20110921Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5156
f". ,.
R. ç: C E \ \d:: l-j~. .J
LO\1 SE? 2 \ P\~ 2: 26
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5983
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 (2011 )
PURCHASED GAS COST ADJUSTMENT). )
)
)
CASE NO. INT-G-11-01
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilties Commission, by and through its attorney of record,
Karl T. Klein, Deputy Attorney General, in response to the Notice of Application and Notice of
Modified Procedure (Order No. 32329) submits the following comments.
BACKGROUND
On August 11, 2011, Intermountain Gas Company fied its anual Purchased Gas Cost
Adjustment (PGA) Application requesting authority to decrease its anualized revenues by $14.4
milion, for an overall decrease of about 5.3%. Application at 2. The PGA mechanism is used to
adjust rates to reflect anual changes in Intermountain's costs for the purchase of natural gas
from suppliers, including transportation, storage, and other related costs. Reference Order No.
26019. The Company contends the proposed changes wil decrease its customer rates while not
affecting the Company's earings. Application at 2 and 4. The Company asks the Commission
to process the Applicatìon by Modified Procedure, and that the new rates take effect October 1,
2011. ¡d. at 9.
STAFF COMMENTS 1 SEPTEMBER 21, 2011
Intermountain seeks to pass-through to each customer class a net change in gas-related
costs resulting from (1) a cost increase biled to Intermountain by Northwest Pipeline GP
("Northwest" or "Northwest Pipeline"); (2) a cost decrease from Intermountain's "upstream"
pipeline suppliers and its storage facilties; (3) a decrease in Intermountain's weighted average
cost of gas ("W ACOG"); (4) an updated customer allocation of gas-related costs pursuant to the
Company's Purchased Gas Cost Adjustment provision; (5) the inclusion of temporar surcharges
and credits for one year relating to natural gas purchases and interstate transporttion costs from
Intermountain's deferred gas cost accounts; and (6) benefits included in Intermountain's firm
transportation and storage costs resulting from Intermountain's management of its storage and
firm capacity rights on various pipeline systems. Application at 3-4.
Intermountain proposes decreasing the W ACOG from $0.49211 per therm to $0.45342
per thermo The Application maintains that "(c)ontinued weakess in the regional and national
economies has put downward pressure on new customer growth and weather adjusted demand
for natural gas. At the same time, natural gas supplies are ample and U.S. dry gas production is
at an all time high. Robust supply coupled with flat demand has kept the near term prices for
natual gas relatively low." ¡d. at 5.
Pursuant to Order No. 32077, Intermountain included temporar surcharges and credits in
its October 1, 2010 prices to pass back to customers deferred gas cost charges and benefits.
Intermountain now seeks to eliminate the temporary surcharges and credits included in its
current prices during the past 12 months. The proposed changes would result in an overall price
decrease to Intermountain's customers. Application at 4 and 6.
The Company asserts that the proposed W ACOG includes the benefits resulting from
Intermountain's storage of significant amounts of natual gas "procured during the summer
season when prices are typically lower than during the winter, (making) the cost of
Intermountain's storage gas normally less than what could be obtained on the open market in
winter months." Additionally, and to further stabilze prices paid by customers during the
upcoming winter period, Intermountain has entered into fixed price agreements to lock-in the
price for significant portions of its underground storage and other winter "flowing" supplies. ¡d.
at 5.
The Company proposes allocating deferred gas costs from its Account No. 186 balance to
its customers through temporary price adjustments to be effective durng the 12-month period
ending September 30, 2012, as follows: (1) fixed gas costs credit of$5.9 milion attributable to
the collection of interstate pipeline capacity costs, the true-up of expense issues previously ruledSTAFF COMMENTS 2 SEPTEMBER 21, 2011
on by the Commission, and mitigating capacity release credits generated from the incremental
release of Intermountain's pipeline capacity; (2) deferred gas cost amounts of $12.2 milion
attributable to variable gas costs since October 1,2010; and (3) deferred gas costs related to lost
and unaccounted-for gas ("L&U"), which results in a net per-therm decrease to both sales and
transportation customers. ¡d. at 6-7.
