20140917Comments.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 83702-59I8
Attorney for the Commission Staff
IN THE MATTER OF INTERMOUNTAIN GAS
COMPANY'S APPLICATION FOR
AUTHORTTY TO CHANGE ITS PRICES (2014
PURCHASED GAS COST ADJUSTMENT).
f-'rnrrr rr_ !_,i"-i-1,-ir./1..1
?0lt' SIP I ? Pl{ l: Zl
tr|rrt,-1 ...t.1' '^rtgt t: J I _ L,
: ; TlLl i,:,:j'- -r; ,',r :S,5lOltl
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
CASE NO. INT.G.14-01
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on
Intermountain Gas Company' s Application.
BACKGROUND
On August S,2ll4,Intermountain Gas Company (the "Company") filed its annual
Purchased Gas Cost Adjustment ("PGA") Application. The PGA adjusts 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 asks
the Commission to let it recover its increased gas costs through new PGA rates that would
increase its annualized revenues by $6.7 million (about 2.64%).
The Company says the proposed changes would not affect its eamings. But they would
increase overall prices for customers. More specifically, the Company says residential customers
using gas for space and water heating would see a $1.89/month (3.81%) average increase,
customers using natural gas only for space heating would see a $ 1 .40/month (3.64%) average
increase, and commercial customers would see a $0.3l/month (0.15%) average increase.
STAFF COMMENTS SEPTEMBER 17,2014
The Company says its proposed PGA rates incorporate all changes in costs relating to the
Company's firm interstate transportation capacity including, but not limited to, any price changes
or projected cost adjustments implemented by the Company's pipeline suppliers and any
volumetric adjustments in contracted transportation agreements that have occurred since the
Company's last PGA filing, Case No. INT-G-13-05.
The Company proposes increasing the Weighted Average Cost of Gas to be recovered
through new PCA rates (WACOG) from the currently approved $0.37341 per therm to $0.39482
per therm. The Company says while there are significant shale gas reserves, modest
improvements in the economy and an increase in natural-gas-fired electric generation have
increased demand and caused natural gas prices to rise. 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 agreements that lock-in its price for significant
portions of its underground storage and other winter "flowing" supplies.
The Company seeks to provide its customers with $3.9 million in benefits that will be
generated from the management of the Company's transportation capacity, as outlined on
Exhibit No. 7 to the Application. The Company also proposes temporarily adjusting prices for
l2-months - until September 30, 2015 - to 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 reflects credits
associated with liquefied natural gas (LNG) sales from the Company's Nampa, Idaho facility.
The Company proposes an October 1,2014 effective date for the new PGA rates.
STAFF ANALYSIS
Staff has thoroughly reviewed the Company's Application and gas purchases for the year
and has verified that the Company's PGA proposal would not change the Company's earnings,
that the Company's deferred costs are prudent, and that the Company's WACOG request is
reasonable.
In this year's PGA, the Company proposes increasing customer rates by about $6.7
million, or 2.64Yo. This increase is due to the pass through of transportation costs billed to the
Company from firm transportation providers, an increase in the Company's weighted average
cost of gas, an updated customer allocation of gas-related costs under the Company's PGA
provision, the inclusion of temporary surcharges and credits for one year relating to natural gas
STAFF COMMENTS SEPTEMBER 17,2OI4
purchases and interstate transportation costs from the Company's deferred gas cost accounts, and
benefits resulting from the Company's management of its storage and firm capacity rights on
various pipeline systems. Temporary surcharges and credits included in the prior year's PGA
have also been eliminated. Table No. I shows how these changes would increase overall prices
for the Company's customer classes:
Table 1:
Customer Class:
Proposed
Change in
Class
Revenue
Proposed
Average
Change in
$/Therm
Proposed
Average o/"
Change
Proposed
Average Price
$/Therm
RS-1 Residential $ 1.0s6.10s 0.03188 3.64%0.90887
RS-2 Residential $5.1 12.890 0.02911 3st%0.79373
GS-1 General Service $ I14.82s 0.00107 0.ts%0.7319s
LV-l Laree Volume $ 83.8s8 0.0153 8 2.94%0.78063
T-3 Transoortation $ 122.319 0.00158 9.42%0.0183s
T-4 Transoortation $ 176,147 0.00102 2.43%0.04307
T-5 Transportation s 25.790 0.00134 92.41%0.00279
$6.691.934 2.64(,/0
Table No. 2 shows how the overall effect of the proposed changes would increase the
Company's annual revenue by $6,691,934.1 This increase consists of the following items:
I The difference between the totals reflected on Table No. I
attributed this difference to rounding.
