20120917Comments.pdf

KARL T. KLEIN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
P0 BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 5156
RE CE 1, V ED
7I7 SEP17 PM 2:53
r-' LJfit) L
UTL1TUS
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 AVISTA )
CORPORATION'S APPLICATION TO ) CASE NO. AVU-G-12-05
CHANGE ITS RATES AND CHARGES (2012 )
PURCHASED GAS COST ADJUSTMENT). ) COMMENTS OF THE
) COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission comments as follows on Avista
Corporation's Application.
BACKGROUND
On July 31, 2012, Avista Corporation dba Avista Utilities filed its annual Purchased Gas
Cost Adjustment (PGA) Application asking to decrease its annualized revenues by about $3.6
million (5.4%). Application at 1.' The Company says its proposal will not affect its earnings
and will decrease the average, residential or small commercial customer's bill by about $4.42 per
month (7.9%). Id. at 4. The Company asks for the new rates to take effect October 1, 2012. Id.
at 5.
'The PGA mechanism is used to adjust rates to reflect annual changes in the Company's costs for the purchase of
natural gas from suppliers including transportation, storage, and other related costs.
STAFF COMMENTS 1 SEPTEMBER 17, 2012
Avista distributes natural gas in northern Idaho, eastern and central Washington, and
southwestern and northeastern Oregon. Id at 2.2 The Company buys natural gas and then
transports it through pipelines for delivery to customers. Id. at 2. The Company defers the effect
of timing differences due to implementation of rate changes and differences between the
Company's actual weighted average cost of gas (WACOG) purchased and the WACOG
embedded in rates. Id. The Company also defers various pipeline refunds or charges and
miscellaneous revenue received from natural gas related transactions, including pipeline capacity
releases. Id. In its annual PGA filing, the Company proposes to (1) pass any change in the
estimated cost of natural gas for the next 13 months to customers (Schedule 150); and (2) revise
the amortization rates to refund or collect the balance of deferred gas costs (Schedule 155). Id. at
2,4.
STAFF REVIEW
Staff has reviewed the Company's Application and performed an audit to verify the
Company's earnings will not change as a result of the filing. Staff reviewed the Company's
adjustments to Schedule 150 to determine if they reasonably capture Avista's 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. Additionally, Staff has reviewed the proposed Schedule 155
amortization rate to ensure that it properly captures all of the deferral account components.
When combined, Schedules 150 and 155 make up the PGA. Each component will be discussed
in greater detail below.
The Company proposes the following rate changes that would result in a decrease of
approximately $3.6 million in annual revenue, or approximately 5.4%
Service
Schedule
No.
Commodity
Change
per Therm
Demand
Change
per Therm
Total
Sch. 150
Change
Amortization
Change
per Therm
Total Rate
Change
per Therm
Overall
Percent
Change
General 101 ($0.02931) ($0.00849) ($0.03780) ($0.00890) ($0.04670) (5.02%)
Lg. General 111 ($0.02931) ($0.00849) ($0.03780) ($0.00890) ($0.04670) (6.31%)
Interruptible 131 ($0.02931) $0.00000 ($0.02931) ($0.00203) 1 ($0.03134) (6.06%)
2 The Company also generates, transmits, and distributes electricity in northern Idaho and eastern Washington. Id.
STAFF COMMENTS 2 SEPTEMBER 17, 2012
Under the proposed rates, a Schedule 101 residential or small business customer using an
average of 60 therms per month will see a decrease of $4.42 per month, or approximately 7.9%.
Actual customer decreases will vary based on the actual amount of therms consumed.
Schedule 150 - Purchased Gas Cost Adjustment
The Schedule 150 portion of the PGA is comprised of two parts: the commodity costs
(WACOG) and the demand costs. The WACOG is the Company's forward-looking price of
purchased gas and storage gas embedded in base rates. The demand costs represent the cost of
pipeline transportation to the Company's distribution system, as well capacity releases which are
credited back to customers. The proposed WACOG in this case is 33.3 cents per therm, which
compares to 41.8 cents per therm approved in the Company's last annual PGA. However, the
Company filed an interim PGA effective March 1, 2012 decreasing the WACOG to 36.2 cents
per therm and providing customers with a decrease in rates of approximately 6%.
Weighted Average Cost of Gas (WACOG)
The WACOG is calculated in mid-July based on the cost of the Company's executed
hedges, current underground storage, and its estimated index price for future deliveries. As of
the date of this filing, the Company has already hedged 60% of its estimated load requirements
for the upcoming year at fixed prices (including 20% underground storage), leaving 40% open to
market variations. Throughout the last year there have been declines in the wholesale cost of
natural gas, which have allowed Avista to purchase gas for the coming year at favorable rates.