Intermountain says it did not use a straight cents-per-therm price decrease for the L V-I
tariff. There are no fixed costs recovered in the tail block of the LV -1 tariff. The proposed
changes in the WACOG, and variable deferred credits (outlined in Exhibit 9) are applied to all
three blocks of the LV -1 taiff, but adjustments relating to fixed costs are applied only to the first
two blocks of the LV -1 tariff. Each block of the proposed LV -1, T -3, T -4 and T -5 tariffs include
a uniform cents-per-therm decrease to adjust for L&U. ¡d. at 7.
Intermountain notified customers about its Application through a customer notice and
press release. ¡d. at 8. The Company asserts that the proposed overall price changes reflect a
just, fair, and equitable pass-through of changes in gas-related costs to Intermountain's
customers. ¡d.
STAFF REVIEW
Staff reviewed the Company's Application and gas purchases for the year to verify that
the filing wil not change the Company's earings, that the deferred costs are prudent, and to
determine the reasonableness of the W ACOG request. The table below ilustrates how the
proposed decrease will impact the customer classes served by the Company:
STAFF COMMENTS 3 SEPTEMBER 21, 2011
Table: 1
Proposed Purposed Purposed Purposed
Change in Average Average Average
Class Change in %Price
Customer Class:Revenue $/Therm Change $/Therm
1 Residential (1,618,870)(0.04864)-5.13%0.89988
RS-2 Residentiai1 (6,047,561)(0.03444)-4.15%0.79476
GS-1 General Service1 (6,431,277)(0.06124)-7.65%0.73878
LV-1 Large Volume (81,735)(0.03026)-5.30%0.54099
T -3 Transportation (56,008)(0.00090)-5.27%0.01618
T -4 Transportation (124,102)(0.00090)-2.12%0.04147
T -5 Transportation (17,852)(0.00090)-3.02%0.02893
(14,377,405)-5.32%
The Company's proposed changes decrease Intermountain's anual revenue by
$14,377,405, as follows:
Table 2:
Deferrals:
Removal ofINT-G-10-03 Temporaries
Removal of INT -G-l 0-03 Lost and Unaccounted for Gas
INT-G-II-0l Temporaries
Total Deferrals
Lost and Unaccounted for Gas (INT-G-11-01)
Reallocation of fixed costs
Changes in the Weighted Average Cost of Gas
Fixed Cost Changes:
Northwest Pipeline
New Upstream Capacity Costs
Other Storage Facilties (Clay Basin) Cost Changes
Total Fixed Cost Changes
Total Annual Price Change
$21,459,356
$547,731
$(21,807,555)
$199,532
$(1,446,804)
$(1,116,356)
$(12,248,241 )
$1,034,554
$(543,569)
$(256,521)
$234,464
$(14,377,405)
i There were no thenn sales under the IS-R and IS-C tariffs. However, the IS-R price is based on the RS-2
December-March price and receives the same PGA adjustments and the IS-C price is based on the GS- i December-
March price and receives the same PGA adjustments.STAFF COMMENTS 4 SEPTEMBER 21,2011
Weighted Average Cost of Gas (WACOG)
Intermountain Gas proposes to reduce the WACOG from $0.49211 per therm to
$0.45342 per thermo This is a 7.86% decrease from the previous year's Commission-approved
PGA fiing (Commission Order No. 32077). Based on the following analysis, Staff believes (a)
the Company's methods are solid and accurate; (b) the proposed WACOG reduction compared
to the previous WACOG correlates with curent and future economic factors that influence the
natural gas market; and (c) the W ACOG value reasonably compares to benchmark market prices.
Staff recommends the Commission accept the Company's proposed WACOG. Staff also
recommends that the Company return to the Commission with a new fiing if prices significantly
deviate from the proposed rates during the upcoming year.
The WACOG is used to determine the rate changes proposed by the Company's PGA
filing. The Company estimates a volume-weighted average cost by averaging the sum of
forward natural gas prices multiplied by projected purchase volumes for each supply source and
contracting instruent the Company utilzes. First, forward natural gas prices are established for
each supply source using various future price indexes and forecasts adjusted by economic factors
that affect the natural gas market and by the Company's established purchasing practices. Then,
projected purchase volumes are allocated for each source and contract instruent considering
pipeline capacity constraints, curent contracts, and future prices.
