20120920Comments.pdf

NEIL PRICE
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 6864
RE CE I \/ E 13
?U!2SEP2O P1 2:86
c,
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE ANNUAL
PURCHASED GAS ADJUSTMENT (PGA) ) CASE NO. INT-G-12-01
FILING OF INTERMOUNTAIN GAS )
COMPANY. ) COMMENTS OF THE
) COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission, by and through its Attorney of Record,
Neil Price, Deputy Attorney General, in response to the Notice of Application, Notice of Modified
Procedure and Notice of Intervention Deadline, issued on September 5, 2012, Order No. 32632,
submits the following comments.
BACKGROUND
On August 10, 2012, Intermountain Gas Company ("Intermountain" or "Company") filed its
annual Purchased Gas Cost Adjustment ("PGA") and requested a Commission Order, pursuant to
Idaho Code §§ 61-307 and 61-622, to institute new rate schedules which will decrease its
annualized revenues by $6.0 million. Intermountain attached copies of its current rate schedules
and proposed rate schedules to its Application.
Intermountain's Application also seeks to refund approximately $11.9 million of variable
deferred credits through a one-time credit. It is proposing to divide the credit balance by actual
STAFF COMMENTS 1 SEPTEMBER 20, 2012
sales volumes over the time period it was generated to arrive at the per therm credit. The calculated
credit would be reflected as a line item on customer bills in December 2012.
Intermountain's Application lists the following cost variations that it seeks to pass-through
to each of its customer classes:
(1) an increase in costs billed Intermountain from Northwest Pipeline GP
("Northwest" or "Northwest Pipeline") reflecting a January 1, 2013 price
increase and the purchase of additional Northwest capacity, (2) a decrease in
Intermountain's weighted average cost of gas, or "WACOG," (3) an updated
customer allocation of gas related costs pursuant to the Company's PGA
provision, (4) 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 (5) benefits resulting from
Intermountain's management of its storage and firm capacity rights on various
pipeline systems. Intermountain also seeks with this Application to eliminate the
temporary surcharges and credits included in its current prices during the past 12
months, pursuant to Order No. 32372 per Case No. INT-G-1 1-01.
The net effect of the above changes would result in an overall price decrease to Intermountain' S
customers.
Intermountain claims that its proposed price changes 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 as
well as any volumetric adjustments in contracted transportation agreements which have occurred
since Intermountain's last PGA filing, Case No. INT-G-1 1-01.
Intermountain's Application states that natural gas prices have continued to fall. Record
storage levels combined with ample natural gas supplies have kept the near-term prices for natural
gas low.
Intermountain states that it has entered into various fixed price agreements to lock-in the
price for significant portions of its underground storage and other winter "flowing" supplies.
Intermountain seeks to pass through to its customers the benefits that will be generated from
the management of its transportation capacity totaling $3.7 million. Further, Intermountain's
proposal seeks to allocate deferred gas costs from its Account No. 186 balance to its customers
through temporary price adjustments to be effective during the 12-month period ending September
30, 2013.
Intermountain states the Company provided notice of the proposed changes to its tariff
schedules through the issuance of a formal Customer Notice and Press Release.
STAFF COMMENTS 2 SEPTEMBER 20, 2012
Intermountain proposes an effective date for the proposed changes of October 1, 2012.
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 to determine the reasonableness of the WACOG request.
In this year's PGA, the Company is proposing to credit a grand total of approximately $17.9
million to customers. Approximately $11.9 million of this total is being passed back to customers
as a one-time credit on their December bill. This amount is the difference between the actual cost
of purchased gas and the WACOG embedded in rates during the period of July 2011 through June
of 2012. An additional $6.0 million in revenue is being passed back to customers through an
average decrease in rates of 2.4% starting October 1, 2012. This is primarily due to a continued
decline in the future cost of purchased gas. The combination of both credits provides customers
with an overall price decrease of 7.1%.
