20141017Comments.pdf

DAPHNE HUANG
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720.0074
[phone]
IDAHO BAR NO. 8370
Street Address for Express Mail:
472W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
?ilirr CIiT ll Pil 12: 55
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF AVISTA )
CORPORATION'S APPLICATTON TO ) CASE NO. AVU-G-14-04
CHANGE ITS RATES AND CHARGES (2014 )
PURCHASED NATURAL GAS COST ) COMMENTS OF THEADJUSTMENT). ) COMMISSION STAFF
)
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Daphne Huang, Deputy Attorney General, and in response to the Notice of
Modified Procedure issued in Order No. 33133, submits the following comments.
BACKGROUND
On September 15, 2014, Avista Corporation dba Avista Utilities filed its annual
Purchased Gas Cost Adjustment (PGA) Application. The PGA is arate mechanism used to
adjust rates up or down to reflect changes in the market price of natural gas, and changes in
transportation and storage costs. These changes in Avista's natural gas costs are deferred to the
PGA account. In this Application, Avista proposes to decrease its PGA rates an average of
2.lyo, or about $1.6 million per year. Application at 1. As set out in greater detail below,
Avista's proposal will decrease the average residential or small commercial customer's rates by
$ 1.16 per month (about 2%). Id. at 4. Avista also proposes that large commercial customers'
rates decrease by about 2%o,but Avista's sole intemrptible customer's PGA rate will increase by
about 0.2%. Id. at3. Avista's proposal will not affect its earnings. Avista asked that its
STAFF COMMENTS ocToBER 17,2014
Application be processed by Modified Procedure, and that the new rates take effect November 1,
2014. Id. at5.
Avista distributes natural gas in northem Idaho, eastem and central Washington, and
southwestern and northeastem Oregon. Id. at2. Avista buys natural gas and then transports it
through pipelines for delivery to customers. Id. In its PGA Application, Avista proposes to: (1)
pass any change in the estimated cost of natural gas for the next 12 months to customers (tariff
Schedule 150); and (2) revise the amortization rates to refund or collect the balance of deferred
gas costs (tariff Schedule 155). Id. at2,4.
Avista estimates that its commodity costs will increase $0.01 16 per therm from the
currently approved $0.374 per therm to $0.385 per therm. Id. at3. "Commodity Costs" are a
company's variable costs for natural gas. The weighted average cost of gas (WACOG), which
also includes other variable administrative costs, approximates a company's commodity costs.
Avista's demand - or fixed - costs are primarily the costs to transport gas on interstate
pipelines to Avista's local distribution system. Id. at 4. Avista proposes deueasing its demand
costs due to high projected-usage for fixed-demand costs which more than offset expiring short-
term capacity release credits on Northwest Pipeline and increasing summer capacity on TCPL-
Alberta pipeline. /d.
Avista proposes deueasing the amortization refund rate by $0.03071 per therm (from a
$0.00015 per therm surcharge to a $0.03056 per therm rebate). Id. at 4. This decrease is driven
by changes in the demand portion of the amortization rate, including: (1) colder than normal
weather during the2013-2014 winter, resulting in higher demand cost collections; (2) Avista
entered into a new Deferred Exchange contract, effective April 2014, for which Avista charges a
fixed per therm charge; and (3) an error regarding allocation of Avista's transport costs between
power supply operations and natural gas distribution operations, resulting in a net benefit to
customers. .Id.
Avista asserts it has notified customers of its proposed tariffs by posting notice at each of
its Idaho district offices, and through a press release. Id. at2. Also, Avista sent a notice to each
customer in bill inserts from September 17 through October 15,2014. Id.
STAFF COMMENTS ocroBER 17,2014
STAFF REVIEW
Staff reviewed the Company's gas purchases for the year, along with its fixed price
hedges, pipeline transportation and storage costs, and estimates of future commodity prices.
