20130918Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5156
Street Address for Express Mail:
472W. WASHINGTON
BOISE, IDAHO 83702-59T8
Attorney for the Commission Staff
IN THE MATTER OF THE APPLICATION OF
INTERMOUNTAIN GAS COMPANY FOR
AUTHORTTY TO CHANGE ITS PRTCES (2013
PURCHASED GAS COST ADJUSTMENT;.
.-'---l') L1,-. -r | _l
CASE NO.INT.G.13.O5
COMMENTS OF THE
COMMISSION STAFF
,:::
l- 4--"J
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
The Staff of the Idaho Public Utilities Commission comments as follows on
Intermountain Gas Company's Application.
BACKGROUND
On August 19,2013,Intermountain Gas Company filed its annual Purchased Gas Cost
Adjustment (PGA) Application and requested a Commission Order, under Idaho Code $$ 6l-307
and 6l-622, to institute new rate schedules that will increase its annualized revenues by $ 10.3
million (about 4.15%). The Company asks that the Commission process the Application by
Modified Procedure, and that the new rates take effect October 1,2013.
The PGA is used to adjust rates to reflect annual changes in the Company's costs to buy
natural gas from suppliers-including transportation, storage, and other related costs. See Order
No. 26019. With this Application, the Company proposes increasing the Weighted Average Cost
of Gas (WACOG) from the currently approved $0.33489 per therm to $0.37341 per therm. The
Company explains that significant shale gas reserves exist, but recent improvements in the
economy and an increase in natural gas-fired electric generation have increased demand and
STAFF COMMENTS SEPTEMBER 18,20I3
placed upward pressure on natural gas prices. The Company notes, however, that natural gas
prices remain much lower than they were a few years ago.
The Company says it has entered into fixed price agreements to lock-in the price for
significant portions of its underground storage and other winter "flowing" supplies.
The Company seeks to pass through to its customers the benefits that will be generated
from the management of its transportation capacity totaling $3.9 million as outlined on Exhibit
No. 7. The Company also proposes temporary price adjustments for the 12-month period ending
September 30,2014, which would allocate to customers the fixed, variable, and lost and
unaccounted-for gas costs from the Company's deferred Account No. 186 balance. The
Company notes that pursuant to Order No. 32793, its deferred variable gas cost credits included
those associated with liquefied natural gas (LNG) sales from the Company's Nampa, Idaho
facility.
The Company says the proposed overall price changes reflect a just, fair, and equitable
pass-through of changes in gas-related costs to the Company's customers. The Company says it
has notified customers about the Application and price changes through a formal Customer
Notice and a Press Release.
STAFF ANALYSIS
Staff has thoroughly reviewed the Company's Application and gas purchases for the year
to verify that the filing will not change the Company's earnings, that the deferred costs are
prudent, and that the WACOG request is reasonable.