STAFF COMMENTS 3
and Table No. 2 is $1,555. Intermountain Gas has
SEPTEMBER 17 ,2014
Table 2:
Weighted Average Cost of Gas (WACOG)
The WACOG is the Company's average variable cost to buy and transport gas to satisff
its customers' estimated annual gas needs. The WACOG includes the volumetric interstate
transportation rate and city gate costs. It does not include fixed capacity costs for interstate
transportation, liquid storage, and underground storage. The WACOG is about 660/o of the
Company's total annual gas cost.
By the time the PGA is filed each year, the Company has injected most of its gas into
storage for withdrawal during the heating season. Consequently, the Company's estimated cost
of gas in storage when it files the PGA is usually close to the Company's actual cost, because
most of those costs are "locked-in" and won't change due to market conditions.2 According to
the Company, about 30Yo of the Company's storage injections that can be withdrawn during the
heating season have been managed at a WACOG of $0.38431 per therm. Similarly, the price of
some "flowing gas supplies" may be known because they are already hedged.3 The Company
also advises that, by mid-August, about 38% of its flowing gas supplies for the heating season
were hedged at a WACOG of $0.38527 per therm. Combined, about 68% of the Company's
2 "Locked-in" means that the gas price is fixed and won't change due to market conditions.
3 "Flowing gas supply" is gas purchased using hedges or spot market purchases. It does not include stored gas.
Deferrals:
Removal of INT-G-13-05 Temporarv Credits and Charses $9.833. I 75
Fixed Defened Gas Costs s( 15.3 16.555)
Variable Defened Gas Costs $s,343,108
Total Deferrals s(140.272\
Fixed Cost Chanses:
Full Rate Demand Changes so.242.657\
Discounted Demand Chanses $ 1.108.717
Upstream Capacitv Cost Changes $26r,441
Other Storase Faciliw Cost Chanses $(489,915)
Total Fixed Cost Chanses s( l -362.414)
Lost and Unaccounted for Gas $634.067
LNG Sales Credit s(40s.441
Re-allocation of Fixed Costs $ l ,083,s l4
Chanses in WACOG $6.884.035
Total Annual Price Change s6.693.489
STAFF COMMENTS SEPTEMBER 17,2OI4
weather normalized throughput for the heating season has been hedged at a WACOG of
$0.38516. The supplies that have not been hedged are estimated based upon an independent,
third-party price forecast. The Company anticipates its remaining throughput needs will be at a
slightly lower WACOG. With the additional fuel charges to move gas at the city gate, plus some
variable transport costs, administrative fees and contributions, the Company's proposed
WACOG is $0.39482 per therm. As reflected in Chart 1, the proposed WACOG will be the
second increase following several years of consecutive decreases.
Chart I
E
o
ir}
Welghted Average Cost of Gas ($/Therm)
0.7000
0.6000
0,5000
0.4000
0.3@0
0,2600
0.1000
7\,/ \ar t
-rJ \
"v \r;n 7"---
'oo 'o1 '02 '03 '04 '05 '06 '07 '08 'o8.
Dec.'09+ r '10 '11 '114
Dec,'12. *'13 't4
Prop.
WACOG
($/rherm)0.286 0.388 0.320 0.475 0.554 o.712 0.585 0.635 o.784 0.674 0.496 0.492 0.453 0.418 o.334 0.373 0.394
0.8000
' 70 Change based on previous regulrly scheduled PGA liling
'i 70 Change based on previous Decembcr filing
Market Fundamentals & Price Analysis
Even though most of the Company's forecasted throughput has already been hedged or
injected into storage at fixed prices, changes in market conditions can still impact the WACOG.
Consequently, Staff closely analyzed the Company's projected monthly cost to buy 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).4 Overall, the
2014-2015 forecasts are consistent, predicting relatively stable near term gas prices. A few
factors that might cause uncertainty include: l) Increased gas-fired electric generation; 2)
a Staff used the most recent EIA Annual Energy Outlook 2014, the NWGA's 2014 Gas Outlook, and the NWPCC's
Revised Fuel Price Forecasts for the Seventh Power Plan.