The Company used an authorized WACOG of $0.49211 per therm to establish last year's
rates. Because the authorized rate exceeded actual gas cost, the Company over-collected about
$12.2 milion in revenue due to an overestimated WACOG. This amount is being netted out of
the 2011 PGA filing. Through the adjusted rates, the Company will credit the over-collection
back to customers over the next year.
Staff reviewed the Company's proposed WACOG in thee different ways. First, Staff
reviewed the Company's fiing to determine if the Company's methodology and calculations
were sound. Second, Staff analyzed trends in the Company's WACOG to understand if the
Company's proposal is reasonable given curent and future market conditions. Finally, Staff
analyzed whether the proposed W ACOG reasonably compares to third-part market prices.
STAFF COMMENTS 5 SEPTEMBER 21, 2011
Method and Accuracy Review
After completing the first par of the analysis, Staff concluded that the Company's
methodology is sound. However, Staff makes three recommendations for next year's filing:
1. Approval of the fixed cost collection rate for the upcoming year should be done
through the authorization of the Company's PGA proposal rather than through a
separate approval by Staff after the PGA has been authorized. The Company should
include all documents in the post PGA approval process as exhibits to the PGA fiing.
This will create procedural efficiency by eliminating an unecessary extra step.
2. The basis for determining how fixed gas costs are spread across customer classes uses
"peak day demand allocators" from a 1990 study. This study should be reviewed to
determine ifit remains valid given current conditions. However, beyond the age of the
study, there are no indications the allocation is invalid and should not be used for this
year's PGA application.
3. Staff auditors had difficulty locating and reviewing gas contracts and documents that
the Company used to develop the WACOG. Much of the problem can be attributed to
employee turover and a lack of organization. Staff recommends that the Company
establish a document control process for regulatory filings that is not person
dependent.
Market Trend Analysis
After analyzing the W ACOG trend given current and future market conditions, Staff
concluded that a continued trend for a decrease in the Company's WACOG is valid and
reasonable. As reflected in Char 1.0, the proposed WACOG, if approved, wil be the third
consecutive decrease. It is about equivalent to the 2003 W ACOG in nominal dollars.
STAFF COMMENTS 6 SEPTEMBER 21, 2011
Chart: 1.0
Intermountan Gas Weighted Average Cost of Gas
($/Term)
E
l
0.80000.7000 .............................._m.._..m.m..m..........
0.6000 .................................
0.5000
0.4000
0.3000
0.2000 .
0.1000
. Percent increase based On previou year's PGAfiing
.. Percent decrease based on December fiing
The Company's WACOG continues to decline for two reasons. First, the natural gas
industry expects relatively low near-term demand growt in both regional and national markets
due to lingering weak economic conditions as reflected in Chart 2.0.
Chart: 2.0
25000000
Natural Gas Consumption Trends
(National and Regional)900000
800000
700000 ~
600000 !
s:500000 if
400000
300000
it 20000000
:æ
:æ
; 15000000
10000000
~ 00 m 0 ~ N M ~ ~ ~ ~ 00 m 0 ~ N M ~ ~ ~ ~ 00 mmm mooooooooo 0 ~~~ ~ ~ ~~ ~ ~ ~~mmoooooooooooo 0 0 0 0 0 00 0~ ~ ~NNNNNNNN N NNNN N N NN NN N
-u.S. Consumption (EIA)- Pacific Northwest Consumption (NWGA)
In addition, the market supply of natural gas continues to grow in spite of lower natural
gas prices. This is due to reduced costs in accessing unconventional gas resources and the use of
newer more advanced driling technology.
Price Benchmark AnalysisSTAFF COMMENTS 7 SEPTEMBER 21, 2011
Staffs final analysis showed that the Company's proposed WACOG is conservative but
reasonably compares to other industry natural gas price benchmarks. Staff compared the
Company's projected monthly cost of purchased gas used in determining the proposed WACOG
to EIA's monthly forecasts2 and to NYMEX futues prices.3 For comparison purposes, Staff
calculated two volume-weighted cost of purchased gas estimates using volume allocation
percentages for the three hubs where Intermountain purchases gas.4 The first estimate used
NYMEXINGX futures prices and differentials based on August 26th settles; the second used
Company-adjusted price forecasts based on NYMEX INGX futures prices and differentials based
on August 3rd settles included in the PGA application.s
Chart: 3.0
This section of Staffs Comments contains confidential information
2 EIA, STEO (Sept 7, 201 I STEO), Table 5b. U.S.Regional Natural Gas Prices,
(htt://www .eia.gov /emeuisteo/pub/cC tab les/steotables.cfm ?tab leNum ber= i 6)3 Prices are based on settlements that occurred on August 26, 20 i I.