Staff also reviewed the accuracy of the Company's jurisdictional allocations and the
reasonableness of its Lost and Unaccounted for Gas (LAUF) volumes.l
The Company's Application and work papers were thoroughly reviewed to verify the
filing will not change the Company's earnings, and that the amortization rates accurately
reconcile prudent expenses from the 2013 PGA. Staff believes the proposed adjustments to
Schedules 150 and 155 accurately capture its fixed (demand) and variable (commodity) costs
given the coming year's forecasted gas purchases and the reconciliation of expenses from the
prior year. Each component of the rate change is shown in Table 1 and will be discussed in
greater detail below.
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 commodity costs are the variable cost of gas the
Company must procure to satisfy its estimated annual throughput requirements. Demand costs
are the fixed capacity costs for interstate transportation and underground storage, as well as
capacity releases which are credited back to customers. The Company estimates that both its
commodity and demand costs will increase, but the higher demand costs are more than offset by
an increase in estimated usage. Specifically, the Company's commodity costs are expected to
increase from the currently approved $0.374 per therm to $0.385 per therm; at the same time, the
Company proposes to slightly decrease its demand costs by $0.00022 per therm.
' LAUF Gas is the difference between the volumes of natural gas delivered to the distribution system at the city gate
and volumes of natural gas billed to customers at the meter.
Table 1: Rate Changes by Class
Service
Schedule
No.
Commodity
Change per
Therm
Demand
Change per
Therm
Total
Sch.150
Chanse
Amortization
Change per
Therm
Total Rate
Change per
Therm
Overall
Percent
Chanse
General 101 $0.01160 (s0.00022)$0.0r 138 (s0.03071)($0.01933)(l.9lo/o\
Le. General lll $0.01160 (s0.00022)s0.01 l 3 8 (s0.03071)($0.01933)(2.490 1
lntemlptible 131 $0.01160 0.00000 s0.01160 $0.001l9 $0.01279 0.20o/o
STAFF COMMENTS ocToBER 17,2014
Weighted Average Cost of Gas (WACOG)
The WACOG includes fuel charges to move gas at the city gate, plus some variable
transport costs, and Gas Research Institute (GRI) funding. Avista's WACOG does not include
third party gas management fees. The proposed WACOG in this case is 38.5 cents per therm,
which compares to 37.4 cents per therm approved in the Company's last annual PGA.2 As
reflected in Staff Chart 1, the proposed WACOG will be the second increase following several
years of consecutive decreases.
Chart I
The Company estimates its cost of natural gas for the next 12 months will increase
because the winter of 2013-2014 was colder than normal, which led to an increase in overall
natural gas demand. Consequently, underground storage reserves were drawn down below their
five-year average, resulting in both higher winter prices and higher summer prices when storage
is being replenished.
The Company's estimated cost of gas at the time of the PGA filing is usually close to
actual costs if forecasted annual throughput is accurate. The cost of gas may vary depending on
how weather and economic conditions impact usage. However, the majority of the Company's
2 This includes a conversion factor that adjusts revenue up to account for uncollectables, commission fees, and taxes.
Weighted Ave rage Cost of Gas ($/Therrnl
0.9000
0.8000
0.7000
0.6000trI o.sooo.c< 0.4000
0.3000
0.2000
0.1000
0.0000
'ro .* .*.* .f .or'
.+o'
STAFF COMMENTS ocToBER 17,2014
winter throughput is "locked-in" and won't change due to market conditions.3 During this
heating season (December 2014 - March 2015), the Company plans to hedge approximately 46Yo
of its estimated throughput requirements at a fixed price.a The Company also hedges against
high winter prices by purchasing gas in the summer and injecting it into underground storage at
its Jackson Prairie facility. According to the Company, approximately 36% of its estimated
throughput for the heating season will be met with gas in underground storage. Aside from the
Company's hedged and underground storage volumes, approximately l8Yo of the Company's
throughput for the heating season will be open to market index purchases.
On an annual basis, the Company plans to meet its estimated load requirement using 20%
underground storage, 35% hedges and 45%o index purchases.s The Company's storage WACOG
is expected to be $0.415 per therm, whereas the planned hedges and index purchases are
expected to be executed at a WACOG of approximately $0.425 per therm and $0.360 per therm,
respectively.
