-4 tariffs. For the
LV-l tariff a straight cents per therm price change was not used, because no fixed costs are
currently recovered in the tail block of that tariff. Id. The Company indicates that the proposed
changes in the WACOG and variable deferred credits and debits (outlined in Exhibit Nos. 9 and
l0) applied to all three blocks of the LV-l tariff. Id. at7-8. However, adjustments related to
fixed costs applied only to the first two blocks. Id. at 8. The net change of the adjustments is a
price increase for the LV-l customers. See id. at Exhibit No. 13. For the T-3 and T-4 tariffs, the
adjustments included in the proposed tariffs include: (a) removal of existing temporary price
changes; (b) the Lost and Unaccounted for Gas decrease (outlined in Exhibit No. 9); (c) for the
T-4 tariff, the Liquified Natural Gas (LNG) Sales Credits (see Exhibit l0), and (d) a temporary
adjustment to recover the Company's general rate case related expenses. Id. at 8. The net
change of these adjustments for the T-3 and T-4 customers is a rate increase. Id.
STAFF ANALYSIS
Staff has thoroughly examined the Company's Application, workpapers, and exhibits and
has verified that the Company's PGA proposal would not impact the Company's earnings, that
the Company's deferred costs are prudent and properly calculated, and that the Company's
WACOG request is reasonable.
Table I summarizes the impact of the Application's proposed changes on customer
classes.
Table 1: Summary of proposed changes on customer classes
Customer Class:
Proposed
Change in
Class
Revenue
Proposed
Average
Change in
$/Therm
Proposed
Average
o,t,/o
Chanse
Proposed
Average
Price
$/Therm
RS Residential
GS-l General Service
LV-l Large Volume
T-3 Transportation
$(12,505,5 l 8) $(0.05900)
$ (6,722,390) $(0.06226)$ 17,803 $ 0.00270$ 13,775 $ 0.00036
-8.r2%
-9.21%
0.68%
2.91%
0.00%
TOTAL S(1q.152.66
$0.667ss
$0.613 82
$0.39877
$0.01274
JSTAFF COMMENTS SEPTEMBER 14,2OI7
The overall effect of the Company's proposed changes is a decrease in annual revenues
of approximately $19.15 million. Staff recommends a decrease of $19.25 million (a difference
of $99,056) as calculated on Table 2 below.
This difference is solely attributable to Stafls recommendation on the recovery and
amortization of deferred rate case expenses, which will be discussed in greater detail later in
these comments.
Table 2: Proposed Changes to Annual Revenue
Deferrals:
Removal of NT-G-16-03 Temporary Credits and Charges
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
Intervenor Funding
Deferred General Rate Case Costs
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
$( 19,954,897)
2,440,939
(858,1 14)
(495,4t8)
25,179
75,723
$(1,163,906)
(99,170)
(545,782)
549,844
(71"306)
$(1,330,320)
$(11,999,770)
$(2,508,419)
$15,354,379
$(18.766.s89)
$ (3,412,210)
$(15.838.509)
s (19.250.719)
The Company included the elimination of temporary credits and surcharges implemented
in last year's PGA, Case No. INT-G-I6-03, in the amount of $15,354,379. The temporary
credits and surcharges proposed for the current PGA case total $18,766,589 in the rebate
direction. These temporary rate adjustments consist of market segmentation and capacity release
4STAFF COMMENTS SEPTEMBER14,2OIT
revenues, interest, and per therm amortization of deferrals and over collections from last year's
PGA. Additionally, the temporaries also include credits for Lost and Unaccounted for Gas and
the off-system sales of Liquefied Natural Gas, along with surcharges for expenses associated
with the Company's general rate case. The Company includes a fixed-cost collection adjustment
that credits S2,508,419 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. During the course of the review, Staff made additional findings
that are discussed in more detail below.
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
50.26020 per therm which is a 12.4o/o decrease from the WACOG of $0.29695 per therm
established in the 2016 PGA filing and currently included in rates. The proposed decrease in the
WACOG represents an approximate $12 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.