The table below illustrates how the proposed decrease will impact the customer classes
served by the Company:
Table 1
Proposed Proposed Proposed Proposed
Change in Average Average Average
Class Change in % Price
Customer Class: Revenue $ITherm Change $!Therm
I Residential $ (129,157) (0.00375) -0.43% 0.86083
RS-2 Residential' (4,257,533) (0.02371) -3.12% 0.73575
GS-1 General Service (2,390,316) (0.02206) -3.14% 0.68142
LV-1 Large Volume (165,981) (0.05126) -10.14% 0.45443
T-3 Transportation 304,548 0.00419 25.90% 0.02037
T-4 Transportation 594,418 0.00419 10.10% 0.04566
1-5 Transportation 77,952 0.00419 13.61% 0.03498
$(5,966,069) -2.37%
The overall effect of the proposed changes in the Company's Application is a decrease in
annual revenue received by Intermountain Gas Company of $5,966,069. This decrease is
comprised of the following items:
'There were no therm 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- 1 December-March price
and receives the same PGA adjustments.
STAFF COMMENTS 3 SEPTEMBER 20, 2012
Table 2
Deferrals:
Removal of INT-G-1 1-01 Temporary Credits $ 21,807,555
Removal of[NT-G-ll-0l Lost and Unaccounted for Gas $ 1,446,804
INT-G-12-0l Temporary Credits $ (9,816,649)
Total Deferrals $ 13,437,710
Lost and Unaccounted for Gas (INT-G-12-01) $ 2,138,220
Reallocation of fixed costs $ (261,440)
Changes in the Weighted Average Cost of Gas $ (27,099,859)
Fixed Cost Changes:
Northwest Pipeline $ 6,255,437
New Upstream Capacity Costs $ (644,033)
SGS & LS Changes $ 50,223
Other Storage Facilities Cost Changes $ 157,673
Total Fixed Cost Changes $ 5,819,300
Total Annual Price Change $ (5,966,069)
Weighted Average Cost of Gas (WACOG)
Intermountain Gas proposes to reduce the WACOG from $0.4181 per therm to $0.3349 per
therm. This is a 19.9% decrease from the WACOG authorized in the Company's December 2011
WACOG decrease filing that went into effect on February 1, 2012 (Commission Order No. 32450),
and a 26.1% decrease from the WACOG approved in the normally scheduled 2011 PGA that went
into effect on October 1, 2011 (Commission Order No. 32372). 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 current and future economic factors
that influence the natural gas market; and (c) the proposed WACOG reasonably compares to
benchmark market prices. Staff recommends the Commission accept the Company's proposed
WACOG. However, Staff recommends that the Company return to the Commission with a new
filing if prices materially 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
STAFF COMMENTS 4 SEPTEMBER 20, 2012
gas prices multiplied by projected purchase volumes for each supply source and contracting
instrument the Company utilizes. 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 instrument considering pipeline
capacity constraints, current contracts, and future prices.
Because previously authorized WACOG's (INT-G- 11-03, INT-G-1 1-01, and INT-G-10-03)
embedded in rates exceeded actual gas cost, the Company over-collected an estimated $13.2 million
in variable cost in spite of filing a WACOG decrease authorized on February 1, 2012. The
Company proposes reimbursing customers for $11.9 million of this amount through a one-time
credit on their December bill (See section on "One-time Credit" under Customer Relations). The
remaining amount is proposed to be netted out of the 2012 PGA filing through adjusted rates over
the next year.
Staff reviewed the Company's proposed WACOG in three different ways. First, Staff
reviewed the Company's filing to determine if the Company's methodology and calculations were
sound. Second, Staff analyzed trends in the Company's WACOG to judge whether the Company's
proposal is reasonable given current and future market conditions. Finally, Staff analyzed whether
the proposed WACOG reasonably compares to third-party market prices.
