20091026Redacted Comments.pdf

KRISTIE A. SASSER
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
BARNO. 6618
RECEI\Îf,!"'j1. ~"r 7 ),~~ t....
2009 OCT 16 PH I: 34
IDAHO PUbUG
UT!LlílES COMr'!1SSION
Street Address for Express mail
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
A VISTA CORPORATION DBA A VISTA)
UTILITIES FOR AUTHORITY TO CHANGE )
ITS NATURAL GAS RATES AND CHARGES )
(2009 PURCHASED GAS COST ADJUSTMENT). )
)
CASE NO. A VU-G-09-05
COMMENTS OF THE
COMMISSION STAFF
The Staff of the Idaho Public Utilities Commission, by and through its Attorney of
record, Krstine A. Sasser, Deputy Attorney General, in response to the Notice of Application
and Notice of Modified Procedure (Order No. 30912) submits the following comments.
BACKGROUND
On September 15,2009, Avista Corporation dba Avista Utilities (Avista; Company) fied
its anual Purchased Gas tost Adjustment (PGA) Application requesting authority to decrease
its anualized revenues by approximately $14.7 milion. Application at 1. The PGA mechanism
is used to adjust rates to reflect anual changes in Avista's costs for the purchase of natural gas
from suppliers - including transportation, storage, and other related costs. Avista's earings wil
not be decreased 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 1,2009.
The COmpany states that if the proposed changes are approved its anual revenue wil
decrease by approximately $14.7 milion or 17.8%. The average residential or small commercial
customer using 66 therrs per month wil see a decrease of $12.74 per month.
STAFF COMMENTS OCTOBER 16, 2009
The Company states that it purchases natural gas for customer usage and then 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 actual Weighted Average Cost of Gas (WACOG) purchased and the WACOG
embedded in rates. The Company states that it also defers the revenue received from the release
of its storage capacity as well as various pipeline refunds or charges and miscellaneous revenue
received from gas-related transactions.
Avista proposes decreasing the WACOG from the currently approved $0.75984 per
therm to $0.49093 per thermo The Application asserts that wholesale gas prices have fallen
dramatically since July 2008 and the Company has been hedging gas on a periodic basis
throughout 2009 for the coming PGA year. The Company states that approximately 64% of its
estimated anual load requirements for the PGA year will be hedged at a fixed price comprised
of: (1) 42% of vol ures hedged for a term of one year or less; (2) 10% of prior multi-year
hedges; and (3) 12% from underground storage. The Company states that through August 2009,
most of the planed hedge volumes for the PGA year have been executed at a weighted average
price of$0.582 per thermo
The demand costs included in the Company's Application primarily represent the costs of
pipeline transportation to the Company's system. Avista's proposal includes essentially no
change in the demand cost included in rates. Application at 4.
The Company is also proposing a change in the present amortization rate that is used to
refund or surcharge customers the difference between actual gas costs and projected gas costs
from the last PGA fiing though the past year. The present amortization rate for firm sales- .
customers is a $0.1580 per therm refund. Avista is proposing a $0.0760 per therm increase in the
amortization rate for firm sales customers. In order to mitigate a potential 20 I 0 PGA increase,
the Company proposes to refund the deferral balance over a two-year period, rather than one.
Application at 4.
A vista asserts that it has notified customers of its proposed decrease in rates by posting a
notice at each of the Company's distrct offices in Idaho, by means of a press release distributed
to various informational agencies, and by separate notice to each of its Idaho gas customers via a
bil insert. The Company requests that this matter be handled under Modified Procedure
pursuant to Rules 20 i -21 0 of the Commission's Rules of Procedure.
STAFF COMMENTS 2 OCTOBER 16, 2009
ST AFF ANALYSIS
Staff has reviewed the Company's Application to determine whether its adjustments to
Schedule 150 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. In
addition, Staff has reviewed the Application to determine whether the Company's Schedule 155
proposed two-year amortization rate appropriately passes back the deferral account credit
balance to customers. When combined, Schedules 150 and 155 make up the PGA. Each
component wil be discussed in greater detail below.
Schedule 150 - Purchased Gas Cost Adjustment
The Schedule 150 portion of the PGA is comprised of two pars: 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. This also includes the benefit of some off
system transactions such as the T erasen Reservation Credit. The demand costs represent the cost
of pipeline transportation to the Company's distrbution system. As stated in the Application,
"there is essentially no change in the demand costs included in rates." In this Application the
proposed WACOG is $0.49093 per therm compared to the present $0.75984 per therm WACOG
settled in the last rate case as par of Order No. 30856. The PGA rate reductions in this proposal
and throughout the past year have been because of decreases in the overall WACOG. More
specifically, this proposaljrops the WACOG by approximately 35% and drops Schedule 101- .
revenue by approximately $15.1 milion.
