20140915Comments.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:
472W. WASHINGTON
BOISE, IDAHO 83702-59I8
Attorney for the Commission Staff
IN THE MATTER OF AVISTA
CORPORATION'S APPLICATION TO ADJUST
ITS ANNUAL POWER COST ADJUSTMENT
(PCA) RATES.
; ,'.- -- l- r . ,.1 -
inltr $[P l5 Pt4 3: 0l
rF:, ! trr r.! I .: .1,:.,'.'',:'..', :'; l'' :i:t .^'i i. I(l^',- ,,r-r r'.-!r -"-r. ,,"uiJiLl,'.
CASE NO. AVU.E.14.O6
COMMENTS OF THE
COMMISSION STAFF
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
The Staff of the Idaho Public Utilities Commission comments as follows on Avista
Corporation's Application to adjust its Annual Power Cost Adjustment (PCA) Rates.
BACKGROUND
On July 30,2014, Avista Corporation dba Avista Utilities (the Company) filed its annual
PCA Application. The Company asks the Commission to let it recover $7.7 million in deferred
net power costs through a0.252(, per kilowatt-hour (kwh) PCA surcharge to be effective
October 1,2014.
The Company's PCA mechanism tracks changes in the Company's revenues and costs
due to changes in hydropower generation, power market purchases and sales, fuel costs, and
other miscellaneous revenues and costs. In this case, the Company attributes its increased net
power supply expenses to:
o a forced outage at Colstrip Unit 4 that required the Company to buy replacement
power at a higher wholesale price;
STAFF COMMENTS SEPTEMBER 15,2014
. 90o of the net expense of Palouse Wind flowing through the PCA as a surcharge
deferral instead of being included in base rates; and
. a change in the Company's contract with Clearwater Paper that enables Clearwater to
generate into its own load instead of selling its generation to the Company.
The Company says the proposed0.252f, per kWh PCA surcharge would collect: (1)
deferrals from July 1,2013 through June 30,2014 (plus interest); (2) unrecovered balances for
the July 1,2012 through June 30, 2012 defenal period; (3) estimated interest during the period
the new PCA rate will be in effect (October 1,2014 through September 30,2015); (4) a
correction to the misallocation of natural gas transport costs; and (5) a credit for the 2013
earnings test proposed in Case No. AVU-E-14-05. If approved, the Company's proposed,
0.252(, per kWh PCA surcharge would be a0.404( per kWh increase over the 0.152(, per kWh
rebate set in last year's PCA case.
The Company-proposed, overall rate increase to customers of 4.99oh is reflected by
schedule below:
Type of Service Schedule Billed Revenue 7o Increase
Residential I 4.44%
General Service 11,t2 3.90%
Large General Service 27,22 5.02%
Extra Large General Service 25 7.41%
Clearwater 25P 7.98%
Pumping Service 37,32 4.37%
Street and Area Lights 4t-49 1.66%
Total 499%
About 38% of the overall rate increase is due to the elimination of last year's PCA rebate. The
remaining 62%o increase occurs because the Company's power supply costs during the
July 1, 2012 through June 30,2014 deferral period were higher than the Company's power
supply costs embedded in base rates.
STAFF COMMENTS SEPTEMBER 15,20I4
STAFF REVIEW
Staff thoroughly reviewed the Company's PCA Application, including: (A) Actual
and authorized expense audit; (B) Net defenal activity; (C) Deferral calculation methodology;
(D) Authorized-to-actual net power supply expense analysis; (E) Other surcharge adjustments;
and (F) Proposed PCA rate adjustments. Staff Review is summarized below.
A. Actual and Authorized Expense Audit
Staff conducted an onsite audit from August 18-22,2014. Staff reviewed and audited the
actual expenses the Company incurred from July 2013 through June 2014. Staff examined a
representative cross section of transactions included in the Purchased Power account (FERC
555), Thermal Fuel account (FERC 501), Combustion Turbine Fuel account (FERC 547), and
the Power Sales Revenue account (FERC 447). Based on its review of these transactions, Staff
concludes that the various power cost transactions were reasonable when made. Staff also
reviewed the other PCA calculations and amounts, including the Natural Gas Transport Costs
previously charged to natural gas customers, and the Company's adjustment to Renewable
Energy Credit (REC) revenue. Staff finds the amounts the Company booked to the PCA deferral
account, and the Company's other calculations, to be correct.
Staff also verified all the authorized amounts used to calculate the base-to-actual deferral.