In this year's PGA, the Company proposes raising total customer rates by about $10.3
million. This increase is due to an increase in costs billed to the Company from firm
transportation providers, an increase in the WACOG, an updated customer allocation of gas-
related costs pursuant to the Company's PGA provision, the inclusion of temporary surcharges
and credits for one year relating to natural gas purchases and interstate transportation costs from
Intermountain's deferred gas cost accounts, and benefits resulting from Intermountain's
management of its storage and firm capaciq rights on various pipeline systems. The temporary
surcharges and credits in the Company's current prices during the past l2 months, pursuant to
Case No. INT-G-12-01, were also eliminated. These changes would increase overall prices for
Intermountain's RS-1, RS-2, GS-1 and LV-l customers and decrease overall prices for
Intermountain's T-3, T-4, and T-5 customers as follows:
STAFF COMMENTS SEPTEMBER 18,2013
Table 1
The overall effect of the Company's proposed changes is to increase the Company's
annual revenue by $10,279,255. This increase is comprised of the following items:
Table 2
Weighted Average Cost of Gas (WACOG)
The Company proposes to increase the WACOG from $0.33 49 per therm to $0.3734 per
therm. The WACOG is calculated based on the anticipated cost of the Company's executed
Customer Class:
Proposed
Change in
Class
Revenue
Proposed
Average
Change in
$/Therm
Proposed
Average o/o
Chanpe
Proposed
Average Price
$/Therm
1 Residential $s61 .3 1s .01616 r.88%.87699
RS-2 Residential s5.282.798 .02887 3.92%.76462
GS-1 General Service $5,202,273 .04946 7.26%.73088
LV-l Larse Volume $245,837 .06797 r4.96%.s2240
T-3 Transportation ($4 r 3.032)(.00360)fi7.67%\.0t677
T-4 Transportation ($s29.2ss)(.00361)( 7.9t%).04205
T-5 Transportation ($70.681)(.00360)(r0.18%).02981
s10.279.255 4.t5%
Deferrals:
Removal of INT-G-12-01 Temoorarv Credits $9.816.649
Removal of INT-G-12-01 Lost and Unaccounted for Gas ($2.r38.220)
INT-G- I 3 -05 Temporary Credits ($9,601,616)
Total Deferrals ($1,923,187)
Lost and Unaccounted for Gas (INT-G-13-05)($444,316)
Reallocation of fixed costs (s2.103.424\
Chanses in the Weishted Averase Cost of Gas sr2,577,507
Fixed Cost Chanses:
Northwest Pipeline $2,r90,264
New Uostream Caoacitv Costs $192,4r0
SGS & LS Chanses ($538.771)
Other Storaee Facilities Cost Chanses $328.77r
Total Fixed Cost Chanees $2,172"674
Total Annual Price Chanse 9t0.279.zss
STAFF COMMENTS SEPTEMBER 18,2013
hedges, current underground storage, and its estimated index price for future deliveries. The
volume-weighted average cost is estimated by averaging the sum of forward natural gas prices
multiplied by projected purchase volumes for each supply source and contracting instrument. As
reflected in Chart 1, the proposed WACOG will be the first increase following six consecutive
decreases, and is among the lowest since the 2000 WACOG in nominal dollars.
Chart I
Weighted Average cost of Gas ($lrhernr)
otF
0.7&60
0 600t1
E o.so,-r,:oc
< 0"4000
L1,36Dl'
o.:000
0.1000 '00 '01 ,0:'s5 'rl7 '03'Dec-'09"'10 11 11" le.-It.13 Prop
IVACOG
1S/Theml 4.2$1 o.-aEa0 0.3.t00 D.475n 0.5549 $.6850 o,6l5B 0.7348 0 5?48 0.4960 0.3349 4.3131
i- ',o Change bascrl orr prc"ious rccularlv schedul.d ll(ii\ tjlirg
" o'u ( irarige baseJ rn previors Deccmber lilirrg
Staff reviewed the market fundamentals to determine whether the Company's executed
hedges and estimated index prices for future delivery are reasonable. Specifically, Staff
reviewed data and reports from: (1) the Energy Information Administration (EIA); (2) the
Northwest Gas Association Q.{WGA); (3) the Northwest Power and Conservation Council
(t{PCC); (3) the NYMEXA{GX Futures; and (4) the Intercontinental Exchange (ICE). Overall,
Staff believes the Company's methodology and calculations are accurate, and that the WACOG
is reasonable given market conditions.
Market Fundamentals
Weak economic conditions, the prolific increase in the supply of shale and
unconventional gas, and several other factors have contributed to some of the lowest gas prices
in the last decade. As the economy shows signs of improvement, we are beginning to see
upward pressure on prices. Other potential factors contributing to higher prices include:
l) Increased gas-fired electric generation due to aggressive regulation ofcarbon
emissions from coal plants;
STAFF COMMENTS SEPTEMBER 18,2013
2) Lower storage inventory levels and flattening production comparedto 2012;
3) Increased demand from natural gas fleet vehicles;
4) Increased demand for exports of LNG from Canada and United States; and
5) Increased demand from gas-to-liquid projects.