4 These allocation percentages are forecasts based on historical allocations supplied by the company through audit
requests. These are not the same allocations used in the WACOG calculation for the PGA.
5 Intennountain Gas is supplied by three natural gas hubs (Rockies, Sumas, & AECO). Futues settlement prices are
reported daily as a price differential from the NYMEX Henry's Hub price.STAFF COMMENTS 8 SEPTEMBER 21,2011
The analysis, ilustrated in Chart 3.0, shows the Company's monthly purchased gas cost to be
generally higher than Staff s estimates, especially during the winter months. Reasons for the
difference include:
. the softening of prices between the August 3rd settlement price used by the Company
and the August 26th settlement price used by Staff;
· the inclusion of a small amount of variable upstream transportation costs from
Canadian hubs embedded in the Company's purchased gas cost not included in Staffs
estimate;
. the Company assuming future monthly spot prices to be equivalent to term index
contract prices plus their adjustment factors;
· the Company allocating _ of its volume to the Rockies hub during summer
months (April though September) which curently has the second highest future price
between the three basins (see char 4.0 in the Pipeline Transportation section) while
Staffs estimates used the Company's projected allocations which are considerably
more realistic; and
· Intermountain Gas having. of its gas volume "locked in" during the winter
months (October through March) though the use of hedging strategies and contracts
which are currently greater than the futue indexed price of gas;
Although the Company's monthly purchased gas cost is generally higher than Staffs
estimates, the largest differences occur during the winter, mostly due to hedging. As discussed
in the next section, Staff believes the Company struck a good balance between price stabilty and
ability to take advantage of future bargain prices. In all, these factors combine to give
Intermountain's purchased gas cost and resulting WACOG a conservative bias. Given the level
of forecast error typical of future natural gas prices and EIA forecasts, the Staff considers the
Company's proposed WACOG reasonable.
Risk Management and Gas Purchasing
Intermountain Gas lowered its winter hedging ratios from. (used during the previous
two years) to.. This wil allow the Company to buy natural gas at lower prices than
purchases the Company would have obtained had it continued with previous ratios. The curent
situation provides an example of the continual review of risk management policies by the
Company and Staff. One question to consider now relates to the proper hedging ratio. With aSTAFF COMMENTS 9 SEPTEMBER 21,2011
proposed WACOG being reduced to 2003 nominal prices, it is Staffs opinion that the Company
took a conservative but appropriate position by allowing for increased opportunities to take
advantage of softening prices, while maintaining sufficient protection against increased market
prices.
The Company's risk management and purchasing strategies are dynamic, flexible, and
allow the Company to make decisions based on fundamentals of the natural gas environment.
The primary purose of the Company's purchasing strategies is to:
· ensure availabilty of adequate gas supplies to customers;
· mitigate the adverse impact of significant gas commodity price movements; and
· minimize the credit risk inherent in the implementation of certain price risk
reducing strategies.
The Company's Gas Supply Oversight Committee (GSOC) makes decisions by using
market fudamentals and management guidelines within the "Gas Supply Risk Management
Program" to evaluate the risk of price volatilty to customers. This includes decisions based on
weather and huricane forecasts, storage levels, dril rig counts, new Gulf of Mexico and shale
gas supplies, LNG levels, interstate pipeline transportation changes, and consumption patterns.
All of these factors affect how the Company (a) executes a given hedge strategy, (b) layers-in the
execution of a given hedge strategy, (c) fixes the price for a given time frame, or (d) utilzes
other forms of financial pricing.
So far, the Company's ability to dynamically adapt to market conditions continues to
offer customers savings and, more importantly, mitigate price volatilty by hedging intellgently.
For example, stagnant economic conditions and the Company's hedging strategies allowed the
Company to purchase gas for less than the current W ACOG set in rates during the past year.