Staff believes the base amounts properly reflect the rates established in Commission Order from
the applicable general rate case.
B. Net Deferral Activity
The "net deferral activity" is Idaho's jurisdictional share of the power cost differences
from base and the associated revenue adjustments that the Company has deferred under the PCA
mechanism for the twelve months ending June 30, 2013. The net change in Power Supply Costs
(FERC Accounts 555, 501, 547 , and 447) is one component of the net deferral. The Power
Supply Cost accounts include the Company's cost to serve its load with its own resources, and
also include additional power purchase costs that the Company incurs when market prices are
lower than generation costs. Generation costs associated with off-system sales are reduced by
the revenue from those sales. The Company's proposed $7,705,909 deferral amount, consists of
the following items:
STAFF COMMENTS SEPTEMBER I5,2014
l. FERC Account 555 - Purchased Power
2. FERC Account 501 - Thermal Fuel
3. FERC Account 547 - CT Fuel
4. FERC Account 447 - Sales for Resale
5. All Clearwater Revenues and Expenses
6. Resource Optimization - Gain on Natural Gas Resold
7. Idaho Retail Revenue Adjustment
8. Net Transmission Revenue and Expense
9. Adjustment to RECs
10. Interest during deferral period
Total
$33,946,400
(2,714,373)
5,672,255
(24,246,033)
2,320,289
(3,427,093)
(4,127,399)
420,267
(157,t29)
63.725
$7,705,909
The ten items comprising the total proposed defenal amount are discussed below.
l. FERC Account 555 - Purchased Power. Purchased Power costs reflect90% of the
Idaho jurisdictional share of the difference in costs the Company incurred for power purchases in
the review period compared to normalized purchased power costs included in base rates. In the
review period, the Company incurred more purchased power costs than are included in base
rates. The positive amount represents a cost to customers.
2. FERC Account 501 - Thermal Fuel. Thermal Fuel, primarily coal, is used to produce
electricity. The amount is90% of the Idaho jurisdictional share of the difference in costs the
Company incurred for thermal fuel compared to the normalized amount included in base rates.
During the review period, the Company incurred lower coal costs than are currently included in
base rates. The negative amount represents a benefit to customers.
3. FERC Account 547 - CT Fuel. Combustion Turbine (or CT) Fuel is natural gas
burned in the Company's gas-fired generators. This amount represents90%o of the Idaho
jurisdictional share of the difference in costs the Company incurred for gas generator fuel
compared to the amount included in normalized base rates. In the review period, the Company
incurred more natural gas cost than is currently included in base rates. The positive amount
represents a cost to customers.
4. FERC Account 447 - Sales for Resale.Sales for Resale are long-term and short-term
off-system sales. The negative amount represents 90Yo of the Idaho jurisdictional share of the
increase in off-system sales revenues above the amounts included in base rates. This negative
amount represents an increase in sales for resale revenues, a decrease in costs during the review
period, and is a benefit to customers.
STAFF COMMENTS SEPTEMBER 15,2014
5. Clearwater Revenues and Expenses. The Clearwater revenue and expense
components are directly assigned to Idaho and are not subject to sharing. They are based on the
difference between the Company's costs and revenues from serving Clearwater's Lewiston
facility and the Company's normalized costs and revenues from serving Clearwater as
established in the Company's last general rate case.
A contract that expired just before the start of the deferral period (July 2013 -
June 2014) is included in base rates. This contract included the Company's purchase of
Clearwater self-generation at PURPA avoided cost rates. Clearwater is currently a Schedule 25P
customer; however, the revenues and expenses for the expired Clearwater contract will remain in
base rates until new base rates are set in a general rate case.
In the review period, the Company recorded base revenues and expenses, with no
offsetting Clearwater revenue and expenses separately stated. The net amount of Clearwater
revenue and expenses included in base rates is $2,320,289. This positive amount represents a
cost to customers.
6. Resource Optimization - Gain on Natural Gas Resold. Resource Optimization results
in a cost or benefit to customers when natural gas purchased in advance for use in generating
plants is later sold because it is more cost effective to sell the gas and purchase electricity than it
is to generate electricity with the gas. The PCA includes ninety percent of the Idaho
jurisdictional share of the gain or loss on the sale of the gas transactions resulting from
optimizing Company resources. The gain during the review period, shown as a negative amount,
is a benefit to Idaho customers. Staff notes that this line item only shows one side of the
transaction when the Company uses its power plants for economic dispatch, and should not be
looked at independently from the entire optimization of Company resources.