STAFF COMMENTS SEPTEMBER 17,2OI4
Increased demand for exports of LNG from Canada and the United States; and 3) Increased
demand from gas-to-liquid projects.
The EIA projects Henry Hub prices to decrease in 2015 from an average price of
$4.46A4MBtu in 2014 to $4.00/lvIMBtu in 2015. Similarly, the NWPCC's medium case
scenario predicts Henry Hub prices in 2015 to drop slightly, from $4.73lMMBtu in20l4 to
$4.59/MMBtu in 2015. The Company buys most of its gas from the AECO basin, which this
year is discounted by about 10% compared to Henry Hub Futures prices.
Staff developed its own forecast using the NYMEXAIGX Futures prices at each of the
three hubs where the Company buys gas. Using the Company's estimated volume allocation
percentages for these three hubs, Staff forecasts the volume-weighted cost of gas to be
$3.6816/MMBtu. The Company's forecasted mainline fuel cost of $3.8263/MMBtu is
comparable to Staffls forecast. The Company's proposed WACOG of $3.9482lMMBtu is
slightly higher than its mainline fuel cost because the proposed WACOG includes variable
interstate transportation costs, British Petroleum (BP) administrative fees, and Gas Research
Institute (GRI) contributions. Based on Staff s review of the market, the Company's weighted
average cost of its current hedges, and the Company's estimated cost of forward-looking index
purchases, Staff believes that the Company's proposed WACOG of $0.39482 per therm is
reasonable. Staff recommends that the Commission accept the proposed WACOG and direct the
Company to return to the Commission with a new filing if prices materially deviate from
proposed rates during the upcoming year.
Risk Management
Staff evaluated the Company's operations to determine whether the Company bought gas
at market prices and whether the Company minimized risk to ratepayers. Staff paid particular
attention to how the Company manages price and risk given the Company's market purchases,
storage, and interstate transportation capacity.
The Company supplies its mainline requirement with hedges, spot market purchases and
underground storage. Underground storage lets the Company buy gas for the winter during the
summer when gas typically costs less. The Company also sells LNG from its above-ground
storage facility to provide customers with a $405,411 PGA credit while still using the LNG to
meet its customers' peak day gas needs. When opportunities are available, the Company
STAFF COMMENTS SEPTEMBER 17 ,2014
continues to manage its interstate transportation capacity so it can sell surplus capacity in the
market.
Overall, the Company's strategy for managing its resource portfolio continues to provide
price stability for customers. The Company's approach is flexible, which allows it to be
opportunistic in buying gas, managing storage, and using interstate transportation capacity if
market conditions change.
Purchasing
Staff reviewed the Company's purchasing strategies to see whether the Company
reasonably changed them to meet current market conditions. When compared to last year, the
Company plans to buy about the same percentage of its mainline throughput requirement using
index or spot purchases. About 28.3% of the Company's total throughput is now index or spot
purchases, compared to 28.6Yo last year. The Company's hedged supply went from 42.9Yo of
total throughput last year to 44.1% this year. Including the Company's storage gas, aboutT2o/o
of its total throughput is essentially hedged.
The Company has increased its hedging ratios during the summer months, but decreased
its hedging ratios in the non-summer months. According to the Company, prices dropped low
enough in the summer to meet its trigger prices. Table 3 compares the Company's proposed
WACOG hedging ratios with those from the past four regularly scheduled PGA filings.
Table 3
Non-Summer Months (Oct.-Mar.)
Summer Months (Apr.-Sept.)
FullYear
' 7o Locked-in gas includes storage volumes that are both hedged and index purchascs.
Staff believes the Company's hedging ratio adjustments match current market conditions,
particularly given that natural gas is expected to be used more for electric generation, which
could cause short term variability in summer prices. The Company continues to rely on its index
% Locked-in Gas by PGA Year*
2010 207L 20L2 2013 20L4
69
0
52
68
29
59
63
45
59
79
48
77
74
63
72
STAFF COMMENTS SEPTEMBER 17,2014
or spot purchases, but Staff believes the Company can react to upward price risk given that most
of the Company's hedged volumes are locked-in at reasonable prices.