The NWGA 2013 Gas Outlook lists the Boardman, Oregon and Centralia, Washington coal
plants as examples of two regional coal plants directly impacted by environmental regulations.
Both plants will close. According to the NWGA, both plant operators say they intend to replace
at least some of that generation capacity with gas-fired generation. The NWGA also believes
natural gas-fired generation will be necessary to balance load given the large investments in
intermittent wind resources in Oregon and Washington. The NWGA thus expects average gas
consumption for electric generation to increase2.6Yo per year through 2022 as electric utilities
increasingly rely on natural gas generation to fill baseload needs. Conversely, the EIA expects
projected year-over-year increases in natural gas prices to contribute to a decline in natural gas
used for electric power generation. Specifically, it expects overall consumption for electric
generation to decline by nearly l4%by 2014 compared to 2012 levels.
Price Analysis
Staff reviewed the projected monthly cost of purchased gas that the Company used to
determine the proposed WACOG, and compared it to several sources to evaluate future price
trends. Staff believes the Company's proposed WACOG of $3.73 per MMBtu is conservative
but reasonable compared to recognized natural gas price benchmarks. Staff analyzed the
NYMEXAIGX futures prices at each of the three hubs where Intermountain buys gas.l Usi.rg
the Company's estimated volume allocation percentages for the three hubs where it buys gas,
Staff calculated $3.40 per MMBtu as the volume-weighted cost of purchased gas.
The Company's monthly purchased gas costs are generally higher than Staff s estimates
because of the premiums embedded in the price of the Company's hedged contracts and
purchasing strategies. But if prices increase as forecasted, the older hedges may be less
expensive than the spot or index purchases. By 2014, the EIA expects Henry Hub prices to
increase by 6.4% compared to the 20i3 price estimates, and,44%o compared to 2Ol2prices. 2
' Prices are based on settlements that occurred on August 27 , 2013.
2 EIA, STEO (September 2013), Tablesb. U.S. Regional Natural Gas Prices (http://www.eia.gov/forecasts/steo/report/)
STAFF COMMENTS SEPTEMBER 18,2013
Similarly, the NPCC expects Henry Hub prices to increase by 4.6% in20l4 when compared to
2013 price estimates. The NPCC expects AECO prices to increase by 6% in2014 when
compared to 2013 price estimates. For comparison purposes, the Company anticipates the
average monthly spot price at AECO tobe 13%o higher than what was forecasted during last
year's PGA, but the forecast is similar to the Company's actual procurement prices at AECO
through July of this year.
Staff believes the Company's hedges were prudent and its approach for estimating the
forward prices reasonable. However, the Company should continue to monitor its long-term
contracts and nominated pipeline capacity. Based on Staffls review of the market fundamentals,
the Company's weighted average cost of its current hedges, and the Company's estimated cost of
forward-looking index purchases, Staff recommends the Commission accept the Company's
proposed WACOG of $0.3734 per therm. Staff also recommends that the Company return to the
Commission with a new filing if prices materially deviate from the proposed rates during the
upcoming year.
Other Considerations
The Company allocates the volume-weighted average costs of gas to each customer class
based on peak-day usages. Before 2012, the peak day used for allocating the volume-weighted
average costs of gas occured in 1990. But in the 2012 PGA, the Company started using a more
recent and colder peak day to allocate the volume-weighted average costs of gas. Now, the
Company allocates the volume-weighted average cost of gas based on usages that occurred on a
peak day in2009, instead of 1990. The resulting change does not reallocate costs much
differently for any of the classes. Staff believes it is reasonable for the Company to allocate
costs by using the more recent and colder peak day.