Method and Accuracy Review
After completing the first part of the analysis, Staff believes that the Company's
methodology is sound and that the calculations in the filing are accurate. In addition, Intermountain
Gas has implemented two improvements from recommendations Staff made in last year's
comments related to the Company's methods. First, approval of the fixed cost collection rate was
incorporated as part of the Company's PGA filing rather than through a separate approval by Staff
after the PGA is authorized. Second, the Company has organized gas contracts and documents that
the Company used to develop the WACOG so that Staff can more easily locate and review them;
however, transportation and storage contracts were not easily traceable to figures in the PGA and
could use improvement.
From a review of this year's filing, Staff recommends the Company include all electronic
versions of exhibits and workpapers as part of its initial filing. This will assist the Commission
Staff in expediting processing the application.
STAFF COMMENTS 5 SEPTEMBER 20, 2012
Market Trend Analysis
After analyzing the WACOG trend given current and future market conditions, Staff
concludes that a continued trend for a decrease in the Company's WACOG is reasonable. As
reflected in Chart 1, the proposed WACOG, if approved, will be the sixth consecutive decrease. It
is about equivalent to the 2002 WACOG in nominal dollars.
Chart 1
*
Weighted Average Cost of Gas
($flbenii)
%Changebasedon previous reguIartyscheduIedPGAttjng ** %thange based onprevious Decemberflng
There are several factors that have driven the price of gas to the lowest levels seen in over
ten years, all related to continued soft demand and a steady supply of working natural gas. This is
reflected by the amount of gas in storage nationally which is currently 13.1% higher than this time
last year and 10.7% higher than the 5-year average.2 Factors include:
• Continued weak economic conditions;
• A mild winter of 2011-2012;
• A prolific increase in the supply of shale and unconventional gas;
• An increase in the amount of natural gas from oil drilling; and
• Storage balances filled to capacity sooner than expected.
One of the biggest factors is related to a lack of demand pressure on prices. Weak national
and regional economic conditions have persisted since the recession as reflected by the relatively
2 EIA, Natural Gas Weekly, September 5, 2012.
STAFF COMMENTS 6 SEPTEMBER 20, 2012
low near-term demand growth in both regional and national natural gas markets as forecasted by the
EJA and Norwest Gas Association (See Chart 2 below). However, one trend to watch over the next
few years is an increase in natural gas use for electricity generation which has increased 7.2% over
last year's figures.3 Electric utilities are increasingly relying on natural gas generation to fill
baseload needs vacated by retirement of aging coal plants and the cost-prohibitive option of
building new coal plants to meet future needs that can meet new federal emission control
regulations.4
Chart 2
Natural Gas Consumption Trends
(National and Regional)
30000000 -------------------------------- 900000
800000
25000000 _..____ ...
700000
20000000 .................................................................................................................. 600000
500000
15000000
400000
10000000 rnrn 300000
r- CO 0, C I C11 CV) 'fl (.0 r.. CO 0) —( r4 CV) LV) (.0 CV- CO 0)
-I —I .—I r- r-4 (.J CV,l CV4 (.J c.I CV4 c- r-1 (.1 r-1 r.J r.1 r-4 r-J CV.J r.4 r-J CJ
U.S. Consumption (EIA) -Pacific Northwest Consumption (NWGA)
On the supply side, production of natural gas continues to grow in spite of lower natural gas
prices. This is due to reduced costs in accessing shale and other non-traditional gas resources and
the use of newer more advanced drilling technology which has increased well productivity. In fact,
EIA reports increases in dry shale gas production even though the number of active rigs show a
steady decline over the same period.5
EIA, U.S. consumption of natural gas by end use, Sept. 7, 2012 STEO:
(http://www.eia.gov/emeu/steo/pub/cftables/steotables.cfin?tableNumber=8) in bold and italics; all others from Annual
Energy Outlook 2012: (http://www.eia.gov/oiaf7aeo/tablebrowser/)
' The primary regulations driving reduced coal plant investment includes Mercury and Air Toxics Standard Rules
(MATS), Regional Haze Rules (BART), and EPA's proposed Carbon Pollution Standard.
See HA Natural Gas Weekly Update, week ending September 5, 2012.