Natural Gas Underground Storage
The Company uses two underground storage facilities: Jackson Prairie owned by
Northwest Pipeline, and Clay Basin owned by Questar. These facilities' combined capacity is
about 94 million therms. This year, the Company credited $489,915 after the Company changed
its asset manager for part of Clay Basin storage. The credit issued because the Company's new
Asset Management Agreement excludes cycling costs and increases the market value of the
Company's storage gas when it is not needed, which consequently lowers the Company's overall
payment for storing gas at Clay Basin.
The capacity ofunderground storage is fixed. In general, underground storage capacity
becomes a proportionately smaller piece of the Company's potential hedging strategy as
throughput increases. The Company decides whether to serve load using storage withdrawals
based on the price of its locked-in hedges and its forecasted spot market prices. Customers
typically benefit from underground storage because the Company can buy low-priced gas during
the summer for use in the winter, when prices are generally higher. Storage also provides system
peaking capacity for unusually high demand events or backup for potential pipeline disruptions
and curtailments.
Staff reviewed the Company's strategy for utilizing underground storage, specifically
focusing on whether changes from last year make sense given the market fundamentals. When
compared to last year, the Company plans to use storage to meet about the same percentage of
total throughput. Last year, storage gas served approximately 28.5Yo of total throughput,
whereas this year it is expected to serve 27A% of total throughput. The Company plans to
withdraw slightly less of its underground storage because its hedged supply is locked in at prices
comparable to the storage WACOG, plus it expects spot market prices to remain low. Staff
supports the Company's decision to rely less on underground storage, particularly given its
hedges are locked at reasonable rates and current market forecasts indicate stable prices and mild
winter weather.
STAFF COMMENTS SEPTEMBER 17,2OI4
Inter s tat e Tr anspor tation
The Company delivers domestically produced natural gas to its city gates through
Northwest Pipeline, an interstate transportation provider whose pipeline runs through the
Company's service territory. 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 (NOVA).
The Company continues to lower its fixed costs by managing its interstate transportation
capacity. For example, this year the Company replaced some of its year-round capacity with
winter-only capacity, and purchased discounted capacity to match its upstream take-away
capacity at Stanfield. Combined, this saved customers 5872,499 and allowed more deliverability
into Northwest Pipeline at the Stanfield receipt point. This allows the Company access to
Alberta based supplies, which the Company currently believes will deliver the lowest priced
supply in future months.
Whenever the Company has surplus capacity because demand is low, it sells that capacity
at the highest market price available that day. All benefits made from these sales are credited to
customers. Staff analyzedthe Company's historical capacity release revenue to see how that
revenue varies annually. The Company's total capacity release revenue this year is about $11
million, which consists of revenues from firm capacity releases on a segment of Northwest
Pipeline and from non-segmented upstream capacity releases on pipelines delivering gas from
Canada. Over all, Staff discovered the capacity release revenue generated during the 2013 PGA
year was considerably higher than it was in most other years as shown inChart2:
STAFF COMMENTS SEPTEMBER 17,2014
Chart2
Historical Transportation Capacity Release Revenue
s16,000,000
514,000,000
s12,000,000
51o,ooo,ooo
s8,000,000
s6.000.000
s4.000.000
s2,000,000
Sol
2O08 PGA
5 Revenue S 5,091.114
2OO9 PGA
59,801,314
2O1O PGA
s 7.789,081
2o1r P6A 20-14 PGA
I'rop.
5r4,721.,s46 S11.046,219
According to the Company, slow economic growth contributes to higher capacity release
revenue. The increased revenue occurs because the Company has more surplus capacity to sell
because customers are using less gas, and because some marketers try to remain financially
viable by giving up the capacity they've previously nominated. Consequently, fewer parties hold
available capacity to meet demand or sell in the marketplace in competition with the Company,
which makes it more likely that the Company's extra capacity will be purchased by others.
The Company seems to actively manage its capacity, but Staff encourages the Company
to continue aggressively marketing its surplus capacity when it is available, particularly given
that the Company is ideally positioned geographically to take advantage of liquidity at the
various purchase points it utilizes.
Recovery of Lost and Unaccounted for Gas (LAUF Gas)
LAUF Gas is the difference between the volumes of natural gas delivered to the
distribution system at the city gate and volumes of natural gas billed to customers at the meter.
The Company recovers LAUF Gas amounts through a per therm surcharge if the amount is
above what was included in Commission-approved base rates. Conversely, the Company credits
customers if the amount is below what was included in base rates.