Risk Management and Gas Purchasing
The Company actively reviews current and future market conditions through its Gas
Supply Risk Oversight Program to ensure its purchasing strategies: (1) provide adequate gas
supplies to customers; (2) mitigate the adverse impact of significant price movements in the
natural gas commodity; and (3) minimizethe credit risk inherent in the implementation of certain
price risk reducing strategies. Staff reviewed the Minutes to the Company's Risk Management
STAFF COMMENTS SEPTEMBER I8,2013
meetings as part of its audit. The Company's strategies seem dynamic and involve flexibility to
make decisions based on the fundamentals of the natural gas environment.
The Company's current mainline requirement is approximately 33,000,000 MMBtu's.
Of that amount, about 28%o is stored gas,43%o is hedged flowing supply, and29Yo remains open
to index or spot purchases. The average price of the Company's stored gas averages about $3.66
per MMbtu, whereas the average price of the hedged flowing supply is $3.75 per MMbtu. The
table below compares the proposed WACOG hedging ratios with those from the past three
regularly scheduled PGA filings. In comparison to previous years, it shows how the Company
has increased its hedging ratios during the summer and non-summer months in anticipation of
higher prices.
Table 3
Non-Summer Months (Oct.-Mar.)
Summer Months (Apr.-Sept.)
Full Year
% Locked-in Gas by PGA Year
2010 2077 201.2 20L3
68.1 69.4 63.3 78.5
28.7 0.0 44.5 48.I
58.5 52.4 59.0 7r.4
Overall, Staff believes that Intermountain's adjustments to its hedging ratios match current
market conditions, and protect consumers from future upward price risk. The Company may be
less capable of acting on dropping prices. But upward price risk appears to be more likely
according to the NYIvIEX futures price confidence intervals published by EIA3 and the low and
high forecasts published by the Northwest Power Conservation Council.a
Temporary Surcharges and Credits
Pursuant to Order No. 32653, Intermountain included temporary credits in its October 1,
2012 prices for the principal reason of passing back to its customers deferred gas cost charges
and benefits. The temporary credits consisted of three separate items: (l) a credit of
approximately $3.7 million in benefits generated by releasing some pipeline transportation
capacity; (2) an additional credit of $4.8 million attributable to the collection of pipeline capacity
3 See EIA, Short-Term Energy Outlook, September 2013, futures price confidence intervals.
a See Northwest Power Conservation Council, Seventh Power Plan Fuel Price Forecast, July 2013.
STAFF COMMENTS SEPTEMBER 18,2013
costs, the true-up of expenses from the 2011 PGA, and capacity release credits generated from
the release of Intermountain's pipeline capacity; and (3) the $1.3 million deferred credit balance,
which is the difference from the commodity costs that Intermountain actually paid for natural gas
and the WACOG that was included in rates. The current credit items total $9.8 million. The
current PGA also contains about $2.1 million in a temporary surcharge for Lost and
Unaccounted for Gas (LAUF Gas) resulting in a net temporary credit of about $7.7 million.
The new temporary credits consist of four items: (1) a roughly $3.9 million credit in
benefits generated by releasing some pipeline transportation capacity; (2) another $8.8 million
credit attributable to the collection of pipeline capacity costs, the true-up of expenses from the
20I2PGA, and capacity release credits generated from the release of Intermountain's pipeline
capacity; (3) the $3.1 million deferred surcharge balance, which is the difference in the
commodity costs that Intermountain actually paid for natural gas and the WACOG that was
included in rates; and (a) a very small credit recorded to reflect the agreed percentage of LNG
sales returned to the ratepayers.s The temporary credits total $9.6 million. But when offset by
the removal of prior temporaries (including LAUF Gas), the credit decreases to $ 1 .9 million.
Staff has confirmed the various temporary credit amounts and agrees with the Company's
proposed temporary credit balance.
Natural Gas Storage
Intermountain utilizes natural gas storage to: (1) avoid high winter prices by procuring
gas during the summer when prices are cheaper; and (2) provide system designed peaking
capacity for unusually high demand events or backup for potential pipeline disruptions and
curtailments.