This contributed to an over-collection of approximately $12.2 milion now being credited back to
customers during this year's PGA.
Temporary Surcharges and Credits
Pursuant to Order No. 32077, Intermountain included temporar credits in its October 1,
2010 prices to pass back to customers deferred gas cost charges and benefits. The temporar
credits consisted of three items: (1) a credit of about $3.8 milion in benefits generated by
releasing some pipeline transportation capacity; (2) an additional $2.1 milion credit attributable
to the collection of pipeline capacity costs, the true-up of expenses from the 2009 PGA, and
capacity release credits generated from the release of Intermountain's pipeline capacity; and (3)
STAFF COMMENTS 10 SEPTEMBER 21,2011
the $15.6 milion deferred credit balance, which is the difference from the commodity costs that
Intermountain actually paid for natural gas and the W ACOG that was included in rates. When
the temporary credit items are totaled to account for the drop in revenue proposed by the
Company, the credits total $21.5 milion. In the same case, Lost and Unaccounted for Gas
temporar credit deferrals were $600,000.
The new temporar credits also consist of three items: (1) a credit of about $3.7 milion
in benefits generated by releasing some pipeline transporttion capacity; (2) an additional $5.9
milion credit attributable to the collection of pipeline capacity costs, the true-up of expenses
from the 2010 PGA, and capacity release credits generated from the release of Intermountain's
pipeline capacity; and (3) the $12.2 millon 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. When the temporary credit items are totaled to account for the drop in revenue
proposed by the Company, the credits total $21.8 milion. However, when offset by the removal
of prior temporaries (including Lost and Unaccounted for Gas) the reduction in revenue is
$200,000. As shown on page 4, Table 2, the total reduction in revenue is $14.4 milion. This is
the combination of the current Lost and Unaccounted for Gas credit of $1.4 milion, the proposed
$12.2 milion revenue reduction due to the reduced W ACOG, additional fixed cost changes and
the $200,000 temporary surcharges and credits discussed above.
Natural Gas Storage
Intermountain uses 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.
Underground storage is typically used to fulfill the Company's winter storage needs and
acts as a hedge to shield consumers from higher winter natural gas prices. The Company has 95
milion therms in contracted underground storage capacity at Northwest Pipeline's Jackson
Prairie and Questar Pipeline's Clay Basin facilities. All of this capacity will be filled going into
the winter heating season. This represents. of the Company's November 2011 to March
2012 supply requirement. Through various supply agreements, these storage injections have
been locked in at prices ranging from $0.4080 to $0.4871 per thermo These rates bracket this
year's proposed W ACOG. Any overall differences will be reconciled in customer rates next
year.
STAFF COMMENTS 11 SEPTEMBER 21, 2011
The Company uses Liquid Natural Gas (LNG) storage throughout the year to meet
system peaks and to supplement local flows due to pipeline congestion or curtailments.
Intermountain has 18.5 milion therms in total LNG storage capacity at Northwest Pipeline's
Plymouth facilty and two Company-owned facilties in Nampa and Rexburg, Idaho. LNG
represents approximately. of the Company's total stòrage, however, the Company expects to
keep this below capacity throughout the winter. As of September 13,2011, the Company's LNG
storage was at approximately. capacity. Storing significantly more LNG than what is
expected to be used during the winter would come at an additional expense to ratepayers because
of Intermountain's cost to maintain LNG at a specific temperature.
Pipeline Transportation
Intermountain delivers transported natural gas to its Idaho 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 utilzing
capacity on Gas Transmission Northwest (GTN), TransCanada's Foothils Pipeline system
(Foothils), and its Alberta system known as Nova Gas Transmission (Nova). Intermountain's
pipeline capacity rates for Nova decreased in 2011, resulting in a decrease of approximately
$500,000. Northwest Pipeline updated its rates effective April 4, 2011. Traditionally, Northwest
Pipeline and other fuel providers change rates anually, but these annual changes do not largely
affect the price Intermountain charges to customers. The pipeline transportation rate biled to
Intermountain remains unchanged. Contractual terms with Northwest Pipeline increased daily
volume as well as capacity costs by approximately $1 milion. Capacity on these pipelines
remains a key component in serving customers and maintaining supply diversity. Intermountain
wil also determine when its contracted interstate transportation is under-utilized due to warmer
weather or declines in industrial demand. This capacity wil be posted for release to others with
the release payments received benefiting Intermountain customers.