5STAFF COMMENTS SEPTEMBER14,2OIT
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Chart 1: Weighted Average Cost of Gas (Per Therm)
When the Company pays less for gas than what is estimated in the WACOG, a credit is
issued to customers. However, if the Company pays more for gas than what is estimated in the
WACOG, a surcharge is added to the PGA. Intermountain Gas procured natural gas at costs
slightly above what it had anticipated in last year's PGA filing resulting in an additional $2.4
million deferral to be amortized over the next 12 months. However, those additional costs are
offset by other activities that allow Intermountain to rebate money to customers during the
upcoming PGA 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"),
the Northwest Gas Association ("NWGA"), and the Northwest Power and Conservation Council
("NWPCC").
Each year, the NWGA publishes its Gas Outlook which contains current and projected
natural gas supply, demand, prices, and delivery capabilities for the next twenty years. NWGA's
2016 Gas Outlook key conclusions on the supply side are that shale reserves continue to
6STAFF COMMENTS SEPTEMBER14,2OIT
I
transform the energy landscape. Furthermore, production techniques continue to improve for
both vertical and horizontal drilling. On the price side, both spot and future commodity prices
reflect growth in North American natural gas production. Absent a major catastrophic event,
natural gas prices should remain relatively stable in the near term.
Risk Management
Staff scrutinized how the Company manages price and risk given the Company's market
purchases, storage, and interstate transportation capacity. Staff analyzed the Company's
operations and business practices to determine whether the Company purchased gas at market
prices 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.
The Company fulf,rlls 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 35o/o of
the Company's total throughput are index or spot purchases. The Company's hedged supply
went from 48.1% of total throughput last year to 49Yo this year. Including the Company's
storage gas, about 65Yo of the Company's supply is essentially hedged which is slightly lower
than last year. 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 utilize index or spot purchases, allowing it to react to upward price risk. 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 hedges over the last six years.
7STAFF COMMENTS SEPTEMBER14,2OI7
Table 3: WACOG Hedging Ratios:
Natural Gas Underground Storage and Interstate Transportation
Staff analyzed the Company's practices for utilizing underground storage. The Company
plans to withdraw about the same amount as it has in previous years (approximately 28%) of its
underground storage to meet total throughput.
Permanent transportation and storage costs reflect a net decrease totaling almost $1.3
million relative to costs in Case No. INT-G-16-03. 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 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 fuither 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 (GTN), TransCanada's Foothills Pipeline system (Foothills), and
TransCanada's Alberta system known as Nova Gas Transmission (NIOVA). The cost of gas
from upstream transportation providers increased by $4,062 from the last PGA (Case No.
rNT-G-16-03).
I % Locked-in gas includes storage volumes that are both hedged and index purchases.
8
% Locked-in Gas by PGA Yearr
2012 2013 2014 20t5 2016 2017
Non-Summer Months (Oct.-Mar.)63 79 74 78 82 80
Summer Months (Apr.-Sept.)45 48 63 62 55 49
Full Year 59 7l 72 74 76 73
STAFF COMMENTS SEPTEMBER14,2OIT
Management of Pipeline Capacity
The Company generally utilizes 100% of its available pipeline transportation capacity
during the winter months. At times when the Company has excess pipeline capacity, the
Company seeks to maximize value by selling the excess capacity on the market. In last year's
PGA filing, the Company included a $3.94 million credit to customers embedded in its forecast.
The Company's capacity release revenue for the current PGA year exceeded the forecasted
amount embedded in rates by $a.3 million, which will be credited back to customers over the
coming PGA year. Additionally, the Company included another $3.74 million credit to
customers for the upcoming year as a forecasted amount of revenue it will receive from the sale
of its excess capacity. If capacity release revenues exceed the $3.74 million embedded in the
forecast, customers will receive an additional credit in the PGA filed in 2018. These credits are
included in the Fixed Deferred Gas Costs listed in Table 1.
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 70o/o on any
amounts greater than $1.5 million. In this Application, the Company proposes to credit
ratepayers $495,418 for their share of the revenues from the non-utility sale of LNG. Staff has
reviewed the Company's non-utility sales of LNG, and verified that the credit to ratepayers has
been reasonably calculated.