Market Fundamentals & Price Analysis
Staff closely analyzes the Company's projected monthly cost of purchased gas to see how
it compares to Staff s forecast, particularly given that nearly half of the Company's annual
throughput will be comprised of market index purchases. The Company continues to use a 30-
day historical average of forward prices to forecast an annual weighted average index price.
Specifically, the estimated monthly volumes to be purchased from production basins are
multiplied by the 30-day average forward price for the corresponding month and basin.
Staff developed its own volume weighted forecast using the NYMEXAIGX Futures
prices at each of the three hubs where the Company purchases gas.6 By using the Company's
estimated volume allocation percentages for the three hubs where it purchases gas, Staff
forecasted $3.6658/N{MBtu as the volume-weighted cost of gas. When compared to the
3 Locked-in means that the gas price is fixed and won't change due to market conditions.
n Utilities engage in "hedging" to minimize the price volatility of natural gas and other fossil fuels.
5 The percentages in this section are calculated using page 8 of Company Exhibit C.
u Avista 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 5 OCTOBER 17 ,2014
Company's forecasted mainline fuel cost of $3.8272lIt4MBtu, the Company's forecast is
comparable to Staff s forecast.T
Staffalso evaluates the forecasts ofnational and regional organizations to see how
perceived market conditions might vary from the NYMEXAIGX Futures prices. Specifically,
Staff reviewed the forecasts from the Energy Information Administration (EIA), the Northwest
Gas Association (NWGA), and the Northwest Power and Conservation Council (NWPCC).8
According to the most recent EIA report, Henry Hub prices are expected to decrease in 2015
from an average price of $4.584{MBtu in 2014, to $3.95/MMBtu in 2015. Similarly, the
NWPCC's medium case scenario predicts Henry Hub prices in 2015 to drop slightly, from
$4.73A4MBtu in 20l4,to $4.59/\4MBtu in 2015. The Company predominantly purchases from
the AECO basin, which this year is discounted by approximately llYo compared to Henry Hub
Futures prices.
Based on Staff s review of the market fundamentals, the 2014-2015 forecasts are
consistent, predicting relatively stable near-term gas prices. Staff also believes the Company's
weighted average cost of its current hedges and its estimated cost of forward-looking index
purchases are reasonable. Consequently, Staff recommends the Commission accept the
Company's proposed WACOG of $0.38510 per therm. Staff also recommends that the
Company return to the Commission with a new filing if prices materially deviate from the
proposed rates during the upcoming year.
Risk Management
The Company's procurement plan uses a structured approach to execute its hedges. The
plan includes a range of possible hedge windows with varying long-term and short-term trigger
prices. However, its procurement plan also allows it to make discretionary decisions so it can
adjust to changes in market conditions. The Company meets with Staff semi-annually to discuss
the status and performance of its Procurement Plan. This process allows Staff to evaluate
Company risk mitigation strategies that are designed to keep prices stable for customers. The
7 The Company's proposed WACOG of $3.85l0iIvIMBtu is slightly higher than the Company's mainline fuel cost
because it includes variable interstate transportation costs, and contributions to the Gas Research Institute (G2).t Staffutilized the October Short-term Energy Outlook (STEO), the NWGA's 2014 Gas Outlook, and the NWPCC's
Revised Fuel Price Forecasts for the Seventh Power Plan.
STAFF COMMENTS ocToBER t7,2014
Company mitigates risk to ratepayers with its market purchases, storage, and interstate
transportation capacity.
The Company plans to slightly increase the percentage of its mainline throughput
requirement using its index purchases while at the same time, decreasing its percentage of
hedged gas. According to the Company's Application, approximately 45Yo of its total annual
throughput will be index or spot purchases, compared to 43Yo last year. The Company's hedged
supply went from 38% of total annual throughput last year to 35Yo this year. Last year, 26%o of
the Company's hedges were comprised of volumes from prior multi-year hedges, compared to
22yo this year. According to the Company, it transacted fewer long-term discretionary hedges
because its trigger prices were based on a multi-year average, which incorporated historically
low gas prices. Recent gas prices have steadily increased, so the Company has reevaluated its
methodology for setting the trigger prices on its long-term hedges.