The Company typically uses underground storage to fulfill its winter storage needs and
shield consumers from higher winter natural gas prices. The Company has 94 million therms in
contracted underground storage capacity at Northwest Pipeline's Jackson Prairie and Questar
Pipeline's Clay Basin facilities. This capacity will be filled going into the winter heating season,
and it represents 36%o of the Company's November 20 I 3 through April 201 4 supply requirement.
Through various supply agreements, these storage injections have been locked in at prices
ranging from $0.335 to $0.413 per therm. These rates bracket this year's proposed WACOG.
5 See discussi on in Liquid Natural Gas (LNG) Sales section below.
STAFF COMMENTS SEPTEMBER 18,2013
The overall differences between the cost of stored gas and the WACOG will be reconciled in
customer rates next year.
Liquid Natural Gas (LNG) Sales
The Company utilizes LNG storage throughout the year to meet system peaks and to
supplement local flows due to pipeline congestion or curtailments. Intermountain has 18.5
million therms in total LNG storage capacity at Northwest Pipeline's Plymouth facility and two
Company-owned facilities in Nampa and Rexburg, Idaho. LNG represents about 15% of the
Company's total storage. In the past, the Company kept only 50% of its LNG capacity full
throughout the winter. But on January 23,2013, the Company filed Case No. INT-G-13-02 and
asked for authority to sell LNG. In Final Order No. 32793, the Commission authorized the
Company to sell LNG under certain conditions.
1. The Company shall obtain Commission approval for any LNG sales contracts that
materially differ from the standard contract.
2. The Company shall use future capital expense funds only to replace existing Nampa plant
capital infrastructure due to accelerated wear and tear from producing LNG sales.
3. The Company shall provide a2.5 cent credit for every gallon of LNG sold for Operations
and Maintenance (O&M) related expenses and pass 100% of this amount to utility
customers through the PGA.
4. The Company shall credit 50% of total net margin to ratepayers for sales of LNG through
the PGA up to $1.5 million at which time it adjusts to 70oh.6
Intermountain Gas recorded two LNG sales in this PGA filing, one in January 2013 and another
in March 2013. Staff examined the sales entries to confirm whether the Company properly
recorded the 2.5 cent credit per gallon for O&M ($985), the 50Yo of total net margin credit for
ratepayers ($4,500), and the 2.5 cent credit for future capital expense ($985). The O&M and the
net profit credits were properly recorded and are reflected in Table 2 Temporary Credits.
The future capital expense credit is recorded in an asset account and no charges for
capital expense have been recorded against it. Staff consulted with the Company on the policy
for future recording of credit and expenses. The Company said it is still working out the details.
6 For a complete list of Final Order requirements see Case No. INT-G-13-2 Final Order # 32793.
STAFF COMMENTS SEPTEMBER 18,2013
Staff recommends the Company provide details for the proposed accounting treatment of capital
credits and off-setting capital expenditures for next year's PGA filing.
The Company has recorded an additional sale of LNG gas in July. This sale will be
reconciled in the next year's PGA along with the associated credits.
Pipeline Transportation
Intermountain delivers transported natural gas to its city gates through Northwest
Pipeline, an interstate transportation provider whose pipeline runs through Intermountain's
service territory. The Company also moves gas from Canada to Northwest Pipeline by utilizing
capacity on Gas Transmission Northwest (GTN), TransCanada's Foothills Pipeline system
(Foothills), and its Alberta system known as Nova Gas Transmission (NOVA). Northwest
Pipeline and its shippers settled Northwest Pipeline's recent rate case filing resulting in about a
9o/o price increase effective January 1,2013. Case No. INT-G-12-01 incorporated this increase
for a pro-forma nine-month period. This PGA includes the annualized impact pertaining to the
costs associated with the additional three months. Staff examined the supporting documents
relating to lines 1-19 of Exhibit No. 4, which detail the proposed changes to Intermountain's
prices resulting from Intermountain's cost of storage, and interstate and upstream capacity from
its suppliers.