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. Since the Company's 1985 General Rate Case, the Company has recovered LAUF
Gas amounts through a $0.00182 per therm charge, or approximately $l.3 million, embedded in
base rates. Beginning rn2007, the Commission allowed the Company to true up actual LAUF
Gas to the amounts included in base rates through the PGA. See Order No. 30443. When actual
STAFF COMMENTS SEPTEMBER14,2Ol]9
LAUF Gas is greater than what is included in base rates, a surcharge is added to the PGA.
Conversely, the Company credits customers through the PGA if the amount is below what was
included in base rates.
This year, the Company's estimated LAUF Gas rate of 0.222Yo is below the maximum
allowable level 0.85% specified in Commission Order No. 30649. The estimated deferral
account balance credit of $858,114 as of September 30,2017 will be credited to customers if the
PGA filing is approved.
The Company allocates LAUF Gas credit 75o/o to the core customers (Residential and
General Service) and25o/o to the industrial customers (Large Volume and Transportation)
through a per therm credit. However, with recent implementation of demand charges (see Order
No. 33757), the LAUF credit for customers receiving service under the Company's
Transportation Schedule T-4 would make the volumetric charge for those customers a negative.
Rather than creating a negative per therm charge and the perception of paying those customers to
take gas, the Company applied the credit to the demand charge for the T-4 class. Staff believes
this approach was reasonable, and verified the credit to the demand charge was accurately
calculated on Exhibit No. 9.
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 (2016
PGA) Line Break Rate is $0.54067 per therm. The Company proposes to decrease the Line
Break Rate from $0.54067 per therm to $0.45984 per therm. The proposed Line Break Rate
includes a $0.19964 Fixed-Cost Component per therm and a $0.26020 Variable-Cost Component
per therm for a total of $0.45984. Both components of the Line Break Rate are determined
annually with the PGA filing. Staff concluded that the Company correctly calculated the
proposed Line Break Rate consistent with Order No. 33139.
Intervenor Funding
At the conclusion of the Company's general rate case, the Commission ordered the
Company to pay $25,178 for intervenor funding, and authorized the Company to recover the
intervenor funding in the 2018 PGA, Order No. 33757. Staff verified that the Company properly
allocated the intervenor funding to the customer classes based on revenues approved in Order
No. 33757. Transportation customers receiving gas under the Company's Rate Schedule T-3
STAFF COMMENTS l0 SEPTEMBER 14,2OI7
will not see a rate change from the allocated portion of the intervenor funding because the $150
amount allocated to that class does not have any impact on rates.
External Rate Case Expenses
On October 9,2015, Case No. INT-G-I5-03, the Company sought approval from the
Commission to defer as a regulatory asset for later recovery the external expenses incurred to
prepare and present its next general rate case. In that case, the Company estimated that the
deferred expenses would be less than $400,000 and would include expenses associated with
outside legal counsel, working capital analysis, revenue requirement studies, cost of capital, cost
of service model and associated studies, rate design, contract computer programming, intervenor
funding, climatological studies, and customer awareness. In approving the Company's request,
the Commission stated that:
. . . we are not determining the prudency of any expenses or precluding
Staff from auditing and ultimately challenging the appropriateness,
reasonableness and prudence of any deferred costs. When the Company
ultimately asks to recover these costs in its next general rate case, it will
need to submit detailed documentation supporting them, and evidence of
prudency.
Order No. 33432 (emphasis added). The Commission further ordered that the Company
maintain detailed documentation with which to support all deferred rate case expenses that the
Company expects to claim in the next general rate case. Id.
The Company is now requesting the recovery of $699,1 14 of deferred rate case expenses,
which is significantly higher than what it represented to the Commission and Staff in Case No.
INT-G-15-03. The Company proposes a four-year amortization of the deferred expenses, or
$174,779 per year. Staffls preference is to determine the prudency and amortization of defened
expenses in a general rate case, as suggested by the Commission, rather than during the
expedited process of a PGA. However, given that INT-G-16-02 was the first general rate case in
over 30 years, and that the PGA is a rate reduction this year, Staff believes it is reasonable to
allow the Company to begin recovering some of the deferred expenses in this case.