Staff has verified that when the Company initially purchased the gas, the cost of
producing electricity at the Company's natural gas plants (primarily the Coyote Springs and
Lancaster facilities) was less than the cost of buying electricity on the open market to meet the
Company's native load. Furtheffnore, Staff has verified that when the Company resold the gas
and purchased electricity to meet native load, the resale of the gas and corresponding electricity
purchased was the least expensive and most cost-effective alternative.
7. Idaho Retail Revenue Adjustment. The Idaho Retail Revenue Adjustment is a load
change adjustment that removes the average, energy-related cost of production from PCA
STAFF COMMENTS SEPTEMBER I5,2OI4
calculations when load grows, as it has done in this case. When load declines, the adjustment
adds back the average energy-related cost ofproduction at the currently approved rate. The rate
changed from $26.6344Wh to $26.97 on October 1,2013. This rate is reestablished whenever
base power supply costs are reset. The rate is multiplied by the change in load to produce the
adj ustment, excluding Clearwater Paper generation.
The PCA includes ninety percent of the total Idaho Retail Revenue Adjustment. In
the review period, the Company experienced an increase in load. Thus, there is a negative
adjustment. The negative amount represents a benefit to customers.
8. Net Transmission Revenue and Expense. In the 2009 general rate case, AVU-E-09-
01, the Company proposed, and the Commission Staff agreed, to include transmission revenues
and expenses in the PCA. The Company incurs third-party transmission costs when it buys
power and has that power wheeled or delivered to its service area by a third party. The Company
also incurs third-party transmission costs when it sells power and pays a third party to deliver
that power. Third-party transmission revenues occur when the Company is the third party that
delivers power for others. Including transmission revenues and expenses in the PCA tracks the
variability of these items. In the review period, the difference in transmission expenses was
more than the difference in transmission revenue, and the net of the transmission revenue and
expense differences is a cost to customers.
9. Adjustment to RECs. In the deferral period, the Company made two adjustments to
REC revenue, both of which favor customers. First, a $123,048 revenue adjustment was made to
reflect a correction in recording authorized Idaho REC revenues during 2013. Second, the
deferral balance includes $46,386 in REC revenue to reflect Idaho's share of the value of system
RECs used by Washington. This $46,386 is compensation from Washington to Idaho for Idaho's
allocation of RECs from hydro upgrades used to meet the Washington Energy Independence Act
requirements in 2012. The total -a negative $157,129- is a benefit to customers.
10. Interest durine Deferral Period. The Company calculates deferral balance interest
using the methodology stated in Order No. 29323, Case No. AVU-E-03-04. Staff reviewed the
Company's interest calculation and found it to be correct. The Company uses the Customer
Deposit Rate to calculate interest on current year deferrals and on carryover balances from one
year to the next. The Customer Deposit Rate for 2013 and for 2014 is lYo. Interest on the
6STAFF COMMENTS SEPTEMBER 15,2014
deferral balance accumulates during the deferral period at the customer deposit rate. In this
review period, the interest is a cost to customers.
C. Deferral Calculation Methodology
Staff reviewed the Company's overall deferral calculation methodology while focusing
on two areas of potential concern: the Load Change Adjustment and the calculation of
Clearwater deferral amounts.
This year's PCA reflects a base rate over-recovery due to change in load of $4.6 million
(credit to customers minus sharing), which is done through the Load Change Adjustment Rate
(LCAR). The Company used Idaho jurisdictional energy-classified production expenses and
base rate sales to calculate the LCAR in the last general rate case. This was appropriately
applied to the difference in Idaho base-to-actual sales during the deferral period in the
Company's Application. Staff believes the Company's use ofjurisdictional sales to determine
the change in load is superior to methods that use loads measured at generation to estimate over
or under recovery through base rates. The Company's method eliminates inaccuracy caused by
base-to-actual differences in line loss and jurisdictional allocation factors.
Clearwater Paper and the Company operated under a new contract during the defenal
period. In reviewing the case authorizing the contract and its treatment in the PCA, Staff
verified that the Company did not purchase any Clearwater self-generation instead of offsetting
generation to meet its own load requirements. Staff also verified that Clearwater authorized self-
generation amounts were not included in the authorized sales amounts used to calculate the Load
Change Adjustment. Including these amounts would have resulted in double revenue recovery
through the Load Change Adjustment.
Overall, Staff believes the Company's PCA methodology complies with all past
Commission Orders. Staff also believes this methodology adjusts base rates so the Company
only recovers its actual power supply costs, minus sharing.