The weighted average cost of this year's planned hedged volumes is $3.09 per dekatherm,
including the weighted average cost of underground storage at $2.10 per dekatherm. The
Company estimates its index volumes will be procured at an annual weighted average price of
$2.98 per dekatherm.
For reference, the table below shows historical WACOG amounts, the difference to
residential customer (Schedule 10 1) total bills, and the percentage change from previous years.
STAFF COMMENTS 3 SEPTEMBER 17, 2012
Year
Weighted Avg. Cost of
Gas $/Therm
% Change From
Previous Year
Resulting Total
General Service
Schedule 101 Tariff,
$/Therm
% Change From
Previous Year
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% 0.91553 3.80%
2011 0.41797 -8.77% 0.91464 -0.10%
2012 0.36216 -13.35% 0.85883 -6.10%
Proposed 0.33285 -8.09% 0.81213 -5.44%
the WACOCi change was part of the AVU-G-09-01 settlement intended to offset the impact of the residential base rate increase approved in
Order No. 30856.
Staff reviewed the natural gas industry fundamentals to determine whether the
Company's executed hedges and estimated index prices for future delivery are reasonable. Staff
utilized several sources, including: (1) the Energy Information Administration (EIA); (2) the
Northwest Gas Association (NWGA); (3) the NYMEX Futures Index; and (4) the Natural Gas
Exchange Inc. (NGX). The Short-Term Energy Outlook (STEO) published monthly by the EIA
reports information on anticipated demand, production, imports/exports, inventories, and prices.
The NWGA is made up of industry participants directly serving Washington, Oregon, Idaho and
British Columbia. Each year it publishes a detailed ten-year look at expected natural gas
demand, supply availability, and prices in the Northwest.
Price Fundamentals
Staff analyzed the EJA and Northwest Power and Conservation Council (NPCC) pricing
forecasts, and the NYMEX and NGX forward prices. According to the EIA, the average Henry
Hub price in July was just under $3.00 per dekathenn, which is 33% lower than July 2011
prices.3 For comparison purposes, the Company's July 2012 WACOG dropped nearly 50% from
last year, from $3.52 to $1.86 per dekatherm. According to the NPCC, the prices of natural gas
The 2011 AECO basis differential from Henry Hub was approximately ($0.47) per dekatherm, whereas the Company's forward
looking AECO basis differential for the PGA time frame averages ($0.42) per dekatherm.
STAFF COMMENTS 4 SEPTEMBER 17, 2012
in 2011 and the first two quarters of 2012 were the lowest since 2002. EIA anticipates Henry
Hub prices to finish the year at $2.67 per dekatherm, 20% lower than the $3.34 per dekatherm
average price it expects in 2013. The NPCC expects Henry Hub prices to average $3.20 per
dekatherm in 2013 given its medium case scenario. Based on the Company's assumption that its
purchases will be predominantly from AECO, it forecasts an average price of approximately
$2.98 per dekatherm during the 2013 PGA year.
The Company's forward-looking forecast for its index prices is developed based on a
30-day historical average of forward prices (ending July 19, 2012) from the AECO basin. Since
approximately 70% of the Company's estimated monthly volumes typically come from AECO,
the total volume was multiplied by the (30-day) average price. Staff compared the Company's
forward looking price estimates for index gas purchases to a weighted average that also includes
volumes purchased from Rockies and Sumas. After looking at the weighted average that
included NYMEX prices for Rockies and Sumas, and the NGX forward prices for AECO, Staff
determined the prices were similar to the Company's estimates.
Staff also evaluated the forward price trends shown in the Company's recently filed 2012
Integrated Resource Plan (IRP), primarily because the Company solicits the forecasting expertise
of third party consultants. 2012 IRP, Figure 6.3, p. 6.5. Although there were differences in
opinion when forecasting forward prices given the current market fundamentals, the near term
2013 price forecast of one consultant is similar to the Company's forecast given typical basin
differentials.
The Company will continue to watch the market for changes that could materially impact
natural gas prices moving forward. Similar to last year, if spring and summer prices significantly
deviate from the proposed rates, Staff would expect the Company to return to the Commission
with a new filing.
Based on its review of the market fundamentals to evaluate the Company's weighted
average cost of its current hedges and its estimated cost of forward-looking index purchases,
Staff believes the Company's hedges were prudent and its approach for estimating the forward
prices reasonable. Staff recommends the Commission accept the Company's proposed WACOG
of $0.33285 per therm.