This year, the Company estimates about 2.9 million therms of LAUF Gas, or 0.48o/o of
total throughput, below the maximum allowable amount of LAUF Gas specified in Commission
STAFF COMMENTS l0 SEPTEMBER 17,2014
Order No. 30649.s The total normalized level of LAUF Gas embedded in base rates yields
$1,110,982 of LAUF Gas already collected.6 The Company wants to collect the difference
between the $1,110,982 normalized level of LAUF Gas already collected through base rates and
the total estimated October 2013 to September 2014LAUF Gas of $1,174,738. The difference,
or the under-collection, will be a$63,756 surcharge to customers. When the true-up amounts
from last year are included, the Company is proposing to surcharge customers a total of
$634,066 for LAUF Gas. This surcharge collects the difference between last year's LAUF Gas
estimate of 1,977,331 therms, and the Company's actual LAUF Gas of 3,328,777 therms. Last
year's forecasted LAUF Gas was about .323% of throughput, while the Company's actual LAUF
Gas was about .548% of throughput (still under the Commission's LAUF Gas cap of .85% of
throughput).
Each year, to retrospectively audit the Company's actual LAUF Gas percentage of
overall throughput, Staff typically requests a modified version of Workpaper No. 8. Since a
portion of each year's LAUF Gas and throughput is estimated due to the filing date of the PGA,
the modified workpaper allows Staff to review a full year of actual LAUF Gas to ensure the
LAUF Gas percentage of overall throughput is less than the cap. Going forward, the Company
has agreed to provide a workpaper in its Application that retrospectively looks at the actual
LAUF Gas percentage of overall throughput.
Line Break- Lost and Unaccountedfor Gas
Staff investigated the Company's LAUF Gas Reports to determine whether the
Company's calculations were accurate. The Company completes Gas Loss Reports when known
leaks and line breaks occur between the citygate and customers' meters. The reports include an
estimate of gas that escapes from the pipeline during the break. At the end of the year, the lost
gas is totaled up and subtracted from the annual LAUF Gas statistics. The reports are also used
to calculate the cost billed to the responsible party, which also reduces annual PGA costs.
Before this year, the Company only used the WACOG to price the lost gas but excluded
the Company's fixed costs to transport the gas through pipelines and the cost of the Company's
t The Company uses actual LAUF Gas results through July and estimates the amount of LAUF gas from August
through September. Commission Order No. 30649 caps the Company's allowable LAUF gas at .85% of throughput.
6 In I 985, the Commission established $0.001 82 per therm as the normalized unit cost that can be collected for
LAUF Gas as part of base rates.
1lSTAFF COMMENTS SEPTEMBERIT,2OI4
storage facilities. In Case No. INT-G-13-05, Staff raised concerns about the Company's pricing.
In response, the Commission stated: "in the future the Company shall bill the full retail rate to
the responsible party when pricing lost gas due to a line break." Order No. 32897. This year, in
most instances, the Company priced all gas from line breaks using the WACOG rate, plus the
Residential Schedule No. I (RS-1) fixed costs of interstate transportation and storage.
According to the Company, it believes the Commission's intent when referring to the "full retail
rate" was to have the Company include the WACOG, in addition to the fixed cost of interstate
transportation and storage, when pricing lost gas due to a line break. According to the Company,
using the full retail rate would be administratively burdensome for pricing lost gas, particularly
when the party responsible for the line break is not a customer. Overall, Staff agrees that it is
less burdensome to have one rate apply to all responsible parties, particularly given the majority
of gas lost due to line breaks was the cause of parties who were not customers. The full retail
rate may also include costs that are unrelated to the per therm cost of a line break, or occur
downstream of the line break (e.g. - meter costs, A&G, O&M, ROR, taxes etc.). Staff
recommends that in the future the Company bill the responsible party for a line break by pricing
lost gas using the WACOG and the RS-l fixed cost of interstate transportation and storage.
Similar to last year, this year Staff discovered instances where the Company
inadvertently charged the incorrect rate for gas lost due to line breaks. Specifically, in some
instances, the Company continued only using the WACOG to bill the responsible party.