D. Authorized-To-Actual Net Power Supply Expense Analysis
Staff analyzedthe Company's actual net power supply expense as compared to expense
embedded in base rates. This analysis was especially important due to nearly seven months of
Colstrip Unit 4 forced outage that caused the Company to replace almost 420,000 MWh of low-
STAFF COMMENTS SEPTEMBER 15,2014
cost generation with other sources of generation, which in turn increased the deferral by about
$4 million. In light of the Colstrip outage, Staff considered whether Avista should receive
recovery for increases in net power supply expenses due to the outage and whether the
Company's net power supply expense was reasonable.
Staff examined the Company's data request responses and found no definitive evidence
of Company, PPL Montana (facility operator), or third-party neglect or malfeasance causing the
Colstrip outage. In addition, although there was insurance that covered property damage, the
Company has no insurance that covers the cost of increased power supply expenses. Staff agrees
with the Company that the Company's portfolio of resources and access to electricity markets
should hold sufficient reserves to cover both forced and unforced outage. By design, Staff
believes this is an appropriate form of insurance to cover these types of outage occunences.
Based on the evidence presented, Staff believes reasonably incurred increases in net power cost
due to the Colstrip Unit 4 outage should be included for recovery in the Company's Application.
To determine reasonableness of overall net power supply expense, Staff compared actual
versus authorized net power supply expense by category for each month of the deferral period.
A summary of the defenal period is shown in the table below.
As seen in the table, the Colstrip outage reduced total coal cost while forcing the
Company to increase its purchased power and natural gas generation costs when compared to
those embedded in base rates. Because coal generation unit cost ($16.74lMWh) is far less
expensive than market ($31.37lMWh) and natural gas generation ($33.5944Wh), the Company
incurred about a $4 million in additional deferred PCA costs. Staff also analyzed market and
natural gas unit costs on a monthly basis and believes that the Company made good decisions in
trading off between generating with its natural gas combined cycle units and going to market to
make up for lost coal generation capacity. The Company also gained additional benefits for
Expense Category Authorized ($ million)Actual ($ million)Actual ($/lv[Wh)
Purchased Power (Acct 555)$88.2 $196.7 $31,37
Sales for Resale (Acct 447)$s7.6 $ l3s. I $3s.68
Thermal Fuel (Coal - Acct. 501)$31.0 s22.2 $t6.74
CT Fuel (Gas - Acct.547)$86.6 $ 104.8 $33.59
STAFF COMMENTS SEPTEMBER I5,2014
customers by economically dispatching resources when the Company had additional capacity
and market prices were favorable. Based on its analysis, Staff believes that the Company's
actual net power costs were reasonably incurred.
E. Other Surcharge Adjustments
The Company's PCA surcharge calculation includes two adjustments that are not
normally included in the PCA defenal and rate calculation.
First, the Company adjusts the PCA surcharge to correct an error in how the Company
allocates AECO natural gas supply volumes between its power supply operations and its natural
gas operations. The error occurred from November 2011 through September 2013. Correcting
the error shifts costs from the Company's Idaho natural gas operations to its Idaho electric
operations. This cost reallocation impacts the Idaho PGA for the natural gas operations and the
PCA for Idaho electric operations. Staff has reviewed the Company's journal entries and
supporting documentation and has verified the calculation of the additional Natural Gas
Transport Costs of $505,265. Staff agrees with this adjustment and finds that the PCA surcharge
is the proper place to reflect this increased cost to customers.
Second, the Company adjusts the PCA surcharge to include a $713,000 credit for the
2013 earning test as proposed in Case No. AVU-E-14-05 (Application to Initiate Discussions
About Extending Existing Rate Plan). In AVU-E-14-05, the proposed stipulation credits
$713,000 in electric revenue sharing money to customers through the PCA. A final order has not
yet been issued in that case, but all parties to the case have signed the stipulation. Staff has
audited the revenue sharing calculations. General Ledger numbers have been traced and
verified. Based on the audit, Staff believes the $713,000 amount is the proper portion of the
electric revenue sharing dollars to be applied in this PCA to benefit customers.
F. Proposed PCA Rate Adjustments
The PCA rate is calculated by dividing the PCA surcharge amount by the total number of
kilowatt-hours in the Company's latest revenue forecast for the twelve month period from
October 1,2014 through September 30, 2015. The PCA rate is then applied to each rate class
based on the number of kilowatt-hours forecasted for each rate class on an even cents per
kilowatt-hour basis.