During the lower-priced summer months, the Company continues to inject gas into its
underground storage at its Jackson Prairie facility. This allows the Company to withdraw gas
during the winter season when market prices are traditionally higher. Compared to last year, the
Company plans to slightly increase the percentage of its underground storage withdrawals used
to meet its annual throughput requirement. This is partly because its hedged supply is locked in
at prices slightly higher than the storage WACOG. However, as winter throughput increases,
storage may also become a proportionally smaller piece of the Company's potential hedging
strategy because the capacity is fixed. This year, the Company's estimated sales volume for the
year increased, but its estimated sales volume during the heating season (December 2014 -
March 2015) decreased from 43,812,797 to 42,619,788 therms.
The Company utilizes interstate transportation capacity on several pipelines so that it can
purchase from a variety of basins, both in the US and in Canada.e Whenever the Company has
surplus capacity because demand is low, it sells capacity at the highest market price available
that day. Since the Company serves both Washington and Idaho, the benefits made from off-
system sales are credited to eachjurisdiction based on a three-year average ofthe five highest
consecutive days of gas consumption in each year. Below is a chart that shows the Company's
historical capacity release revenue for the two combined jurisdictions.
e Avista delivers domestically produced natural gas to its city gates through Northwest Pipeline, Gas Transmission
Northwest (GTN), TransCanada's Foothills Pipeline system (Foothills), and Spectra Energy Pipeline.
STAFF COMMENTS ocToBER 17,2014
Chart2
Historical Transportation Capacity Release Revenue
914.0.
i$12.0 i
5100 I
$8.0 l
96.0 I .
)9{.0 i
s2.0 :
5oo :
! Rwerrur
200ti P(iA
slr.5
2009 pGA
91o o
2010PCA I
510.6 i
2011 P6A
510.8
201]PGA I 2014PGAProp
s10.6 : 9e.4
The Company's total capacity release revenue this year is approximately $9.4 million, of
which Idaho receives approximately $2.7 million. Staff analyzed the allocations and confirmed
that Idaho was correctly allocated benefits from capacity releases. This year, some of the
Company's short-term capacity release credits on Northwest Pipeline expired. When this is
combined with an increase in summer capacity from Alberta Pipeline, demand costs increased.
However, the increase in the Company's forecasted throughput more than offsets the additional
fixed demand costs.
Overall, Staff believes the Company's strategies for its market purchases, storage, and
interstate transportation capacity reduce risk to ratepayers. The Company's changes to its
procurement plan appear reasonable given that current market forecasts indicate stable index
prices and mild winter weather. Staff reviewed the Company's hedges and believes they were
prudent. However, Staff encourages the Company to continue evaluating the historical
performance of its procurement plan so that its portfolio remains diverse and protects customers
from upward price risk. Further, Staff encourages the Company to continue looking for
opportunities to benefit customers by managing its interstate transportation capacity when it has
surplus capacity.
Schedule 155 - Deferred Expenses
The Schedule 155 portion of the PGA reflects the amortization of the Company's deferral
account. When the Company pays less for gas than what is estimated in the preceding WACOG,
a credit is issued to customers. However, if the Company pays more for gas than what is
STAFF COMMENTS ocToBER 17,2014
estimated in the preceding WACOG, a surcharge is added. As gas prices continued to rebound
throughout the year, Avista procured natural gas at costs slightly above what it had anticipated in
last year's filing. However, the excess deferral is offset by other activities that allow Avista to
rebate money to customers during the upcoming PGA year. The current Schedule 155
amortization rate is a surcharge of $0.00015 per therm. In this Application, the Company
proposes to decrease the Schedule 155 amortization rate by $0.03071 per therm, resulting in a
new Schedule 155 amortization rate of $0.03056 per therm credit. This new amortization rate
will refund to customers approximately $2.4 million during the next 12 months based on the
Company's weather-normalized load forecasts.
