20150916Comments.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:
472 W , WASHINGTON
BOISE, IDAHO 83702-5918
Attomey for the Commission Staff
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BEFORE THE IDAHO PUBLIC UTILITTES COMMISSION
IN THE MATTER OF INTERMOUNTAIN GAS
COMPANY'S APPLICATION FOR CASE NO. INT.G.Ts.O2
COMMENTS OF THE
COMMISSION STAFF
AUTHORITY TO DECREASE ITS PRTCES (2015 )
PURCHASED GAS COST ADJUSTMENT).
The Staff of the Idaho Public Utilities Commission comments as follows on
Intermountain Gas Company's Application.
BACKGROUND
On August 7,2015,Intermountain Gas Company (the "Company") filed its annual
Purchased Gas Cost Adjustment ("PGA") Application. The PGA adjusts rates each year to
reflect changes in the Company's costs to buy natural gas from suppliers-including
transportation, storage, and other related costs. See Order No. 26019. A change in the PGA does
not affect the Company's earnings. But a PGA change can cause customer rates to go up or
down. With this Application, the Company proposesto decrease overall prices for customers
and decrease the Company's annualized revenues by $15.3 million (5.69%).
In summary, the Company proposes to pass through to customers gas-related cost
changes that would decrease the average bill of: (l) residential customers who use natural gas
for space heating and water heating, by $3.12lmonth (6.1 1%); (2) customers who use gas for
space heating only, by $1.36/month(3.56%); and (3) commercial customers by $12.15/month
(5.66%). The Company proposes that the new rates take effect October l, 2015.
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STAFF COMMENTS SEPTEMBER 16,2015
The Company explains 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 the Company's last PGA filing, Case No. NT-G-14-01.
The Company notes that its Application includes $1.4 million related to the Company's
acquisition of more liquefied natural gas ("LNG") storage capacity at its Plymouth facility on
Northwest Pipeline's delivery system. The Company acquired incremental Plymouth capacity of
378,900 MMBtu with a daily deliverability of 41,975 MMBtu. The Company states that the
Plymouth facility has been a valuable asset given its ability to help ensure supply and delivery to
customers.
The Company proposes decreasing the weighted average cost of gas used to calculate its
PGA rates ("WACOG") from the currently approved $0.39482 per therm to $0.32764 per therm.
The Company explains the existence of significant North American shale reserves and slow
growth of the nation's economy contributed to the WACOG decrease, and that natural gas
supplies combined with significant storage balances have kept natural gas prices lower than they
were just a year ago. The Company states that it has entered into fixed price agreements to lock
in the price for significant portions of its underground storage and other winter "flowing"
supplies.
The Company seeks to pass through to its customers, as per therm credits, $3.9 million
that will be generated from the management of its transportation capacity. The Company also
proposes to temporarily adjust prices for 12 months - until September 30,2016 - to allocate
deferred gas costs from its Account No. 191, including: (1) a fixed gas cost debit of $1.1 million;
(2) avariable gas cost debit of $0.7 million; and (3) a Lost and Unaccounted For Gas ("LAUF
Gas") credit of $76,166.
The Company states that the proposed overall price changes reflect a just, fair, and
equitable pass through of changes in gas-related costs to the Company's customers. The
Company states that it has notified customers about the Application and price changes through a
formal Customer Notice and a Press Release.
STAFF COMMENTS SEPTEMBER 16,2015
STAFF ANALYSIS
Staff examined the Company's Application and gas purchases for the year. Staff
confirms that the Company's PGA proposal would not change the Company's earnings, the
Company's deferred costs are prudent, and the Company's WACOG is reasonable.
In this PGA filing, the Company proposes lowering customer rates which will decrease
the Company's annualized revenuesby 5.69Yo or $15.3 million. The Company explains that the
gas-related cost changes result from: (l) transportation costs billed to the Company by Northwest
Pipeline GP, an interstate gas transportation provider whose pipeline runs through the
Company's service teritory; (2) a decrease in the Company's WACOG, (3) an updated customer
allocation of gas-related costs under 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 the Company's deferred gas cost accounts; and (5) benefits resulting
from the Company's management of its storage and firm capacity rights on various pipeline
systems. Tables I and2, below, summarize the Application's proposed changes by customer
class and their effects on the Company's overall base rates and prices:
Table l: Summary of proposed changes
Customer Class:Revenue
Change
$ Per Therm
Change
%o Average
Change
Average Price
S/Therm
RS-l Residential s(1,118,517)(0.03233)-3.56%$0.87654
RS-2 Residential $(8,875,757)(0.048s 1)-6.t1%$0.74s22
GS-l General Service s(4,580,524)(0.04146)-5.66%$0.69049
LV-l Large Volume $(248,722)(0.04284)-7.97%$0.49494
T-3 Transportation $(l 17,637)(0.001s2)-8.28%$0.01683
T-4 Transportation $(354,247)(0.00206)-4.78Yo $0.0410 r
T-5 Transportation $(30,876)(0.00168)-60.22%$0.001 I I
$(15,326,280)(0.02s48)-5.690/0 s0.422s6
STAFF COMMENTS SEPTEMBER 16,20I5
Table 2: Effect of proposed changes
Deferrals:
Removal of INT-G-14-01 Temporary Credits and Charges $10,114,746
Additional INT-G-15-02 Temporary Credit and Charges
Fixed deferred Gas Costs g(2,889,972)
Variable Deferred Gas Costs $696,361
Lost and Unaccounted for Gas $(989,783)
LNG Sales Credit $(68e.367)
Total Additional Temporary Credit and Charges $3.872.761
Totsl Defefials $6,241,985
Fixed Cost Changes:
NWP Full Rate Reservation s I ,545,062)
NWP Discounted Reservation $(483,850)
Upstream Full Rate $(525,768)
Upstream Discounted $748,71 I
SGS & LS $1,390,722
Total FLYed Cost Changes $2,674,877
Re-allocation of Fixed Costs $(1,815,042)
Changes in WACOG $(22,428,100)
Totsl Buse Rote Changes $(2 I .s68.265)
Total Annual Price Change $(r 5,326,280)
Weighted Average Cost of Gas (WACOG):
The WACOG is the Company's average variable cost to buy and transport gas to satisfy
its customers' estimated annual gas requirements. The WACOG includes the volumetric
interstate transportation rate, city gate costs, IGI Resources administrative fees, and Gas
Technology Institute (GTI) charges. It does not include fixed capacity costs for interstate
transportation, liquid storage, and underground storage. The WACOG is roughly 68% of the
Company's total annual gas cost. The WACOG proposed price is $0.32764 per therm which is
$0.0671 8 per therm lower than the price of $0 ,39482 per therm reflected in current tariffs.
The Company injects most of its natural gas into storage for use during the following
heating season before filing the annual PGA. Consequently, the Company's estimated stored-gas
cost when it files the PGA is similar to its actual stored-gas cost, because most of those costs are
locked-in and will not fluctuate with the market. The Company maintains that it can withdraw
STAFF COMMENTS SEPTEMBER I6,20I5
about 28Yo of its storage injections during the heating season at a WACOG of $0.3413 per therm.
Similarly, the Company can obtain about 39Yo of its weather normalized throughput for the
heating season from "flowing gas supplies" that have been hedged at a WACOG of $0.3088 per
therm. The supplies that have not been hedged are estimated based upon an independent, third-
party price forecast. Chart l, below, describes the WACOG:
Market Fundamentals & Price Analysis
Although the Company has hedged or stored most of its forecasted throughput at fixed
prices, market fluctuations can impact the WACOG. Staffthus analyzed the Company's
projected cost to purchase natural gas. Staff compared the Company's forecast to forecasts from
national and regional organizations, including the Energy Information Administration ("EIA"),
the Northwest Gas Association ("NWGA"), and the Northwest Power and Conservation Council
("NWPCC").
The EIA projects Henry Hub prices will increase from an average of $2.84/\4MBtu in
2015 to $3.11/MMBtu in 2016. Additionally, the EIA predicts increased average consumption in
2015 (76.5 Bcf/d) and2016 (76.6Bcfld) over 2014 (73.5 Bcf/d). The increases in 2015 and
2016 are primarily attributed to electricity generation and new industrial projects. However,
natural gas consumption is projected to decline in both the residential and commercial sectors.
Chart 1: Weighted Average Cost of Gas (Per Therm)
0.s00
0,8000 ,
0.7000 .
0.6000 r-
Fi 0.5000oc(. o,aooo .
1r1
0,3000
I
0.2000 r-
0.1000 r
0.0000 '
tr"
ho'
YEAR 00 01 02 03 04 05 06 07
" 16 Change based !n prev,oi.,s.egula,ry stheduied PGA frirng
o8 *08 **09
Dec.
10 11 *17 r.*t2
Dec.
13 t4 15
STAFF COMMENTS SEPTEMBER 16,20I5
The NWGA published an abbreviated Outlook for 2015 because trends identified in its
2014 publication continue to be relevant. Additionally, key conclusions and analyses are
consistent with current conditions. NWGA's 2015 Gas Outlook key conclusions on the supply
side are that shale plays continue to transform the energy landscape, production techniques
exceed expectations, and Pacific Northwest natural gas customers benefit from being near two
large natural gas producing areas. On the price side, both spot and future commodity prices
reflect growth in North American natural gas production, natural gas has a price advantage over
diesel and petroleum, and most long-term price forecasts have declined since 2008.
Staff developed its own forecast using the NYMEXA.JGX Futures prices at each of the
three hubs where the Company buys natural gas. Utilizing the Company's estimated volume
allocation percentages for each hub, Staff forecasts the volume-weighted cost of gas to be
$3.184/MMBtu. The Company's forecasted mainline fuel cost of $3.178/MMBtu is comparable
to Staff s forecast. The Company's forecasted delivered fuel cost of $3.276lMMBtu is higher
than its mainline fuel cost because the proposed WACOG includes variable interstate
transportation costs, IGI administrative fees, and Gas Technology Institution ("GTI") charges.
Based on Staff s analysis of the market, weighted average cost of the Company's hedges,
and estimated cost of forward-looking index Company purchases, Staff believes that the
Company's WACOG of $0.32764 per therm is reasonable. Staff recommends that the
Commission accept the proposed WACOG and direct the Company to retum to the Commission
with a new filing if prices significantly deviate from proposed rates during the forthcoming year.
Risk Management
Staff analyzed the Company's operations and business practices to determine whether the
Company purchased gas at market prices and minimized risk to ratepayers. Staff scrutinized
how the Company manages price and risk given the Company's market purchases, storage, and
interstate transportation capacity.
The Company fulfills its mainline requirement with hedges, spot market purchases,
underground storage, and LNG storage. Underground storage enables the Company to purchase
gas for the upcoming heating season during the summer when natural gas prices are typically
lower. When opportunities are present, the Company manages its interstate transportation
capacity, selling surplus in the market. The Company sold LNG from its storage facility
STAFF COMMENTS SEPTEMBER 16,20I5
providing customers with a S689,367 PGA credit while maintaining LNG to meet peak day gas
demands. This is an increase of $283,956 or 70o/o over 2014 sales of $405,411.
Overall, the Company's strategy and practices associated with managing its resource
portfolio provide price stability for customers. The Company's approach is flexible, which
allows it to opportunistically buy gas, manage storage, and utilize interstate transportation
capacity as market conditions change.
Purchasing
Staff analyzedthe Company's purchasing practices to determine if the Company
reasonably adapted them to meet current market conditions. When compared to last year, the
Company plans to purchase a larger percentage of its mainline throughput requirement using
index or spot purchases. About 32Yo of the Company's total throughput are index or spot
purchases, compared to 28.3Yo last year. The Company's hedged supply went from 44.1o/o of
total throughput last year to 46.7% this year. Including the Company's storage gas, about 68% is
essentially hedged which is 4o/o lower than last year. The Company increased its hedging ratios
during the non-summer months, but decreased its hedging ratios in the summer months. This is
shown in Table 3, below:
Table 3: WACOG Hedging Ratios
% Locked-in Gas by PGA Yearr
2010 20t1 2012 20t3 20t4 2015
Non-Summer Months (Oct.-Mar.)68 69 63 79 74 78
Summer Months (Apr.-Sept.)29 0 45 48 63 22
Full Year 59 52 59 7t 72 68
Staff believes the Company's hedging ratio adjustments compliment current market
conditions, particularly since natural gas prices declined in the summer. The Company continues
to utilize index or spot purchases, but Staff believes the Company can react to upward price risk
since most of the Company's hedged volumes are locked-in at reasonable prices.
' % Locked-in gas includes storage volumes that are both hedged and index purchases.
STAFF COMMENTS SEPTEMBER I6,2015
Natural Gas Underground Storage
The Company says its management of storage assets benefits customers. Management of
the Company's storage assets at Northwest Pipeline's Jackson Prairie and Questar's Clay Basin
result in $1.8 million savings. Because gas added to storage is procured during the summer
season when prices are typically lower than during the winter, the Company's cost of storage gas
is typically lower than what could be procured in winter months. The Company has also entered
into various fixed price agreements for portions of underground storage and other winter flowing
supplies to further stabilize prices.
Staff analyzed the Company's practices for utilizing underground storage. When
compared to last year, the Company plans to withdraw slightly more of its underground storage
to meet total throughput. Last year, stored gas served about 27.4% of total throughput, whereas
this year it is expected to serve 27.7% of total throughput.
LNG Storage
The Company's Application includes $1.4 million for additional LNG storage capacity at
the Company's Plymouth facility on the Northwest Pipeline system. The Company acquired
incremental capacity of 378,000 MMBtu, with daily deliverability of 41,975 MMBtu. The
Company states that: "In addition to the operational and price mitigating benefits this added
capacity brings to Intermountain's customers, had this incremental Plymouth capacity not been
subscribed to, Intermountain would have been faced with a rise in costs associated with its
existing (lower) Plymouth capacity in excess of the costs associated with this incremental
acquisition."
Inter s tat e Tr ansportation
The Company delivers domestically produced natural gas to its city gates through
Northwest Pipeline. The Company also delivers natural gas from Canada by using capacity on
Gas Transmission Northwest (GTN), TransCanada's Foothills Pipeline system (Foothills), and
TransCanada's Alberta system known as Nova Gas Transmission (NOVA).
When the Company has excess capacity, it sells the surplus gas at the highest market
price available that day. All the benefits made from these sales are credited to customers. Staff
analyzedthe Company's historical capacity release revenue to determine annual variability. The
Company's proposed revenue from capacity releases this year totals $8,715,102, which includes
STAFF COMMENTS SEPTEMBER I6,2015
revenues from releases on a segment of Northwest Pipeline and non-segmented releases on
pipelines delivering natural gas from Canada. Staff determined that this capacity release revenue
is$849,227 below an eight year average of $9,564,929. Staff encourages the Company to
aggressively market its surplus capacity when it is available. Chart 2, below, describes the
Company's revenue from capacity release:
Chart 2: Transportation Capacity Release Revenue
s16,m,m0
s14,000,m0
S12,ooo,mo
s10m0,000
s8,ooo,mo
56,000 mo
s4,ooo,mo
S2,ooo,ooo
Hlstorical Transportation Capacity Release Revenue
50
2OM PGA 2OO9 PGA
Capacity Release S 55,091.334 , Sg,eof,Sfo
2O1O PGA 2011 PGA
s7,789,m1 s9,318,366
2012 PGA
s10,035,448
2013 PGA I ;;;;;;;
i
s14,721,s46 | sr r, om,zas
2015 PGA
Prop.
58,7 1s,702
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 volume of 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 2.3 million therms of LAUF Gas, or 0.394o/o of
total throughput, below the maximum allowable amount of LAUF Gas specified in Commission
Order No. 30649.2 The total normalized level of LAUF Gas embedded in base rates yields
$1,055,71I of LAUF Gas already collected.3 The Company wants to retum the difference
between the $l ,055,711 normalized level of LAUF Gas already collected through base rates and
2 The Company uses actual LAUF Gas results through August and estimates the amount of LAUF Gas from October
through September. Commission Order No. 30649 caps the Company's allowable LAUF Gas at .85% of
throughput.
3 In 1985, the Commission established $0.00182
LAUF Gas as a part of base rates.
STAFF COMMENTS
per therm as the normalized unit cost that can be collected for
SEPTEMBER I6,2015
the total estimated October 2014 to September 2015 LAUF Gas of $ 1 ,13 1,877 . The difference,
or the over-collection, will be a $76,166 credit to customers.
In the past, to retrospectively audit the Company's actual LAUF Gas percentage of
overall throughput, Staff requested a modified workpaper to provide a full year view of actual
LAUF Gas. Last year, the Company agreed to provide a workpaper in its Application that
retrospectively looks at the actual LAUF Gas percentage of overall throughput. Starting with
this filing, the Company provided Workpaper No. 7 in its Application which retrospectively
looks at the actual LAUF Gas percentage of overall throughput. Actual October 2013 through
September 2014 LAUF Gas was 880,946 therms or 0.l43Yo of throughput. Projected LAUF Gas
for October2014 through September 2015 is 2,288,309 therms or 0.394Yo of throughput.
Line Break-Lost and Unaccountedfor Gas
Last year, Staff discovered instances where the Company inadvertently charged the
incorrect rate for gas lost due to line breaks. In some instances, the Company used only the
WACOG to bill the responsible party. Order No. 33139 states "the Company shall bill a party
who is responsible for a line break to price lost gas using the WACOG and the RS-l fixed-cost of
interstate transportation and storage." The Company planned to hard code the price of gas into
an electronic system, so the price remains fixed throughout the PGA year and need not be
manually entered for each occurence.
Staff audited the Company's LAUF Gas based on Case No. INT-G-14-01 (2014 PGA).
Staff concluded that the Company implemented hard coding of the lost gas price into its LAUF
policies, operating procedures, and software. Additionally, Staff examined accounting records
and Gas Loss Reports from October 7,2014 through June 30, 2015. Staff concluded that the
accounting system and Loss Gas Reports are consistent and reflect the same cost for lost gas.
The current price of LAUF gas includes a fixed-cost component of $0.22841 (Fixed-Cost
Collection Rate) per therm and a variable component of $0.39482 (WACOG) for a total of
$0.62323 referred to as the Line Break Rate. The Company proposes to decrease the Line Break
Rate from $0.62323 per therm to $0.55674 per therm. The proposed Fixed-Cost Collection Rate
is $0.22910 per therm and the proposed variable component is the WACOG of $0.32764. Both
components of the Line Break Rate are determined annually with the PGA filing. Staff
concluded that the Company correctly calculated the proposed Line Break rate.
STAFF COMMENTS l0 SEPTEMBER 16,2015
Demand Allocation Factors
Last year, Staff discovered the Company exceeded the December 2009 peak day usage in
December 2013. Staff thus recommended that the Company update its peak demand allocation
factors in the PGA filing following a new peak day. Through discovery, Staff learned the
Company reviewed peak days before filing. According to the Company, the peak day for 2014
was 58 heating degree days which is warmer than the peak day of 63 heating degree days for
2013. Therefore, the Company continued to use the 63 heating degree days from 2013 as the
peak day for this filing.
CUSTOMER RELATIONS
Credit Customer Notice and Press Release
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined that both comply with Rule 125 of the
Commission's Rules of Procedure, IDAPA 31.01.01.125.
The customer notice was included with bills mailed beginning August 10 and ending
September 4. Customers have the opportunity to file comments on or before September 16,
20t5.
Customer Billing
The Company recently implemented a new Customer Care and Billing System. Among
the resulting changes was a new billing format. The new format provides customers with
information previously unavailable on bills, e .8., a 13-month usage history, a calendar
highlighting the payment due date, and an improved layout that makes it easier to find account
information.
Staff is concerned, however, about changes in how the Company itemizes charges. For
example, the residential bill now breaks down the commodity charge into three separate
components: (1) WACOG; (2) pipeline costs and temporaries; and (3) distribution charge.
Previously, customer bills reflected a commodity charge with no breakdown of components.
The Company's tariff provides for a commodity charge, noting that the charge includes the
annual PGA adjustment and the WACOG. Staff notes that the residential tariff does not mention
pipeline or distribution costs.
llSTAFF COMMENTS SEPTEMBER 16,20I5
The new billing format came to Staff s attention less than two weeks before the
Company's scheduled system implementation date of August 3 - too late in the process to make
changes. Staff has determined that the three itemized charges add up to the total cents per therm
charge authorized by the Commission as stated in its current tariff. The Company has not
proposed to change its tariff format to break out charges in a manner that differs from past
practice. As it stand now, however, Staff cannot consult the Company's tariff to verify the
accuracy of each separately itemized charge as it appears on customer bills.a In addition to the
inability to verify charges, Staff is concerned about the increased complexity of customer bills.
The Company has agreed to work with Staff to resolve these billing and tariff issues after
this case has concluded.
Customer Comments
As of September 16,2015, the Commission has received no comments from customers.
STAFF RECOMMENDATION
After examining the Company's Application, exhibits, workpapers, and gas purchases for
the year, Staff recommends the Commission approve the Company's Application and filed tariffs
to decrease the Company's annual revenue by $15.3 million (5.69%) and establish a WACOG of
$0.32764 per therm.
Additionally, Staff recommends that the Company and Staff work together to resolve
billing and tariff issues resulting from the Company's recent change in bill format.
4 The tariff does note the WACOG included in the commodity rate.
STAFF COMMENTS 12 SEPTEMBER I6,2015
Respecttully submitted this I L't' day of September 2015.
u //L
Karl T. Klein
Deputy Attorney General
Technical Staff: Teni Carlock
Daniel Klein
Kevin Keyt
i:umisc/comments/intgl 5.2kktcdkksk comments
STAFF COMMENTS l3 SEPTEMBER 16,2015
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 16th DAY OF SEPTEMBER 2015,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. INT-G.I5-02, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
MICHAEL P McGRATH
DIR _ REGULATORY AFFAIRS
INTERMOUNTAIN GAS CO
PO BOX 7608
BOISE TD 83707
E-MAIL: [e-mail]
RONALD L WILLIAMS
WILLIAMS BRADBURY
1015 W HAYS ST
BOISE ID 83702
E-MAIL: [e-mail]
CERTIFICATE OF SERVICE