STAFF COMMENTS 7 SEPTEMBER 20, 2012
Price Benchmark Analysis
Staff compared the Company's projected monthly cost of purchased gas used to determine
the proposed WACOG to EIA's monthly forecasts and to NYMEX futures prices.7 Staff believes
that the Company's proposed WACOG is conservative but reasonably compares to recognized
natural gas price benchmarks.
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.8 The first estimate used NYMEXINGX futures prices and differentials based on August 20
settles; the second used Company-adjusted price forecasts based on NYMEX/NGX futures prices
and differentials based on August 3rd settles included in the PGA Application.9
Chart 3
Monthly Weighted Cost of Gas Comparison
($/Dtherm)
$3.8000
$3.6000
$3.4000
$3.2000
$3.0000
$2.8000
$2.6000
$2.4000
$2.2000
Oct-12 Nov-12 Dec-12 Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13
Wtd. Cost of Purchased Gas (IGCPGA filing)
* - ElAHenry's Hub Spot Price (AugSTEO)
- - - NYMEX Henry Hub- NN Today's Settle 8/26/11
• Wtd. Cost of Purchased Gas (NYMEX data/PUC method)
J. Wtd. Cost of Purhased Gas (lGCdata / PUC method)
The analysis, illustrated in Chart 3, shows the Company's monthly purchased gas cost to be
generally higher than Staff's estimates, especially during the early winter months (October and
ELA, STEO (Sept 7, 2012 STEO), Table 5b. U.S.Regional Natural Gas Prices, (http://www.eia.gov/emeulsteo/pub
/cftables/steotables.cfiri?tableNumber= 16)
Prices are based on settlements that occurred on August 20, 2012.
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.
Intermountain Gas is supplied by three natural gas hubs (Rockies, Sumas, & AECO). Futures settlement prices are
reported daily as a price differential from the NYMEX Henry's Hub price.
STAFF COMMENTS 8 SEPTEMBER 20, 2012
November) and summer months (April through September). The two factors contributing the
largest differences are: (1) the sourcing of higher priced Rockies index-priced gas that is $0.26 per
therm more expensive than index-priced gas sourced from AECO; and (2) price premiums
embedded in the price of hedged contracts.
The first factor is reflected by the Company's WACOG sourcing more than 50% of its
index-priced gas from higher priced Rockies basin and only 17% from price-leader AECO (See
Chart 4). This is compared to Staff's estimates of 30% for Rockies and 65% from AECO.
However, the Company is contractually obligated to take delivery of Rocky Mountain index gas due
to long-term contracts that have been in place for several years. Beyond contractual obligations,
Staff believes this is prudent in spite of paying a higher price by maintaining source diversity that
contributes to assurance of supply through pipelines that the Company has reserved capacity.
Chart 4
Future Settlement Prices - August 20th Settle
Average Price (Oct. '12 - Sept. '13)
AECO-NGX
(1)
Rockies-Nymex
(K)
Sumas-Nymex
(J) $33681
The second factor can be attributed to price premiums and costs embedded in the price of
hedged contracts and purchasing strategies. The Company has 59% of its gas volume "locked in" at
prices that are generally greater than current natural gas futures prices. As will be discussed in the
next section, Staff believes the Company struck a good balance between price stability, protecting
consumers from higher price risk, and ability to take advantage of future bargain prices. Given all
of these factors, Staff believes that the Company's proposed WACOG is reasonable and
recommends approval.
Risk Management and Gas Purchasing
As discussed earlier, there are several factors that have pushed natural gas prices to the
lowest levels seen in over ten years. However, there are indications that prices have approached
STAFF COMMENTS 9 SEPTEMBER 20, 2012
the bottom of the pricing cycle and there is a greater than average upward price risk as reflected by
NYMEX futures price confidence intervals published by EIA'° and high and low price forecasts by
the Northwest Power Conservation Council."