Weighted Average Cost orGas (WACOG)
Throughout the last year there have been substantial declines in the wholesale cost of
natural gas, which have allowed A vista to purchase gas for the coming year at favorable rates.
Aside from this spring's settled rate case, this request reflects the third decrease within the
Company's past four PGA fiings, and makes the Company's proposal the lowest rate since the
2003 filing. The table below ilustrates the changes in the natural gas market over the past eight
years and the volatility experienced over the same period.
STAFF COMMENTS 3 OCTOBER 16, 2009
Approved % Change Resulting Total % Change
Year Tariff Weighted Avg.From General Service From
Was Cost of Gas Previous Schedule 101 Previous
Established $rrherm Year Tariff, $rrherm 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%
(Company
Proposed)
*The W ACOG change was part of the A VU-G-09-0 I settlement intended to offset the impact of the residential base
rate increase approved in Order No. 30856.
In addition to the national economic impact on weather adjusted demand, a number of
factors have contributed to excess supplies throughout the past year. Several influencing factors
contrbuting to this supply include: (1) the cooler summer reduced the need for natural gas fired
electrc generation; (2) the discovery of an abundance of North American shale reserves; (3) the
spread of global recession:ed to higher than normal supplies of Liquid Natural Gas (LNG); (4)
the volume of natural gas in storage exceeded historical averages and continued to increase
through the injection season; and (5) the surge in driling rigs brought on by last summer's high
prices.
In order to estimate natural gas prices for the following year the Company used a 30-day
historical NYMEX average of forward prices (ending August 31) by supply basin to develop an
estimated cost associated with index/spot purchases. The estimated monthly volumes to be
purchased by basin are multiplied by the 30-day average price for the corresponding month and
basin. The Company has already hedged 64% of its estimated anual load requirements at a
fixed price of$0.582 per thermo The index spot volumes, using Company estimated future
STAFF COMMENTS 4 OCTOBER 16,2009
prices, represents approximately 36% of the estimated annua1load requirements in the coming
year. It has estimated the weighted average price for these volumes to be $0.478 per thermo
Upon review the Company's estimates for these volumes seem reasonable given NYMEX
forward prices. However, Staff has estifuated approximately a 24% average premium built into
the 20 i 0 NYMEX prices when compared to the estimates of third party forecasters. It is
understandably diffcult to estimate the risk margin built into forward prices in these dynamic
times. Consequently, Staff encourages ~he Company to closely watch these as a number of
determining factors develop throughout Ithe year.
When evaluating the Company'~ estimates against data from the NYMEX Futures Index,
Energy Information Administration (EIl), and Wood Mackenzie, the Company seems to have
estimated prices slightly higher than antIcipated. The following factors support lower estimated
prices through October 2010: (1) slight Iglobal economic improvements are only expected to
increase consumption 0.5 percent in 20110 from a comparative decline of 2.6 percent in 2009; (2)
¡
compared to 2009, the 2010 expectationl of lower coal prices is anticipated to lead to slight
i
reductions in natural gas use by the electric power sector; (3) Gulf of Mexico production is
expected to increase by 3.3 percent this ~ear because of a lower anticipated incidence of
hurrcane activity and several deep water fields coming online; (4) Liquefied Natural Gas (LNG)
imports are expected to increase by 240 Ibcf in 2010 as the U.S. becomes the most attractive
import market; and (5) the EIA is forec"sting fewer heating degree days than normaL.
i
i
Given that the Company has he~ged 64% of its estimated load requirements for the
!
upcoming year at fixed prices, and it est~mates the additional volumes to be purchased at $0.478
per therm, StaffrecommeQds the Cornission accept the Company's proposed $0.49093- .
WACOG. However, if spring and surner prices significantly deviate from the proposed rates,
the Company should return to the Comaiission with a new filing.
Schedule 155 - Deferred Expenses
The Schedule 155 portion ofthelPGA is the amortization component of the Company's
i
deferral account. When the Company p~ys more for gas than what is estimated in the preceding
WACOG, a surcharge is issued to custobers. However, if the Company pays less for gas than
!
what is estimated in the preceding WAqOG, a credit is issued to customers. Gas prices have
continued to fall throughout the year cotnpared to the WACOG anticipated in the Company's last
STAFF COMMENTS 5 OCTOBER 16, 2009
fiing, and as part of the adjustment in the last rate case settlement. By November 2009, the
deferral balance is expected to leave customers with a refund of $12.3 milion.
Typically the deferral balance is amortized over one year through a credit or surcharge.