According to the Company, Staff s review has caused it to reevaluate its internal process for
pricing the lost gas due to a line break. In the future, the Company will make its Engineering
Department responsible for reconciling the impact of lost gas due to line breaks. Previously, the
Company had two separate departments reconciling the impact of lost gas due to line breaks,
which apparently caused errors. Also the Company now plans to hard code the price of gas into
an electronic system, so the price remains static throughout the PGA year and need not be
manually entered by field personnel each time. After meeting with the Company to discuss its
LAUF Gas Reports, Staff believes the Company's administrative changes will correct errors that
have occurred the last few years. The Company's calculation errors are small and will not
impact customers. Staff thus believes the Company's LAUF Gas amount is reasonable.
STAFF COMMENTS t2 SEPTEMBER 17,2014
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 occurred in 1990. But since the 2012 PGA, the Company has used a peak
day that occurred December 2009 to allocate the volume-weighted average costs of gas.
According to the Company, the update from the 1990 peak-day allocators to the 2009 peak-day
allocators appreciably impacted the customer class allocations.
Through discovery, Staff leamed the Company exceeded the December 2009 peak day
usage in December 2013. According to the Company, updating the allocation factors to the
December 2013 peak day would have an immaterial impact. Regardless, Staff believes the
Company should use the more recent peak day. The Company's decision to update its demand
allocation factors for class cost-of-service should not be subjectively determined. Staff
recommends that in the future the Company update its peak demand allocation factors in the
PGA filing following a new peak day.
CUSTOMER RELATIONS
The Company's press release and customer notice were included with the Application.
Staff reviewed both documents and found one technical deficiency. The press release and
customer notice did not include all of the information required by the Commission's Rules of
Procedure (IDAPA 31.01.01). Rules 125.01.c and 125.04 require a utility to inform customers
that a copy of the utility's application is available for public review at the offices of the utility.
The Company's offices are not open to the public, but its application is available on the
Company's website. At its Decision Meeting on August 18,2014, the Commission accepted
Staff s recommendation that the Commission deem the Company's posting of the application on
its website to substantially comply with Rule 125. See Order No. 33099, fn 1.
The customer notice was included with bills mailed to customers beginning August l3
and ending September 11,2014. Customers have the opportunity to file comments on or before
September 17.
As of September I l, the Commission has received four comments. All opposed to the
proposed increase.
In comments filed in last year's PGA case (INT-G-13-05), Staff discussed its concerns
about the Company's tariff and noted that the Company had agreed to work with Staff to revise
STAFF COMMENTS l3 SEPTEMBER 17,2014
its rate schedules and the General Service Provisions. The Commission approved a substantial
revision earlier this year, and Staff anticipates that the Company will file rate schedule revisions
shortly after the conclusion of this case.
In last year's comments, Staff indicated that it was working with the Company to better
understand what actions the Company takes to verifu that customers are billed under the most
appropriate rate schedule. Staff examined the Company's procedures for reviewing rate
classification as well as its audit process for identifying meter/equipment failures. As a result of
Staffls discussions with the Company, the Company modified its procedures and audit
parameters, and plans to continue to refine and improve its processes. The Company also
revised its summary of rules and rates mailed to customers annually. The srmlmary describes the
eligibility requirements for each customer class, and advises customers to contact the Company
if there has been a change in appliances that would affect their rate classification.
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 filed tariffs to
increase the Company's annual revenue by $6,693,489 and establish a WACOG of $0.39482 per
therm. However, Staff recommends that when the Company bills the responsible party for a line
break in the future, the Company should price lost gas using the WACOG and the RS-l fixed
cost of interstate transportation and storage. Furthermore, Staff recommends that in the future
the Company update its peak demand allocation factors in the PGA filing following a new peak
day.
Respecttully submitted this I ?-'1 day of September 2014.
Karl T. Klein
Deputy Attorney General
Technical Staff: Matt Elam
Donn English
Daniel Klein
i:umisc/comments/intgl4. lkkmededk comments
STAFF COMMENTS l4 SEPTEMBER 17 ,2014
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 17TH DAY oF SEPTEMBER 2014,
SERVED THE FOREGOTNG COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT.G.I4-01, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWNG:
MICHAEL P MoGRATH
DIR - REGULATORY AFFAIRS
INTERMOUNTAIN GAS CO
PO BOX 7608
BOISE ID 83707
E-MAIL: [e-mail]
RONALD L WILLIAMS
WILLIAMS BRADBURY PC
IO15 W HAYS ST
BOISE ID 83702
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE