20101022Comments.pdf

KRISTINE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BARNO. 6618
iomOCT 2 l PM 4: 59
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 APPLICATION OF )
A VISTA UTILITIES FOR AUTHORITY TO )
CHANGE ITS NATURAL GAS RATES AND )
CHARGES (2010 PURCHASED GAS COST )ADJUSTMENT). )
)
)
CASE NO. A VU-G-I0-03
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilties Commission, by and through its
Attorney of record, Kristine A. Sasser, Deputy Attorney General, and in response to the Notice of
Application and Notice of Modified Procedure issued in Order No. 32081 on September 30, 2010, in
Case No. AVU-G-I0-03, submits the following comments.
BACKGROUND
On September 15,2010, Avista Corporation dba Avista Utilties fied its anual Purchased Gas
Cost Adjustment (PGA) Application requesting authority to increase its annualized revenues by
approximately $3.1 milion, or about 4.3%. Application at 1. The PGA mechanism is used to adjust
rates to reflect annual changes in Avista's costs for the purchase of natural gas from suppliers-
including transportation, storage, and other related costs. Avista's earnings wil not be increased as a
result of the proposed changes in prices and revenues. The Company requests that its Application be
processed by Modified Procedure and that its rates become effective on November 1,2010.
STAFF COMMENTS 1 OCTOBER 21,2010
The Company states that if the proposed changes are approved its annual revenue wil increase
by approximately $3.1 milion, or 4.3%. The average residential or small commercial customer using
63 therms per month wil see an increase of$2.75 per month.
The Company states that it purchases natural gas for customer usage and transports this gas
over various pipelines for delivery to customers. The Company defers the effect of timing differences
due to implementation of rate changes and differences between the Company's actul weighted
average cost of gas (W ACOG) purchased and the WACOG embedded in rates. The Company states
that it also defers varous pipeline refuds or charges and miscellaneous revenue received from gas-
related transactions, including pipeline capacity releases. Applicåtion at 2.
Avista's filing utilizes a WACOG of $0.458 per therm, or $0.461 per therm once the gross
revenue factor (GRF) is included to reflect an allowance for uncollectibles and Commission fees. This
is lower than the curently approved W ACOG of $0.491 per thermo The Application asserts that daily
wholesale natural gas prices have been higher this year than last year, thus impacting the cost of
purchased natural gas for storage pricing. However, prices in the forward market have been lower this
year than what is curently embedded in rates. The decrease in forward market prices offset the
increase in storage prices, leading to a drop in the proposed W ACOG.
The Company has been hedging gas on a periodic basis throughout 2010 for the coming PGA
year. The Company states that approximately 60% of its estimated anual load requirements for the
PGAyear wil be hedged at a fixed price comprised of: (1) 41% of volumes hedged for a term of one
year or less; and (2) 19% of prior multi-year hedges. The Company states that an additional 10% of its
annual volume comes from underground storage. The Company states that through August 2010, the
planed hedge volumes for the PGA year have been executed at a weighted average price of $0.542
per thermo The storage gas has been purchased at an estimated weighted average price of $0.363 per
thermo
The demand costs included in the Company's Application primarily represent the costs of
pipeline transportation to the Company's system. Application at 3. Avista proposes a slight increase
in demand charges due to a change in tariffs on the TransCanada (Alberta) and TransCanada (BC)
pipelines. ¡d.
The Company is also proposing an amortization rate change of $0.035 per therm for
interrptible service customers and an amortization rate change of $0.062 per therm for general and
large general service customers. The expiration of the large 2009 amortization refud is the main
change in the proposed amortization rate. Included in the proposed refud rate is a substantial deferral
STAFF COMMENTS 2 OCTOBER 21,2010
balance that the Company was refunding over the past year through Schedule 155 that was not fully
refunded to customers as natural gas loads for the winter 2009/2010 were softer than projected. As a
result, the proposed amortization rate stil reflects some level of previous deferrals, allowing for a
lower proposed rate for customers.
A vista asserts that it has notified customers of its proposed increase in rates by posting a notice
at each of the Company's district offices in Idaho, by means ofa press release distributed to various
informational agencies, and by separate notice to each of its Idaho gas customers via a bil insert.
STAFF ANALYSIS
Staff has reviewed the Company's Application to determine whether its adjustments to
Schedule 150 and 156 reasonably capture its fixed (demand) and variable (commodity) costs. More
specifically, Staff has reviewed the Company's pipeline transportation and storage costs, fixed price
hedges, estimates of future commodity prices, and its risk management policies. Staffhas also
reviewed the appropriateness of the Schedule 155 change in amortization rates that "true up" the
expenses from the 2009 PGA. Each component of the rate changes wil be discussed in greater detail
below.
The Company fied the following rate changes that would result in an increase of
approximately $3.1 milion or about 4.3%:
Table 1:
Filed
Filed Schedule 155 Overall
Schedule 156 Amortization Filed Total Filed
Change per Change per Rate Change Percentage
Schedule Description Therm Tberm per Tberm Cbane:e
101 General ($0.01842)$0..06215 $0.04373 4.9%
111 Large General ($0.01842)$0.06215 $0.04373 6.1%
131 Interrptible ($0.02992)$0.03509 $0.00517 0.9%
Source: Apphcation, Page 2.
Subsequent to the fiing, the Company notified Staff that its filing contained a calculation error and
omitted a deferred credit of approximately $2,000. To correct the calculation error, the gross revenue
factor (GRF) for uncollectibles and Commission fees should be applied only to the rate change instead
of to the entire rate. Staff comments reflect the corrections. The revised rates shown in Table 2 below
result in a revenue increase of approximately $2.9 milion, or about 3.9%, and support the proposed
W ACOG of $0.458 per thermo
STAFF COMMENTS 3 OCTOBER 21,2010
Table 2'.
REVISED Schedule 155 REVISED Overall
Schedule 156 Amortization Total Rate REVISED
Change per Change per Change per Percentage
Schedule Description Therm Therm Therm Chane:e
101 General ($0.02204)$0.06215 $0.04011 4.5%
111 Large General ($0.02204)$0.06215 $0.04011 5.6%
131 Interrptible ($0.03296)$0.03509 $0.00213 0.4%
Under the revised rates above, a residential or small business customer served under Schedule 101
using an average of 63 therms per month can expect to see an average increase of approximately $2.53
per month or about 4.5%. However, actual customer increases wil vary based on therms consumed.
Schedules 150 and 156 - Purchased Gas Cost Adjustment
Schedules 150 and 156 are comprised of two pars: the commodity costs (WACOG) and the
demand costs. Prior to the Company's PGA filing, Schedule 150 was suspended by Order No. 31038
in Case No. A VU-G-l 0-0 1. i In order to be able to update the forward-looking cost of natual gas
purchased for customer usage during the suspension of Schedule 150 and because of the overlap
between the Company's PGA filing and the general rate case final order, the Company created a new
schedule, Schedule 156. The Company states that the current Schedule 150 and 156, when approved,
wil be consolidated into a single rate schedule.
The Company proposes a WACOG of$0.45817 per thermo The WACOG is the Company's
forward-looking price of purchased gas and storage gas embedded in base rates. This also includes the
benefit of some off system transactions, (This section of Staffs comments contains confidential
information). The demand costs represent the cost of pipeline transportation to the Company's
distribution system. The Company's Application proposes a demand cost increase of $0.012 per
thermo As previously discussed, due to the error in the Company's filing, this demand cost increase
should be reduced to $0.01 i per thermo This increase in demand cost is attributed to adjustments in
tariffs by TransCanada (Alberta) and TransCanada (BC) pipelines.
The Company delivers transported natural gas to its Idaho and Washington city-gates via two
interstate transportation natural gas pipeline providers, Northwest Pipeline and TransCanada - Gas
Transmission Northwest (GTN). Each of these providers has transmission pipelines which ru directly
STAFF COMMENTS 4 OCTOBER 21,2010
through the Company's service territory. The Company benefits from the geographic proximity of
these pipelines because each transmits natural gas from separate and distinct supply basins which
allows the Company to procure natural gas from the lowest cost supply basin to minimize commodity
costs. Available capacity on these pipelines remains a key component in serving customers and
maintaining supply diversity. The Company continuously determines when its contracted interstate
transportation supply is under-utilized due to warmer weather or declines in industrial demand and will
post for release to others with the release payments received benefiting the Company's customers.
As in prior years, the Company is bound, as are other natural gas entities that are served by
Northwest Pipeline, to purchase gas (This section of Staffs comments contains confidential
information). The Company asserts that Sumas gas prices have typically been higher than both
Rockies and AECO and, (This section of Staffs comments contains confidential information) the
Company has utilzed its proximity to GTN to acquire gas supply at lower commodity prices without
incuring significant demand costs to acquire the gas supply.
Lower Rockies Basin prices have benefited natural gas utilities in the Northwest due to Rockies
lack of pipeline infrastructure capable of moving Rockies gas east. However, Rockies Express
pipeline, a 639 mile pipeline built to move gas east, was completed this past year. This pipeline wil
enable Rockies direct access to the eastern markets for the first time which is expected to increase price
competition among suppliers in North America. To date, the completion of the Rockies Express
pipeline has not significantly influenced natural gas prices.
The Company's diversity of supply basins has enabled it to exercise multiple hedging options
and obtain expected winter flowing gas requirements at favorably contracted prices. This allows the
Company to provide customers with low priced natural gas.
Weighted Average Cost of Gas (WACOG)
Throughout the last year, the wholesale cost of natural gas has been low, which has allowed the
Company to purchase gas for the coming year at favorable rates. This request reflects the third
WACOG decrease within the Company's past four PGA filings, and makes the Company's proposed
W ACOG the lowest since its 2003 fiing. The table below ilustrates the changes in the natural gas
market over the past nine years and the volatility experienced over the same period:
1 As par of the A VU-G- i 0-0 i case the parties agreed, and the Commission approved, to move all natural gas commodity
and demand costs from base rates to Schedule i 50 for purposes of clarity and transparency. The retail rate schedules now
only reflect the non-commodity distribution rates. Order No. 32070.
STAFF COMMENTS 5 OCTOBER 21,2010
Table 3'.
Approved Weighted % Change Resulting Total General % Change
A vg. Cost of Gas From Previous Service Schedule 101 From Previous
Year $/Therm Year Tariff, $/Therm Year
2002 0.34572 Base Year 0.75722 Base Year
2003 0.44989 30.13%0.77716 2.63%
2004 0.55739 23.89%0.95315 22.64%
2005 0.76786 37.76%1.18692 24.53%
2006 0.76085 -0.91%1.16175 -2.12%
2007 0.75544 -0.71%1.1056 -4.83%
2008 0.78646 4.11%1.15103 4.11%
2009*0.75984 -3.38%1.07507 -6.60%
2009 0.49093 -35.39%0.88199 -17.96%
2010 0.45817 -6.67%0.79123 -10.29%
*The W ACOG change was part of the AVU-G-09-0 i general rate case settlement Intended to offset the impact of the
residential base rate increase approved in Order No. 30856.
The primary reason for the decline in the W ACOG is the continuing decline in natural gas prices due
to the weakess in our regional and national economy that has reduced the weather adjusted demand
for natural gas during a period of time when natural gas supplies have been plentifuL.
A national report issued by the Energy Information Administration (EIA) in August of this
year, provides insight into the anticipated conditions of the natural gas industry through 2011 in the
areas of natural gas consumption, production, inventory and pricing. Natural gas consumption is
forecast to increase by 3.8% from the 2009 levels of 64.9 bilion cubic feet per day (Bcf/d) in 2010 and
remain flat in 2011. Natural gas consumption in the industrial sector is proj ected to increase by 7%
through the remaining months of 2010 and expected to increase by only 1 % through 2011. Residential
and commercial consumption through 2011 is projected to remain at levels comparable to those of
2009. Production during 2010 is expected to be 1.1% above 2009 levels with a 1.4% reduction in
driling activity in 2011. The EIA Report (September 9, 2010) states that inventories held in
underground storage in the lower 48 states is 5.5 percent above the five-year average of2.998 trilion
cubic feet, and 6.4 percent below last year's storage level of about 3.382 trilion cubic feet. Finally,
natural gas spot prices averaged $0.463 per therm in July 2010 - $0.0017 per therm less than June
2010. EIA forecasts natural gas prices for the remainder of 2010 to average $0.447 per therm with an
average price of $0.498 per therm in 2011.
STAFF COMMENTS 6 OCTOBER 21,2010
Throughout the year, Staff reviews several publications relating to the natural gas industry.
However, two primary sources are utilzed to develop forecasts, specifically: (l) NYMEX Futures
Index and (2) Energy Information Administration (EIA). For puroses of this Application, Staffhas
reviewed the Company's proposed WACOG of $0.458 per therm and its forecasted natural gas prices
through October 2011. When comparing the data from the above informational sources, forecasts and
the WACOG of other Pacific Northwest natural gas utilties, Staff believes the Company's forecasted
natural gas prices are reasonable.
Schedule 155 - Deferred Expenses
The Schedule 155 portion of the PGA is the amortization component of the Company's deferral
account. When the Company pays more for gas than what is estimated in the preceding W ACOG, a
surcharge is assessed to customers. However, if the Company pays less for gas than what is estimated
in the preceding W ACOG, a credit is issued to customers. Although gas prices have been lower than
the WACOG anticipated in the Company's 2009 filing, the curent refud rate required to amortize the
current deferral is less than the refud rate approved in the 2009 PGA filing. The net effect of the
adjustments is an increase of $4.5 milion. Combining the two rate schedules (the reduction in
Schedule 156 of $1.6 milion and the increase in Schedule 155 of $4.5 milion) the total revenue
increase is $2.9 milion.
Hedging Policies
As was the case in prior years, the Company's gas procurement plan generally incorporates a
structured approach for the hedging portion of the portfolio, while maintaining flexibilty such that
discretionar adjustments can be made when the wholesale gas market presents opportnities to
achieve cost reductions. Discretion is used in evaluating curent volatilty, forward cure shapes, and
alternatives when considering price triggers. The Company continues to hedge utilzing a series of
price targets. In the case of decreasing prices, taget purchase volumes are increased.
Procedurally, the Company (This section of Staffs comments contains confidential
information) develop an estimated cost for index/spot purchases. The estimated monthly volumes to
be purchased (This section of Staffs comments contains confidential information) determine
estimated spot purchase costs. These index/spot purchase volumes represent approximately (This
section of Staffs comments contains confidential information) of the Company's estimated anual
STAFF COMMENTS 7 OCTOBER 21, 2010
load for the coming year. At the time of this Application the price for this volume segment of the
Company's annual gas required is $0.399 per thermo
The Company has been hedging gas on a periodic basis throughout 2010 for the coming PGA
year. The Company states that approximately 60% of its estimated annual load requirements for the
PGA year wil be hedged at a fixed price comprised of: (1) 41 % of volumes hedged for a term of one
year or less; and (2) 19% of prior multi-year hedges. An additional 10% of the Company's anual
volume comes from underground storage. The Company states that through August 2010, the planed
hedge volumes for the PGA year have been executed at a weighted average price of $0.542 per thermo
At the time of this Application, the Company's weighted average cost for the gas in storage is $0.363
per thermo
Following the filing of the Application, the Company provided additional information to Staff
regarding the status of the Company's discretionary natural gas hedging program activities. The intent
of the discretionary hedging program is to acquire low hedge prices in the event that natual gas market
prices fall below Company established price targets. The discretionar hedging program is divided
into short-term and long-term transactional components. (This section of Staffs comments contains
confidential information). As of October 2010, the Company has executed the last long-term hedge
and previously executed all short term hedges for the 2010 gas year. The average executed price for
the discretionar hedges was $0.505 per therm for the short-term and $0.530 per therm for the long-
term components.
The Company typically develops, establishes and implements the anual procurement plan by
November or December of each year. However, due to low curent market prices and foreseeable low
market prices in the coming months, the Company developed and implemented the annual
procurement in October 2010 in order to a take advantage of favorable natural gas market prices.
The Company periodically meets with Staff to discuss the procurement plan given the
wholesale natural gas environment. The Company has informed Staff that it plans to modify the
hedging strategy developed last year and wil soon meet with the Staff to discuss these options. The
Company wil continue to: (l) keep long-term hedges open for up to two or three years, depending on
which strip triggers first; (2) decide price targets that wil be "open" all year; and (3) maintain the
current minimum portfolio hedge percentage (This section of Staffs comments contains
confidential information). Throughout the year the Company communicates with Staff when it
believes a decision is being made outside the scope of the normal procurement plan. Over the course
of the year, the Company has also continued to communicate with Staff regarding the Company's
STAFF COMMENTS 8 OCTOBER 21,2010
storage and procurement activities, (This section of Staffs comments contains confidential
information). The Company continues to purchase gas in an effort to provide price stabilty to
customers within its service area.
CONSUMER ISSUES
Customer Notice and Press Release
The Press Release and Customer Notice were included in Avista's Application, which was fied
with the Commission September 15, 2010. Staff reviewed the customer notice and press release and
determined they were in compliance with the requirements ofIPUC Rules of Procedure 125.04 and
125.05 (IDAPA 31.01.01.125). The customer notice was mailed with cyclical bilings beginning
September 22,2010 and ending October 20,2010.
Customer Comments
Customers were given until October 21, 2010, to fie comments. As of October 20, 2010, only
one comment had been fied by a customer. The customer opposed a rate increase during the current
economic downturn.
STAFF RECOMMENDATION
After a complete examination of the Company's Application and gas purchases for the year,
Staff has the following recommendations for the Commission:
1. Staff recommends that the Commission accept a W ACOG of $0.45817 per thermo
2. Staff recommends the Commission accept the Schedule i 55 (Gas Rate Adjustment)
amortization for deferral balances. The combination of the first two recommendations
results in an increase of $2.9 milion or about 3.9%.
3. Staff also recommends that the Commission reserve the right to reopen this case and
reevaluate any approved tariffs if the WACOG materially changes below that included in
this Application.
STAFF COMMENTS 9 OCTOBER 21,2010
Respectfully submitted this J)cf day of October 2010.
~)a,~U\Kr~ÃSasser
Deputy Attorney General
Technical Staff: Doug Cox
Patricia Hars
Daniel Klein
i:umisc:commentsavuglO.03ksdcphdk comments
STAFF COMMENTS 10 OCTOBER 21,2010
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 21sT DAY OF OCTOBER 2010,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. AVU-G-1O-03, BY E-MAILING AND MAILING A COPY THEREOF,
POSTAGE PREPAID, TO THE FOLLOWING:
DAVID J MEYER
VP & CHIEF COUNSEL
AVISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220-3727
E-MAIL: david.meyer(favistacorp.com
KELLY 0 NORWOOD
VP STATE & FED REG
AVISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220-3727
E-MAIL: kelly.norwood(favistacorp.com
~...~SECRETÃRY? '-
CERTIFICATE OF SERVICE