A reconciliation of the Schedule 155 deferral balance is shown on Table 2:
Table 2: Summary of Deferral Balance
Balance as of October 31, 2013 $ (57,537)
Amortization Activity (8.280)
Total Unamortized Balance $ (65,817)
Current Year Deferral Activity
Deferral of Price Differences $ 855,638
Interest on Deferrals (2,598)
Excess Capacity Releases (2,343,166)
Deferred Exchange Contract (394,000)
Transportation Costs Correction (487.554)
Total Current Year Deferral Activity $ (2.371.680)
Balance to be Amortized S (2,437,498)
The deferral activity consists of the difference in the price Avista paid for natural gas and
the WACOG established in the previous PGA, monthly interest charges on the deferred balances,
and excess capacity releases for the benefit of customers. When Avista has unused capacity, it
routinely releases that capacity to other pipeline users. During the 2014 PGA year, Avista's
Idaho gas customers benefitted by $2.3 million from this practice.
Additionally, on April 1, 2014, Avista entered into a new Deferred Exchange contract
with a counterparty whereby the Company receives natural gas during the summer and re-
delivers that natural gas in winter. The Company charges a fixed per therm charge for this
service. The net benefit provided to customers from this agreement in this PGA is $394,000, and
reflected in the deferral activity in the table above.
STAFF COMMENTS ocToBER 17,2014
The deferral balance was also decreased by an additional $487,554 to adjust for an over-
collection error related to the allocation of AECO natural gas transport costs between the
Company's power supply operations and the Company's natural gas distribution operations.
Correcting this over-recovery benefits natural gas customers by shifting costs from the
Company's natural gas operations to the Company's electric operations. A similar correction
was also reflected in the Company's most recent Power Cost Adjustment (Case. No, AVU-E-I4-
06). The Company notified Staff of the allocation error in its December 2013 monthly PCA
deferral report filed with the Commission on January 16,2014.
Other Considerations
Staff reviewed the Company's LAUF gas volume and compared it to total throughput.
Staff believes the Company's LAUF gas volume is reasonable compared to other local
distribution companies (LDCs). However, typically the Company's LAUF gas information is
only provided when Staff requests it on an as needed basis. Staff believes that information
necessary to complete the review should be included as a workpaper in the Company's
Application. LAUF gas is an important part of Staff s annual review. Going forward, the
Company has agreed to provide a workpaper with its Application that includes a retrospective
look at the actual LAUF gas percentage of overall throughput.
Customer Relations
The Company's press release and customer notice were included in the Application.
Staff reviewed the documents and determined that both meet the requirements of Rule 125 of the
Commission's Rules of Procedure (IDAPA 31.01.01 .125).
The customer notice was included with bills mailed to customers beginning September l7
and ending October 15,2014. Customers have the opportunity to file comments on or before
October 1,7,2014. As of October 17, the Commission has not received any customer comments.
STAFF RECOMMENDATION
After thoroughly examining the Company's Application, natural gas purchases, and
deferral activity for the year, Staff recommends that the Commission:
STAFF COMMENTS l0 ocroBER 17,20t4
1.
Technical Staff: Daniel Klein
Donn English
Matt Elam
i :umisc/comments/avugl 4.4djhdkdeme comments
2.
Approve the Company's proposed Schedule 150, including the proposed WACOG of
$0.38510 per therm; and
Approve the Company's proposed Schedule 155 amortizationrate of $0.03056 per therm
credit to refund approximately $2.4 million to customers. The combination of Staff s
recommendations will result in a net decrease in the Company's Idaho natural gas
revenue by approximately $ I .6 millio n or 2.lYo.
Respectfully submitted this l?Pdayof octo ber2ot4.
1tSTAFF COMMENTS ocToBER 17,2014
CERTIFICATE OF SERVICE
I HEREBy CERTIFy rHAT I HAVE THIS l7'h DAy oF ocroBER 2014,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. AVU-G-T4-04, BY E.MAILING AND MAILING A COPY THEREOF,
POSTAGE PREPAID, TO THE FOLLOWING:
KELLY O NORWOOD
VP STATE & FED REG
AVISTA CORPORATION
PO BOX3727
SPOKANE W A 99220-3727
DAVID J MEYER
VP & CHIEF COUNSEL
AVISTA CORPORATION
PO BOX3727
SPoKANE WA99220-3727
E-MAIL: [e-mail] E-MAIL: [e-mail]
CERTIFICATE OF SERVICE