Through a review of the Company's Application and current purchased gas contracts, Staff
believes that Intermountain has made adjustments in its hedging ratios to match current market
conditions and to protect consumers from future upward price risk. The table below compares the
proposed WACOG hedging ratios with those from the past two regularly scheduled PGA filings. In
comparison to previous years, it illustrates how the Company has reduced its hedging ratios over the
winter months to match continued soft prices in the near term, while increasing its hedging ratios
substantially through the summer months in anticipation of higher prices. Although the Company
has increased its ratios, Staff believes it has done so conservatively to allow opportunities to take
advantage of continued soft prices without having to pay premiums required for price certainty.
Table 3
Winter Months (Oct-Mar.)
Summer Months (Apr.-Sept.)
Full Year
% Locked-in Gas by PGA Year
2010 I 2011 J 2012 Proposed
68.1% 69.4% 63.3%
28.7% 0.0% 44.5%
58.5% 52.4% 59.0%
In addition, the Company is actively reviewing current and future market conditions through
its Gas Supply Risk Oversight Program and is acting accordingly to protect customers from future
upward price risk even beyond the current PGA year. Staff is supportive of these reviews given that
the focus of the Commission through the PGA is primarily to look at one-year snapshots.
So far, the Company's ability to dynamically adapt to market conditions continues to offer
customers savings and, more importantly, mitigate price volatility by hedging intelligently. As
evidence, stagnant economic conditions and the Company's hedging strategies allowed the
Company to purchase gas for less than the current WACOG set in rates during the past year. This
contributed the previously mentioned over-collection of approximately $13.2 million now being
credited back to customers during this year's PGA.
'° See EIA, Short-Term Energy Outlook, August 2012, futures price confidence intervals.
See Northwest Power Conservation Council, Update to the Council's Forecast of Fuel Prices, August 2011.
STAFF COMMENTS 10 SEPTEMBER 20, 2012
Temporary Surcharges and Credits
Pursuant to Order No. 32372, Intermountain included temporary credits in its October 1,
2011 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: (1) a credit of approximately
$3.7 million in benefits generated by releasing some pipeline transportation capacity; (2) an
additional credit of $5.9 million 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 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. When the temporary credit items are totaled to account for the
drop in revenue proposed by the Company, the credits total $21.8 million. In the same case, Lost
and Unaccounted for Gas temporary credit deferrals was $1.4 million.
The new temporary credits consist of three separate items: (1) 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 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. When the temporary credit items are totaled to account for the
drop in revenue proposed by the Company, the credits total $9.8 million. However, when offset by
the removal of prior temporaries (including Lost and Unaccounted for Gas) the reduction in revenue
is $13.4 million. As shown on page 4, Table 2, the total reduction in revenue is approximately $6
million. This is the combination of the current Lost and Unaccounted for Gas credit of $2.1 million,
the proposed $27.1 million revenue reduction due to the reduced WACOG, additional fixed cost
changes and the $13.4 million temporary surcharges and credits discussed above.
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.
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 million
STAFF COMMENTS 11 SEPTEMBER 20, 2012
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 38% of the Company's November 2012 through April 2013 supply
requirement. Through various supply agreements, these storage injections have been locked in at
prices ranging from $0.2375 to $0.3852 per therm. These rates bracket this year's proposed
WACOG. Any overall differences will be reconciled in customer rates next year.
The Company utilizes 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 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 approximately 15% of the Company's total storage; however, the Company expects to
keep only 50% of its LNG capacity full throughout this winter. Storing significantly more LNG
than what is expected to be used during the winter would come at an additional expense to
customers because of Intermountain's cost to maintain LNG at a specific temperature.
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). Intermountain's pipeline capacity rates
decreased in 2012 resulting in a decrease of approximately $600,000. Northwest Pipeline settled its
pre-filed rate case with FERC and will update its rates effective January 1, 2013. Contractual terms
with Northwest Pipeline increased daily volume as well as capacity costs by approximately $6
million. Capacity on these pipelines remains a key component in serving customers and
maintaining supply diversity. Intermountain will also determine when its contracted interstate
transportation is under-utilized due to warmer weather or declines in industrial demand. This
capacity will 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
natural 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.