Intermountain's proximity to several interstate pipelines allows it to effectively allocate
its natual gas supply mix from different basins based on price differentials, and to subsequently
redeliver that specified volume on its own distribution pipeline network at the lowest possible
price. Intermountain has traditionally sourced a higher percentage of gas from the Rockies
Basin, because of Northwest Pipeline's close proximity to the Company's service territory and
lower price.
STAFF COMMENTS 12 SEPTEMBER 21,2011
The recent completion of the Rockies Express (November 2009) and Ruby (July 2011)
pipelines has opened access of Rockies Basin natural gas to the East and to the West,
respectively. There are indications that this is changing the market that the Company uses to
source its gas by increasing competition and price for Rockies Basin gas while decreasing
competition and the price of gas out of Alberta Canada (AECO-C) as shown in Char 4.0.
Chart: 4.0
Future Settlement Prices - August 26th Settle
Average Price (Oct. '11 - Sept. '12)
AECO-NGX
(Ll
$4.1154
Rotkles-Nymex
(K)
5umas.Nymex
(J)
Last year, approximately. of the Company's gas was purchased from the Rockies
Basin, with the remaining. coming from Canada ~ from Sumas in British Columbia;
. from AECO in Albert). This proportion is lower than in past years when the percentage
from the Rockies Basin was in the _ range indicating that the Company is shifting its
sources in response to changing market conditions.
Recovery of Lost and Unaccounted for Gas
L&U is the difference, or variance, between the physical purchase of natural gas from
suppliers and the volumes biled to customers. Intermountain asks to the recover L&U through a
per therm surcharge that is considered above and beyond that which is included in Commission-
approved base rates from 1985. Due to concerns that the Company's requests for L&U recovery
was becoming excessive, the Commission placed a 0.85% cap on allowed L&U as a percentage
of total throughput. Order No. 30649. The Commission also ordered the Company to submit
quarerly reports outlining (1) the Company's framework for how it has tested for, identified, and
remediated equipment measurement errors or leaks; and (2) the business process for alleviating
measurement errors through its financial accounting of nominations, scheduling, measurements,
flow volume allocation, and biling.
STAFF COMMENTS 13 SEPTEMBER 21, 2011
Table 3.0 below shows the Company's L&U estimates submitted in the past three PGA
applications along with the percentage change in these estimates experienced over the same time
period.
Table: 3.0
% Change
Annual from
L&UGas6 14 L&U PreviousThroughput
Year Time Period (Therms)(Therms)(% of Throughput)Year
2007 Oct '06 - Sept '07 3,700,000 513,583,000 0.72%n/a
2008 Oct '07 - Sept '08 4,800,000 559,313,840 0.86%19.1%
2009 Oct '08 - Sept '09 2,414,773 531,960,560 0.45%-47.1%
2010 Oct '09 - Sept '10 1,077,361 549,583,146 0.20%-56.8%
2011 Oct '10 - Sept '11 -894,032 563,763,803 -0.16%-180.9%
This year the Company is in a "found gas" position, with 894 thousand therms more of
gas being metered into Intermountain's service area than were metered at the point of
consumption. The Company says this can happen if measurement error occurs on the high side
at Intermountain's city gates and/or on the low side at the customer's meter, even if the error is
within acceptable tolerances. Because the absolute value of L&U as a percent oftotal yearly
throughput is below what was reported last year, this may indicate that the amount of
measurement error is improving and the measures the Company has put into place to improve on
reducing L&U are working.
The Company has continued to meet requirements stipulated in Order No. 30649 by
filing semi-anual reports mentioned earlier. One of the measures the Company has taken to
identify potential leaks, identify errors, or find faulty meters is to audit and flag potentially
inaccurate biling data, which can then be investigated furher to determine root cause through a
"check-for-dead" meter order. During 2010, the Company performed 12,441 "check-for-dead"
biling audits and found approximately 4.8% of meters were dead or had drive/pressure related
issues. This percentage has gone down from both 2008 and 2009, which respectively had 14.7%
and 8.9% of meters with issues.