Through the segmentation of the Company's transportation capacity on Northwest, the
Company believes it has attained two distinct advantages: (1) significant cost mitigation through
the re-marketing efforts of IGI Resources for certain of this segmented capacity; and (2) the
providing of significant deliverability into Northwest at the Stanfield receipt point which allows
access to Alberta based supplies, which the Company believes will deliver the lowest priced
supply in future months. Staff has determined that the Company continues to effectively manage
its pipeline capacities, along with its natural gas storage assets at Northwest Pipeline's Jackson
Prairie and Questar Pipeline's Clay Basin storage facilities to the benefit of its ratepayers.
Recovery of Lost and Unaccounted for Gas
LAUF Gas is the difference between volumes of natural gas delivered to the distribution
system and volumes of natural gas billed to customers. Potential sources of LAUF Gas vary, but
is primarily due to meter malfunctions that cause measurement error at the citygate or at
customers'meters. LAUF Gas may also occur if the Company's billing system is incorrectly
STAFF COMMENTS 10 SEPTEMBER 18,2013
progralnmed or if an industrial customer has changed its demand and, consequently, has an
incorrect meter size.
This year the Company is in a position to credit customers because LAUF Gas amounts
are less than the amounts included in Commission-approved base rates from 1985. In 1985, the
Commission established $0.00182 per therm as the normalized unit cost that can be collected for
LAUF Gas as part of base rates. This past year, the total normalized level of LAUF Gas
embedded in base rates yields an amount of $1,114,285 of LAUF Gas already collected.T The
total estimated October 2012 to September 2013 amount for LAUF Gas is only $716,775. The
Company proposes that the difference of $397,510 be credited to customers for this year's LAUF
Gas. When the true-up amounts from last year are included, the Company is proposing to credit
to customers a total of $444j16 for LAUF Gas. For comparison pu{poses, the Company reports
2 million therms of LAUF Gas for this PGA year, which represents 0.32% of total throughput.
Last year, the Company reported 4.5 million therms of LAUF Gas, which represented 0.76Yo of
total throughput.
Staff reviewed the Company's LAUF Gas in three different ways. First, Staff reviewed
the Company's Gas Loss Reports to determine if the Company's approach for estimating gas
found during line breaks is reasonable. Second, Staff analyzedthe Company's LAUF Gas
workpapers to determine whether the Company's calculations were accurate and reasonable.
Finally, Staff analyzedthe Company's Annual Statistics on LAUF Gas to judge whether the new
reporting format adequately summarized what used to be separately reported in the Company's
semi-annual LAUF Gas reports. (Order No. 30913).
When known leaks and line breaks occur between the citygate and customers'meters, the
Company completes a Gas Loss Report, which includes an estimate of gas that escapes from the
pipeline during the break. These reports serve two purposes. First, they are totaled at the end of
the year and subtracted from the annual LAUF Gas statistics. Second, they are used to calculate
the cost billed to the responsible party. Staff reviewed these reports and found the quantity of
gas to be close to what was reported for line breaks in Workpaper No. 8, Annual Statistics.
However, during the audit, Staff discovered the Company using an outdated WACOG to price
the lost gas due to a line break.s The outdated WACOG was higher than the current WACOG.
' This is included in the Company's PGA application, more specifically, on page 1 of Workpaper No. 8.
t The Company was using $0.41812, when it should have used the current WACOG ($0.37340).
1lSTAFF COMMENTS SEPTEMBER 18,2013
Staff recommends that in the future the Company bill the full retail rate to the responsible party
when pricing the lost gas due to a line break. The WACOG does not include the Company's
fixed costs to transport gas through the pipelines to its distribution system or the cost of the
Company's storage facilities that allow it to procure low-priced summer gas for use during the
non-summer.