Staff audited all defened rate case expenses and attempted to analyze the customer
benefit of each expense to determine if it is appropriate for recovery from customers. Staff
began the audit by inquiring about vendor selection process. For the most part, the Company
STAFF COMMENTS 11 SEPTEMBER14,2OIT
limited its choice of consultants to those whom the Company had experience working with and
who were familiar to the Company. A Request for Proposals (RFP) was issued for the
Regulatory Consultant to assist the Company in developing a cost of service model, cost of
capital recommendations, a lead lag study for working capital, revenue requirement, rate base
and rate design. Staff reviewed the RFP, but notes that it was undated and there were no records
indicating when it was issued.
The Company provided two responses to the RFP for Staff to review. The first response
was dated October 25,2013. The second response was dated January 29,2016. Given that only
two proposals were received, the proposals were 27 months apart, and the large number of
consultants in the utility industry capable of performing the requested duties, Staff does not
believe the audit evidence demonstrates the proper use of a competitive bidding process. The
Company chose to use the vendor that submitted the January 29,2016 proposal, Concentric
Energy Advisors (Concentric), for preparation of its case.
Charges from Concentric make up the largest portion of the total deferred rate case
expenses, and Concentric alone exceeded the $400,000 estimate provided by the Company in
Case No. INT-G-15-03. Staff audited all 14 invoices from Concentric and identified six
categories for the charges. Staffbelieves these categories are appropriate for rate cases and the
testimony and exhibits presented in the Company's general rate case demonstrate the initial work
performed by Concentric.
Staff believes it is reasonable to include for recovery in this PGA the original budgeted
amounts included in the Concentric proposal for the LeadlLag Study, Revenue Requirement,
Cost of Service, and Rate Design. The Concentric budget for each of these categories is listed on
Confidential Attachment A. Concentric also performed Cost of Capital (COC) studies and made
Return on Equity recommendations for the Company in expert witness testimony. Staff notes
that the COC work performed by Concentric amountedto 27.8%o of the total and exceeded its
budget by more 200%. Staff has concerns with the amount charged by Concentric for its COC
work and the magnitude of the total amount over the budget. The COC work provides the
greatest benefit to shareholders. Staff recommends that one-half of the budgeted amount for Cost
of Capital be included with expenses to begin recovery in this PGA and the remainder be
deferred until such time that Staff can fully examine the expense and determine if customers
should be responsible for the remaining amount.
STAFF COMMENTS 12 SEPTEMBER14,2OTT
Additionally, Concentric performed rate base consulting and calculations for
Intermountain. Staff does not believe that any of the billed amounts for rate base consulting
should be included for recovery in the PGA. Reporting plant-in-service details, accumulated
depreciation and all account details to calculate rate base is a normal part of the Company's
day-to-day operations. Additionally, the Company could seek regulatory advice on the treatment
of rate base from its affiliates with MDU Resources Group, Inc., Intermountain's parent
company. Staff believes the work provided by Concentric may be duplicative and excessive and
could have been provided at a significantly reduced cost from Intermountain's affiliates.
The Company also contracted with Alta Vista Systems, LLC (Alta Vista) to provide
external computer services. Documentation from Alta Vista included l4 invoices. Several of
these invoices referred to billing histories, billing data, gas sales, and files used by consultants.
Staff requested some of this information in Production Requests during the general rate case, but
the information was not provided. Furthermore, these files used by consultants would help
determine the prudency of the charges. Staff recommends that all expenses paid to Alta Vista be
deferred until Staff can fully evaluate the work performed, necessity and prudence of the
expenses.
Based on its analysis, Staff recommends that the Commission approve $378,614 for
current recovery amortized over five years, or $75,723 annually in the PGA, as shown on
Confidential Attachment B. This amount includes expenses to all external consultants and
attorneys with the exception of Alta Vista Systems, LLC and a portion of the expenses to
Concentric Energy Advisors. Staff believes additional time is needed to evaluate the remaining
$319,963 and recommends the Commission defer its decision on this amount until the next
general rate case so Staff can thoroughly review additional documentation related to the purpose
and prudency of these expenses.