In 1985, the Commission established $0.00182 per therm as the normalized unit cost that
can be collected as par of base rates. This past year, the total normalized level ofL&U gas
6 See INT-G-I 1-01, INT-G-09-02, INT-G-08-03, and INT-G-08-04 fiing.
STAFF COMMENTS 14 SEPTEMBER 21, 2011
embedded in base rates yields an amount of$I,026,050 ofL&U already collected.7
Intermountain wants to reimburse the sum of the total estimated October 2010 to September
2011 L&U gas of $480,202 (which is negative due to its "found gas" position) and the
$1,026,050 normalized level ofL&U gas revenue already collected in current base rates. This
yields a total of $1 ,506,252, which the Company asks be passed back to customers.
Staff recommends that the Commission allow the Company to refud $1,506,252 to
customers for L&U requested in this PGA. This is based on amounts the Company has already
collected and the amount of estimated L&U gas from this past year. Furhermore, results are
showing that concerns about higher than normal L&U are being addressed. Although the
Company has reduced L&U, Staff recommends that the Company continue to submit semi-
annual L&U reports for review. Staff also maintains its view that losses due to errors in faulty
meters or measurement control practices should not be recovered in the PGA; however, the
Commission would expect the Company to file for an accounting order authorizing the Company
to defer the costs of repair and the cost of lost gas in the event of a catastrophic failure. Finally,
Staff recommends the Commission maintain the maximum L&U gas recovery at 0.85% of total
throughput as specified in Order No. 30649.
CUSTOMER RELATIONS
Customer Notice and Press Release
The Customer Notice and Press Release were included in Intermountain's Application.
The Application was received on August 11, 2011. Staff reviewed the customer notice and press
release and determined they complied with ¡PUC Rules of Procedure 125.04 and 125.05.
IDAPA 31.01.01.125. The customer notice was mailed with cyclical billngs beginning August
12,2011 and ending September 14,2011.
Customer Comments
Customers were given until September 21,2011 to fie comments. As of September 19,
one comment had been received. Although the customer misunderstood what was driving
Intermountain Gas to decrease its rates, the customer was nevertheless pleased with a rate
decrease.
7 This is shown on Workpaper NO.8 included in the Company's PGA application.
STAFF COMMENTS 15 SEPTEMBER 21,2011
Financial Assistance for Paying Heating Bils
If approved, residential customers wil see an approximate 5% decrease in their natural
gas rates. Nonetheless, energy costs continue to challenge some customers. Because some
customers stil struggle to make ends meet, Staff would like to remind qualified customers to
take advantage of the energy assistance available through the federally-funded Low Income
Home Energy Assistance Program (LIHEAP) and non-profit fuel funds such as Project Share in
southwestern Idaho and Project Warth and Helping Hand in southeastern Idaho. For more
information on these programs, customers may call the nearest Community Action Agency,
Intermountain Gas Company, the Idaho Public Utilties Commission, or the 2-1-1 Idaho Care
Line.
STAFF RECOMMENDATION
After examining the Company's Application and gas procurements for the year, Staff
recommends that the Commission accept the Company's Application and fied tariffs decreasing
the Company's anual revenue by approximately $14.4 milion and establishing a WACOG at
$0.45342/therm. Staff further recommends that the Commission continue to require semi-annual
L&U gas reports and maintain a cap for L&U gas recovery at 0.85% of total throughput.
':
Respectfully submitted this 1-\day of September 2011.
K~I)5$-- 1l
Deputy Attorney General
Technical Staff: Shelby Baker
Mike Louis
Marilyn Parker
i:umisc/comments/intgl I. I kkphsbmkmp comments
STAFF COMMENTS 16 SEPTEMBER 21, 2011
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 21sT DAY OF SEPTEMBER 2011,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT-G-II-0l, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
SCOTT MADISON
VP & CHIEF ACCT OFFICER
INTERMOUNTAIN GAS CO
PO BOX 7608
BOISE ID 83707
STEPHEN R THOMAS
MOFFATT THOMAS ET AL
STE 1000
101 S CAPITOL BLVD
BOISE ID 83702
Jo~
SECRETA~~
CERTIFICATE OF SERVICE