Based on its examination, Staff believes the Company's methodology for estimating
LAUF Gas is reasonable. Staff believes the Company's calculations are accurate and below the
cap established by the Commission in Order No. 30649 (i.e., the Company's LAUF Gas is less
than 0.85% of total throughput.) However, Staff recommends that in the future the Company
include more information on page2, WorkpaperNo. 8, Lost and Unaccounted for Statistics.
Specifically, Staff recommends that the Company not only summarize the amount of lost gas due
to line breaks, but for all causes. This will assist the Commission Staff in evaluating the results
of the Company's LAUF Gas situation, operations and procedures. Staff recommends that the
Commission allow the Company to credit customers a total of $444,316 for LAUF Gas.
CUSTOMER RE,LATIONS
Customer Notice and Press Release
The customer notice and press release were included in Intermountain's Application.
The Application was received on August 9,2013. Staff reviewed the customer notice and press
release and determined they complied with the Commission's Rules of Procedure 125.04 and
125.05. IDAPA 31.01.01.125. The customer notice was mailed with cyclical billings beginning
August 13,2013 and ending on September 12,2013.
Customer Comments
Customers were given until September 18, 2013 to file comments. As of September 6,
2013, one customer had submitted a comment. That customer says he opposes the increase
because the cost ofgas has declined and gas supplies are adequate.
Tariff Revisions
Staff identified several areas of Intermountain's tariffs that are in need of revision. For
example, the description of who is eligible to receive service under the two available residential
rate schedules is unclear. Intermountain has agreed to work with Staff in revising its rates
STAFF COMMENTS t2 SEPTEMBER 18,2013
schedules and discussing other changes that need to be made to update the General Service
Provisions section of its tariff. The Company has indicated that it will file proposed revisions
under a Tariff Advice for the Commission's consideration following the conclusion of this case.
Additionally, Staff is working with the Company to identi$r what actions the Company
takes to verify that customers are placed on the appropriate rate schedule when service is
initiated. Staff is also working with the Company to determine how the Company monitors
usage of existing customers to make sure they are billed under the most appropriate rate
schedule. For example, a residential customer on RS-l who adds a natural gas water heater
would benefit by switching to the RS-2 rate. Finally, Staff is reviewing the Company's customer
communications to determine how customers are made aware of available rate options. Staff
was unable to complete its investigation by the comment deadline in this case, and so has no
recommendations regarding these issues at this time. Staff will continue to work with the
Company and will report its findings to the Commission at a later date.
STAFF RECOMMENDATION
After thoroughly examining the Company's Application and gas purchases for the year,
Staff recommends the Commission approve the Company's Application and fiIed tariffs
increasing the annual revenue of Intermountain Gas Company by $10.3 million and establishing
a weighted average cost of gas at $0.3734 per therm. However, Staff recommends that in the
future the Company include the number of therms lost from all causes, not just from line breaks
on its workpaper summarizing the lost and unaccounted for gas statistics. Staff also recommends
the Company be required to bill the full retail rate to the responsible party when pricing the lost
gas due to a line break.
Respecttully submitted this i 8fl-day of September 2013.
Deputy Attorney General
Technical Staff: Matt Elam
Sandra Walker
Marilyn Parker
i :umisc/comments/avugl 2. 5kkmeswmp comments
STAFF COMMENTS 13
Klein
SEPTEMBER I8,2013
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 18TH DAY oF SEPTEMBER 2013,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT-G-13-05, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
MICHAEL P MoGRATH
DIR _ REGULATORY AFFAIRS
INTERMOUNTAIN GAS CO
PO BOX 7608
BOISE ID 83707
EMAIL: [e-mail]
MORGAN W RICHARDS JR
zuCHARDS LAW OFFICE
PO BOX 2076
BOISE ID 8370I
E-MAIL : [e-mail]
SECRETARY
CERTIFICATE OF SERVICE