STAFF COMMENTS 12 SEPTEMBER 20, 2012
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.
However, this has changed over the past year. The 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. This has changed 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).
Recovery of Lost and Unaccounted (L&U) for Gas
L&U is the variance between the physical purchase of natural gas from suppliers and the
volumes billed to customers over the PGA year. Intermountain asks to 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.
This year the Company is in a "lost gas" position with 4.5 million therms more of gas
flowing through customer's meters than into Intermountain's service area. This represents a 0.76%
L&U rate approaching the 0.85% cap of L&U as a percentage of total throughput allowed under
Order No. 30649. This, in addition to large swings in L&U percentages year-to-year, caused Staff
to examine potential root causes. Based on its examination, Staff believes that L&U for this year's
PGA is accurate and has been adjusted properly for errors in faulty meters and/or measurement
control practices. Staff recommends that the Commission allow the Company to surcharge
customers $2,060,867 for L&U requested in the PGA. This is based on amounts the Company has
already collected and the amount of estimated L&U gas from this past year.
Because this year's L&U was approaching the 0.85% cap and because of relatively large
swings in the L&U from year-to-year, Staff investigated the causes for some of the variation. Staff
discovered that the Company had found an error that affected a large customer's bill for
approximately the past three years. If not caught, the Company would have been over the cap this
year. By adjusting the past three years, L&U rates would have changed from previous filings
reducing the size of year-to-year variation as reflected in the table below.
STAFF COMMENTS 13 SEPTEMBER 20, 2012
Table 4
PGA
Year
Lost Gas Rate
(% of Throughput)
% Change
(from previous yr)
Adjusted Lost Gas Rate
(% of Throughput)
% Change
(from previous yr)
2007 0.72% n/a 0.72% n/a
2008 0.86% 29.7% 0.86% 19.1%
2009 0.44% -36.8% 0.57% -48.6%
2010 0.20% -36.3% 0.35% -55.5%
2011 -0.16% -104.3% -0.01% -181.2%
2012 1.19% -5528.9% 0.76% -849.6%
Note: Historical rates are actual; 2012 rate includes 3 mos. of estimates.
The Company has continued to meet requirements stipulated in Order No. 30649 by filing
semi-annual L&U reports. The Company has expressed interest in reviewing L&U through their
integrated resource plan rather than through semi-annual reports; however, Staff believes the
Company needs to be able to quantify normal causes of variation with fully capable measuring
equipment and processes before shifting to less frequent reviews. Because a "normal" amount of
losses have not been determined, Staff recommends the Company continue to submit semi-annual
L&U reports for review until the Company can propose a better way to monitor losses to identify
causes of variation and subsequently make appropriate adjustments.
In 1985, the Commission established $0.00182 per therm as the normalized unit cost that
can be collected as part of base rates. This past year, the total normalized level of L&U gas
embedded in base rates yields an amount of $1,078,618 of L&U already collected. 12 Intermountain
wants to collect the difference between the $1,078,618 normalized level of L&U gas revenue
already collected in current base rates and the total estimated October 2011 to September 2012
L&U gas of $3,139,485. This yields a total of $2,060,867 that the Company requests to be
surcharged to customers.
Finally, Staff recommends the Commission maintain the maximum L&U gas recovery at
0.85% of total throughput as specified in Order No. 30649.
12 This is shown on Workpaper No. 8 included in the Company's PGA application.
STAFF COMMENTS 14 SEPTEMBER 20, 2012
CUSTOMER RELATIONS
One-Time Credit
The PGA mechanism is generally designed to reallocate the difference between actual and
forecasted cost of purchased gas embedded in rates between the Company and its customers. When
actual cost is greater than the Company's forecast, customers are surcharged. When actual cost is
less than the forecast, customers receive a credit. Once the PGA is approved by the Commission,
the forecasted price of gas is embedded into the customer's rates and the surcharge or credit is
reallocated as customers pay for additional gas they consume during the upcoming year.