STAFF COMMENTS 5 SEPTEMBER 17, 2012
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
WACOG, a surcharge is issued to customers. However, if the Company pays less for gas than
what is estimated in the preceding WACOG, a credit is issued to customers. Gas prices have
continued to fall throughout the year compared to the WACOG anticipated in the Company's last
filing. In this Application, the Company proposes to increase the Schedule 155 amortization
refund rate by $0.00890 per therm (from $0.02885 per therm to $0.03775 per therm) which will
refund approximately $3.1 million to customers over the next 13 months, assuming normal
weather.
A reconciliation of the deferral balance in this case is as follows:
Beginning Deferred Costs Balance (1,584,903)
Wholesale Gas Costs Below WACOG (2,925,726)
Demand Deferral and Capacity Release (220,584)
Interest on Deferrals (19,826)
Transfer to Amortization Account 1,078,948
Unamortized Balance from Prior PGA 625,694
Idaho Deferred State Income Tax Amortization (6,165)
Total Deferred Amount Credited to Customers (3,052,562)
The Settlement Stipulation in the Company's 2010 general rate case included an offset to
the Company's natural gas revenues of $0.5 million in Deferred State Income Tax (DSIT) credits
to be amortized over a one-year period. The Company includes the remaining $6,165 in the
deferral balance being credited to customers in this case, which true's up the original
amortization amount.
Hedging Policies
The Company develops its procurement plan based on a load forecast consistent with the
methodology used for budgeting, rate making, and IRP planning. The Company's procurement
plan includes hedging on a short-term (one year or less) and long-term (3 winters beyond the
prompt year) basis. The hedges from the previous year's long-term discretionary hedging and
anticipated storage withdrawals are deducted from the forecasted load. The remaining load
requirements are served with either index (spot/cash) purchases or short-term hedges. The
STAFF COMMENTS 6 SEPTEMBER 17, 2012
short-term plan utilizes hedge windows which are open for a predetermined period of time and
have upper and lower pricing levels that are market based. The long-term plan is driven by
pricing targets that allow the Company flexibility to hedge at potentially favorable pricing levels.
This flexibility in the procurement plan reduces costs to customers by allowing the Company to
make discretionary adjustments when the wholesale gas market changes.
According to the Company, this year's market fundamentals indicate continued low
prices during the 2012-2013 procurement plan year. In response to anticipated continued low
prices, the portion of the Company's portfolio consisting of index gas is now about 40%,
whereas last year it consisted of about 30% index purchases. Correspondingly, the portion of the
Company's portfolio comprised of short-term and long-term hedges has decreased to 60% of the
Company's portfolio, whereas last year it consisted of about 70% short-term and long-term
hedges.4 The percentage of its volume met by short-term hedges has been reduced from 32%
last year, to 11% this year. However, the Company increased the percentage of its volume met
by multi-year hedges from 18% last year, to 29% this year. The Company has continued to keep
20% of its volume in underground storage.
Staff believes the Company's changes to its procurement plan continue to protect
customers from the price risks of a changing market. By allocating more of its overall portfolio
to index purchases while at the same time increasing the percent of hedged volumes on multi-
year contracts, the Company is capturing the benefit of current low gas prices and mitigating
customers' upward price risk. Staff encourages the Company to continue closely evaluating
upward price risk, and to consider more multi-year hedges if favorable opportunities exist.
Multi-year hedges can potentially capture the benefit of current low prices and maintain stable
rates given changes in market fundamentals.
The Company meets with Staff semi-annually to discuss the Company's procurement
plan. Throughout the year, the Company communicates with Staff when it makes decisions
outside the scope of the normal procurement plan.
Other Considerations
On August 10, 2012, Avista filed a Notice of Intent to File a General Rate Case. Under
the Commission's Rules this rate case could be filed as soon as October 10, 2012. See RP 122
The short-term and long-term hedge percentages include 20% of estimated throughput in underground storage.
STAFF COMMENTS 7 SEPTEMBER 17, 2012
(Utility must file notice of intent at least 60 days before filing a general rate case). In
anticipation of a rate increase that may result from a general rate case, Staff proposes to hold
back a portion of the decrease proposed by Avista in this case. Rather than increase the Schedule
155 amortization refund from $0.02885 per therm to $0.03775 per therm, Staff proposes to
reduce the rate to $0.01785 per therm. The effect of the Staff's proposal is to refund
approximately $1.55 million over the next 13 months instead of the $3.1 million proposed by the
Company. The remaining $1.55 million un-refunded credit balance will remain in the PGA
deferral account and accumulate interest until it is used to offset base rate increases or is returned
to customers in a future PGA. Staff believes that the holdback can be used to reduce potential
rate increases that could occur in the spring and fall of 2013, thereby improving rate stability in
the long-run. Staff's proposal results in an October 1, 2012 rate decrease of approximately $2.14
million in annual revenue, or about 3.2%. Staff's proposed rate adjustments are as follows:
Service Schedule
No.