However, in this PGA fiing the Company has proposed to refund the deferral balance over a
two. year period. The Company believes that the substantial W ACOG reduction in this fiing
presents a unique opportunity to mitigate future PGA increases through a two-year refud of the
deferral balance. The inherent risk to customers of a two. year amortization centers around gas
prices continuing to drop (or being less than the estimated WACOG), and therefore contributing
to a larger deferral account credit owed to customers. Staff believes that the risk of higher gas
cost for customers next year under a single year amortization is diminished by continued growth
in the Schedule i 55 deferral balance for refund since June 30, 2009. Staff also cites the potential
for a lower W ACOG than that included by the Company in this case.
Similar to the PGA, in 1993 the Commission instituted a "Power Cost Adjustment"
(PCA) to ameliorate the adverse consequences of fluctuating power supply costs both to
customers and the Company. Therefore, ratepayers receive a credit when power costs are lower
than anticipated in the previous year, and a surcharge when power costs are higher than
anticipated in the previous year. In two prior cases, IPC-E-O 1-07 and IPC-E.O 1- i i, Idaho Power
sought to recover a combined $227.4 milion in power purchase costs over a one-year period.!
Staff and intervening paries recommended a more flexible time period for admini;;tering the
tre-up of approximately $168.3 milion. The Commission declined to adopt these
recommendations and determined it was "reasonable and appropriate for the Company to recover
these costs within the no~al one ye~ time frame." In Order No. 28852, the Commission- .
reinforced its decision in Order No. 28722 by stating that it must "balance the needs of the
Company to maintain its financial viability with customer concerns of fair rates and rate
stabilty. "
Based on prior Commission decisions and reasoning, Staff recommends in the present
PGA filing that the Commission amortize the deferral credit balance to customers over one year.
When a credit is due, business owners and familes are entitled to maintain financial viabilty to
the same extent that the Company enjoys in a surcharge situation. Nationally, according to the
i In Order No. 28722 regarding these cases, the Commission questioned the prudency of certin power purchase
costs, and therefore deferred the recoveiy of approximately $59 milion pending further investigation.
STAFF COMMENTS 6 OCTOBER 16, 2009
Small Business Administration (SBA), an estimated 627,200 new employer firms began
operations in 2008, and 595,600 firms closed that same year. Although conditions have shown
signs of improvement in the second and third quarters of this year, many businesses need relief
now in order to keep doing business. For many of these businesses, ifrate relief is not received
now, they may have paid into a deferral account they wil never have returned. According to a
report filed by the Idaho Department of Labor, "The rapid escalation ofIdaho's unemployment
rate has hit every county. Fifteen had double digit rates in August 2009, and every county had a
rate higher than a year earlier." Families have had to make decisions between purchases to put
food on the table and paying bils to heat their homes. The economic climate remains
challenging for businesses and familes alike. Given past Commission decisions regarding the
amortization of rate adjustment mechanisms, the curent economic conditions, and the low risk
of gas price increases next year, Staff recommends the Commission amortize the deferred credit
balance over one year instead of accepting the Company's proposed two-year amortization. If
Staffs recommendation is approved, the per therm amortization rate for Schedule 155 wil
increase by 2.008 cents per therm for customers on tariff Schedules 101 and ILL and 0.433 cents
per therm for customers on tariff Schedule 131. When this is combined with the proposed
decrease in Schedule 150 rates, the Company's annual overall revenue wil decrease by
approximately $18.8 milion or about 22.9%, as compared to the Company's proposal of
approximately $14.7 milion or about 17.8%. The calculation of Staff s proposal can be seen in
Attachments 1 through 5.
Hedging Policies _
The Company's gas procurement plan generally incorporates a structured approach for
the hedging portion of the portfolio, however it also maintains flexibility in its plan so
discretionar adjustments can be made when the wholesale gas market changes. Discretion is
used in evaluating curent volatility, forward curve shapes, and alternatives when considering
price triggers. The Company continues to hedge utilizing a series of price targets. In the case of
decreasing prices, target purchase volumes are increased. The Company meets with Staff to
collaborate on the procurement plan given the wholesale natural gas environment. In meetings
this spring, the Company informed Staff of several additions to its long-term hedging strategies.
Specifically, the Company has: (1) defined its pricing target
STAFF COMMENTS 7 OCTOBER 16,2009
(2) decided to keep long-term hedges open for up to
two or three years, depending on which strip triggers first; (3) decided price targets wil be
"open" all year; and (4) dropped the minimum portfolio hedge percentage by 10% with an
additional 15% carved out for discretionary action. 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 communicated with
Staff regarding its storage and procurement activities
Given volatilty in the natural gas
market over the last two years, the Company has done a reasonable job of maintaining a
procurement plan that is structured but provides discretionar decision making. The Company
continues to purchase gas at favorable prices and provide stability to customers.