Because of rapidly falling gas prices and the Company's conservative forecast estimates for
purchased gas cost over the period of July 2011 through June 2012, an $11.9 million balance has
accumulated to be credited back to customers. Instead of reimbursing customers over the next PGA
year by embedding the credit in rates as is normally done, the Company is proposing to credit the
balance back to customers as a single payment in the customer's December bill. Each customer's
credit will be determined by multiplying their actual usage from July 2011 through June 2012 by a
$0.03877 per therm rate. This rate was calculated by dividing the $11.9 million owed back to
customers by the Company's total actual sales volume (307.9 million therms) over the same period.
Based on this calculation, residential (RS-1) and multiple use residential (RS-2) customers
can expect an average $19.40 and $29.85 one-time credit, respectively. Commercial customers
(GS-1) can expect a $129.80 credit on the average.
Staff agrees with the Company's method for calculating the credit. Furthermore, Staff
supports the one-time credit over the normal PGA method for three reasons. First, it returns money
to customers sooner. Second, the credit is based on each customer's usage during the time period
that the credit accumulated and therefore more accurately and equitably reimburses customers for
actual costs incurred. Finally, it will provide rate stability by not allowing an unusually large credit
balance to artificially push rates lower than would normally occur, lessening the likelihood of a
large increase the following year.
Customer Notice and Press Release
The Customer Notice and Press Release were included in Intermountain's Application. The
Application was received on August 10, 2012. Staff reviewed the customer notice and press release
and determined they complied with IPUC Rules of Procedure 125.04 and 125.05. IDAPA
STAFF COMMENTS 15 SEPTEMBER 20, 2012
31.01.01.125. The customer notice was mailed with cyclical billings beginning August 14, 2012
and ending on September 14, 2012.
Customer Comments
Customers were given until September 21, 2012 to file comments. As of September 13,
2012, no comments had been received.
Financial Assistance for Paying Heating Bills
If approved, residential customers that have both a natural gas furnace and water heater will
see a 3.1% decrease in their rates; customers that use natural gas for heating only will see a 0.4%
decrease in their rates. Even though all customers will see a decrease in rates, energy costs continue
to challenge some customers. Staff would like to remind qualified customers to take advantage of
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 Warmth 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 Utilities Commission, or the 2-1-1 Idaho Care Line.
STAFF RECOMMENDATIONS
After a careful examination, Staff recommends that the Commission accept the Company's
PGA Application and filed tariffs, decreasing the Company's annual revenue by approximately
$5,966,069 and establishing a WACOG of $0.3349 per therm. In addition, Staff recommends that
the Commission:
• Authorize a one-time credit on customers' December bill at a $0.03877 per therm
rate based on actual customer usage from July 2011 through June 2012.
• Require the Company to continue to submit semi-annual L&U gas reports until the
Company can propose a better method of identifying and correcting non-normal
losses.
• Maintain a 0.85% cap for L&U recovery.
STAFF COMMENTS 16 SEPTEMBER 20, 2012
Respectfully submitted this of September 2012.
Neil Price
Deputy Attorney General
Technical Staff: Shelby Hendrickson
Mike Louis
Marilyn Parker
i:umisc:comments/intgl 2.1 npshmlmp comments
STAFF COMMENTS 17 SEPTEMBER 20, 2012
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 20TH DAY OF SEPTEMBER 2012,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT-G-12-01, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO
THE FOLLOWING:
SCOTT MADISON
VP & CHIEF ACCT OFFICER
INTERMOUNTAIN GAS CO
P0 BOX 7608
BOISE ID 83707
[e-mail]
LORI.BLATTNER(intgas.com
STEPHEN R THOMAS
MOFFATT THOMAS ET AL
P0 BOX 829
BOISE ID 83701-0829
E-MAIL: [e-mail]
SECRETA
CERTIFICATE OF SERVICE