Commodity
Change per
Therm
Demand
Change per
Therm
Total Sch.
150
Change
Amortization
Change per
Therm
Total Rate
Change per
Therm
Overall
Percent
Change
General 101 ($0.02931) ($0.00849) ($0.03780) $0.009975 ($0.02782) (2.99%)
Lg. General 111 ($0.02931) ($0.00849) ($0.03780) $0.009975 ($0.02782) (3.76%)
Interruptible 131 ($0.02931) $0.00000 ($0.02931 $0.015550 ($0.01376) (2.66%)
CUSTOMER RELATIONS
Customer Notice and Press Release
The Customer Notice and Press Release were included with Avista's Application. The
Application was received on July 31, 2012. Staff reviewed the customer notice and press release
and determined they were in compliance with the requirements of IPUC Rules of Procedure
125.04 and 125.05. IDAPA 31.01.01.125. Avista issued a Press Release covering four separate
cases: the PGA (AVU-G-12-05), the PCA (AVU-E-12-06), the natural Gas Energy Efficiency
Tariff Rider Adjustment (AVU-G-12-06) and the Electric Energy Efficiency Tariff Rider
Adjustment (AVU-E- 12-07).
The customer notices for this PGA case were mailed with cyclical billings beginning
August 3, 2012 and ending September 4, 2012. In addition to providing information regarding
its PGA request, Avista also included information regarding the natural Gas Energy Efficiency
Tariff Rider Adjustment Case No. AVU-G-12-06.
STAFF COMMENTS 8 SEPTEMBER 17, 2012
Customer Comments
Customers were given until September 17, 2012 to file comments. As of September 10,
2012, two customers had filed comments. One customer mistakenly believed that Avista had
requested a rate increase. That customer was informed by IPUC Staff that the Company had
filed for a decrease to its natural gas rates. The second commenter applauded Avista for
reducing rates during a time of economic hardship.
Financial Assistance for Paying Heating Bills
If the Company's proposal is approved, residential customers will see an approximate 8%
decrease in their natural gas rates. (The PGA requests to lower rates by 5.4% and the Tariff
Rider requests a 2.6% reduction to rates). Staff reminds all customers, struggling to pay utility
bills, of the energy assistance that is available to qualified customers. Information regarding the
federally-funded Low-Income Energy Assistance Program (LIHEAP) and local non-profit and
other fuel funds such as Project Share in Avista's northern Idaho service territory can be
obtained by calling the nearest Community Action Agency, Avista Utilities, the Idaho Public
Utilities Commission, or the 2-1-1 Idaho Care Line.
STAFF RECOMMENDATION
After thoroughly examining the Company's Application and gas purchases for the year,
Staff recommends the following:
1.Staff recommends the Commission approve the Company's proposed Schedule 150,
including the proposed WACOG of $0.33285 per therm; and
2.Staff recommends the Commission approve Staff's proposed Schedule 155
amortization rate of $0.1785 per therm for the deferral balances. The combination of
Staff's recommendations results in a decrease of approximately $2.14 million, or
about 3.2% of annual revenues.
STAFF COMMENTS 9 SEPTEMBER 17, 2012
Respectfully submitted this / TJi' day of September 2012.
Karl T. Klein
Deputy Attorney General
Technical Staff: Matt Elam
Donn English
Marilyn Parker
i:umisc/comments/avugl 2.5kkmedemp comments
STAFF COMMENTS 10 SEPTEMBER 17, 2012
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 17TH DAY OF SEPTEMBER 2012,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. AVU-G-12-05, BY E-MAILING AND MAILING A COPY THEREOF,
POSTAGE PREPAID, TO THE FOLLOWING:
DAVID J MEYER
VP & CHIEF COUNSEL
AVISTA CORPORATION
P0 BOX 3727
SPOKANE WA 99220-3727
E-MAIL: [e-mail]
KELLY 0. NORWOOD
VP - STATE & FEDERAL REGULATION
AVISTA CORPORATION
P0 BOX 3727
SPOKANE WA 99220-3726
E-MAIL: [e-mail]
je)
SECRETA
CERTIFICATE OF SERVICE