CONSUMER ISSUES
Customer Notice and Press Release
The press release was included in Avista's original Application. The Application was
received September 15, 2009. Staff obtained a copy of the Customer Notice. Staff reviewed the
original customer notice and press release and determined that the Company was in compliance
with the requirements of IDAPA 31.21.02.102. The customer notice was mailed with cyclical
bilings beginning September 20,2009 and ending October 20,2009.
Customer Comments
Customers were giYen until October 16,2009 to fie comments. As of October 16,2009,
no comments had been fied by customers.
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) That the Company's proposed changes to the Schedule 150 (Purchased Gas Cost
Adjustment) be accepted. In doing so, Staff recommends that the Commission accept the
proposed W ACOG of 49.093 cents per therm which results in a Schedule 150 credit of
STAFF COMMENTS 8 OCTOBER 16, 2009
26.922 cents per therm for customers on tariff Schedules 10 1, 111 and 112 and a credit of
26.891 cents per therm for interruptible customers on Schedules 13 i and 132.
2) That the Commission approve a one-year amortization of deferral balances. In doing so,
Staff recommends that the Commission accept a proposed decrease in the credit of 2.008
cents per therm for customers on tariff Schedules 101, and 111 and a decrease in the
credit of 0.433 cents per therm for customers on tariff Schedule 131. This would result in
a decrease to the Company's annual overall revenue by $18,881,959 or 22.90%. This
compares to the Company's proposal that results in an anual overall revenue decrease
by $14,699,479 or 17.83%.
3) Staff also recommends that the Commission reserve the right to reopen this case and
reevaluate any approved tariffs if the W ACOG materially changes below that included in
this Application.
Respectfully submitted this I Co!! day of October 2009.
~d.~4l'l
Krs me A. Sasser
Deputy Attorney General
Technical Staff: Matt Elam
Donn English
Daniel K-lin
i:umisc:commentsavug09.Sksdedkme comments. doc
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Idaho Public Utilities Commission
StaWs Proposal
Calculation of Idaho Proposed Rates
--
Attachment 2
Case No. A VU-G-09-05
~t"ff rl'mmpnt"
Idaho Public Utilties Commission
Staffs Proposal
Average Increase Per Customer
Average Average Present Total Proposed Total Estimated EstimatedSchNo. of Mo. Usage Rate Present Rate Proposed Monthly Decrease
No.Customers Description Per Cust.,Cost Cost Decrease Percentage
101 69,515 66 $1.07507 $70.95 $0.82593 $54.51Basic Charge $4.00 $4.00 $4.00
$74.95 $58.51 ($16.44)-21.93%
111 792 1,971
First 200 $1.05595 $211.19 $0.80681 $161.36
Next 800 $0.99223 $793.78 $0.74309 $594.48
1,0001 -10,000 $0.91764 $891.03 $0.66850 $649.11
Over 10,000 $0.87680 $0.62766
$1,896.00 $1,404.95 ($491.05)-25.90%
131 None $0.82778 $0.56320 -31.96%
132 35,236 $0.94811 $33,407.60 $0.67920 $23,932.29 ($9,475.31)-28.36%
70,308
Attchment 3
Case No. A VU-G-09-05
Staff Comments
Attchment 4
Case No. A VU-G-09-05
Staff Comments
Idaho Public Utilties Commission
StaWs Proposal
Gas Rate Adjustment (Schedule 155)
Calculation of Changes
Schedule
Current Proposed Total
Rate Rate Proposed
Incr ~Decr::Incr ~Decr::Incr~DecP
($0.15805)($0.13797)$0.02008Firm Customers, Schs 101 & 111
Firm Customers, Schedules 112
Interruptible Customers, Schedules 131 ($0.120~3)($0.11600)$0.00433
Interruptible Customers, Schedules 132
Transportation Customers, Schedules 146
Special Amortization Rates
Attachment 5
Case No. A VU-G-09-05
Staff Comments
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 16TH DAY OF OCTOBER 2009,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN CASE
NO. AVU-G-09-05, BY MAILING A COPY THEREOF, POSTAGE PREPAID, TO THE
FOLLOWING:
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL
A VISTA CORPORATION
PO BOX 3727
SPOKANE W A 99220
E-MAIL: david.meyeraYavistacorp.com
KELLY NORWOOD
VICE PRESIDENT - STATE & FED. REG.
A VISTA UTILITIES
PO BOX 3727
SPOKANE W A 99220
E-MAIL: kelly.norwoodaYavistacorp.com
~~~
SECRETARY
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CERTIFICATE OF SERVICE