Quarterly Reporting
In October 2}ls,Intermountain stopped filing its monthly Summary of Deferred Gas
Cost Balances reports and its quarterly WACOG calculations. The updates continue to be useful
to assist Staff in tracking the PGA balances throughout the year and to determine if the WACOG
included in rates remains reflective of current conditions. Staff has discussed the need for
routine updates on the deferral balances and WACOG estimations, and the Company has agreed
STAFF COMMENTS 13 SEPTEMBER14,2OI7
to file the reports on a quarterly basis going forward. In order to obtain the most useful
information in the Summary of Deferred Gas Costs report, Staff requests that the Company file
monthly beginning balances, amortization amounts, interest, and ending balances for each line
item included in the Company's deferrals that flow through the PGA in its quarterly report. Staff
will work with the Company to determine the format and presentation of the information that
will provide the most use to Staff, the Commission, and interested parties.
CUSTOMER NOTICE AND PRESS RELEASE
Intermountain Gas filed copies of its press release and customer notice with its
Application. Staff reviewed both documents and determined that they comply with Rule 125 of
the Commission's Rules of Procedure. IDAPA 31.01.01.125.
The notice was included with customer bills beginning August 16 and ending
September 13. Some customers will not have a reasonable opportunity to file comments on or
before the Commission's comment deadline of September 14,2017. Because this year's PGA
results in a reduction to customer rates, it is less likely that customers will object to the proposed
rate changes. However, customers must have the opportunity to file comments and have those
comments considered. Therefore, Staff recommends that the Commission accept late filed
comments in this case.
CUSTOMER COMMENTS
As of September 14,2017, the Commission has not received any comments from
customers regarding the rate decrease proposed in this case.
STAFF RECOMMENDATIONS
After examining the Company's Application, exhibits, workpapers, and gas purchases for
the year, Staff recommends the Commission approve a decrease in revenues of $ 19.25 million as
calculated in Table 2 and direct the Company to file tariffs representing the Commission's order
in this case. Staff also recommend the Commission approve the Company's proposed WACOG
of $0.26020 per therm. Staff encourages the Company to return to the Commission if gas prices
deviate from projections significantly.
STAFF COMMENTS l4 SEPTEMBER14,2OI7
Staff recommends the Commission approve $378,614 of rate case expenses for current
recovery or $75,723 annually in the PGA over five years. Staff also recommends the
Commission defer its decision on the remaining $319,963 until the next general rate case.
Additionally, Staff recommends the Commission order the Company to file quarterly
updates reflecting the deferred gas costs and WACOG projections, and continue to file those
reports until the Commission issues an order stating the reporting requirements are no longer
necessary.
Because some customers may not receive the Customer Notice in time to file comments
in this case, Staff also recommends that the Commission accept late filed comments.
Respectfully submitted this l '{ ' day of September 2017.
Camille Christen
Deputy Attorney General
Technical Staff: Kevin Keyt
Patricia Harms
John Nobbs
Daniel Klein
i : umisc/comments/intg I T.5cckskphjndk comments
STAFF COMMENTS 15 SEPTEMBER 14,2OI7
ATTACHME,NTA
IS
CONFIDENTIAL
ATTACHMENT B
IS
CONFIDENTIAL
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS I4TH DAY OF SEPTEMBER 2017,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT-G.17-05, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
MICHAEL P McGRATH
DIR _ REGULATORY AFFAIRS
INTERMOUNTAIN GAS CO
PO BOX 7608
BOISE ID 83707
E-MAIL: [e-mail]
(Confi dential Attachment)
RONALD L WILLIAMS
WILLIAMS BRADBURY
1015 W HAYS ST
BOISE TD 83702
E-MAIL: [e-mail]
(Confi dential Attachment)
r[ '
CERTIFICATE OF SERVICE