STAFF COMMENTS SEPTEMBER 15,2014
The surcharge amount consists of revenue and expenses booked during the deferral
period (July 1, 2013 - June 30, 2014) and expected to be booked in the future (July 1, 2014
through November 30,2014). The surcharge amount also includes a Revenue Conversion
amount that grosses up the surcharge amount to capture Commission fees and uncollectibles as
they fluctuate with revenue. These calculations are as follows:
Booked Amounts (July 1, 2013 - June 30, 2014)
7,705,909 Deferral with Interest505,265 Gas Transport Adjustment(713,000) Rebate of 2013 Earning Test (AVU-E-14-05)(246,636) TransferUnamortizedBalance-20I2PCA(960.875) Unamortized Balance - 2013 PCA
6,290,663
Expected Booked Amounts (July 1, 2014 - September 30,2014)
19,000 Deferral interest (71111,4 -9130114)1,369,881 Amortizationincludinginterest38.000 Forecasted interest (l0llll4 - 9130115)
1,426,881
Revenue Conversion Amount
38,704 Commission fees and uncollectibles
Total
7,756,248
Rate Calculation
Surcharge Amount
7,756,248
3.075.297
0.00252
Surcharge Amount
Forecasted Sales
PCA Rate ($/kwh)
Staff s calculation of the PCA rate matches the rate proposed by the Company. Based on
its analysis, Staff believes that the Company's calculation is accurate and that it complies with
Commission's orders.
STAFF COMMENTS l0 SEPTEMBER 15,2014
CUSTOMER RELATIONS
The Company's press release and customer notice were included in the application. Staff
reviewed both documents and found two deficiencies where the press release and customer
notice do not include information required by the Commission's Rules of Procedure (IDAPA
31.01.01). First, the Company's notice and press release do not inform customers that they may
subscribe to the Commission's RSS feed to receive periodic updates via email about the case, as
required by Rule I25.01.d. Second, the customer notice does not inform customers that written
comments regarding the utility's application may be filed with the Commission, as required by
Rule 125.04.
Staff notes that the Rules of Procedure were revised effective February 14,2014. Staff
recommends that the Company review the updated Rules of Procedure and include all required
information in its customer notices and press releases in the future.
The Company included the customer notice with bills that it mailed to customers from
August l1 through September 10,2014. Customers have the opportunity to file comments on or
before September 15, 2014.
As of September 15, the Commission has received nine comments. All oppose the
proposed increase. Staff is concerned that customers are not generally aware of the distinction
between general rate cases and other types of cases that may affect rates, such as the PCA. Staff
notes that the filing of Avista's PCA case closely followed the announcement of a proposed
settlement in Case No. AVU-E-14-05, pursuant to which the Company agrees not to seek new
base rates before January 2016. The Company's PCA proposal, on the other hand, would
increase rates beginning October 1,2014. As a result, customers are understandably perplexed
by what they perceive as contradictory messages. Staff recommends that the Commission
recognize and address this confusion in its Order in this case.
llSTAFF COMMENTS SEPTEMBER I5,2014
STAFF RECOMMENDATION
Staff recommends that the Commission authorizethe total deferral amount of $7,705,909
(including interest) for recovery from customers.
Staff also recommends approval of Schedule 66 rates as filed in Exhibit A of the
Company's Application to be effective on October t,2014. Staff further recorrmends that the
Commission recognize and differentiate this PCA rate increase from base rate stability proposed
in AVU-E-14-05.
Respectfully submitted this lStU day of September 2014.
*-l l lk
Karl T. Klein
Deputy Attorney General
Technical Staff: Mike Louis
Kathy Stocklon
Daniel Klein
i :umisc/comments/avue I 4.6kkmlklsmedk comments
STAFF COMMENTS t2 SEPTEMBER 15,2014
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS I5TH DAY OF SEPTEMBER 2014,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NOS. AVU.E.I4-06, BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
KELLY NORWOOD
VP _ STATE & FED REG
AVISTA CORPORATION
PO BOX3727
SPOKANE W A 99220-3727
E-mail : kel [e-mail]
DEAN J MILLER
McDEVITT & MILLER LLP
PO BOX 2s64
BOISE ID 83702
E-mail: [e-mail]
PETER J RICHARDSON
GREGORY M ADAMS
RICHARDSON ADAMS PLLC
515 N 27TH STREET
BOISE ID 83702
E-mail : oeter@.richardsonadams.com
eres@.richardsonadam s.com
E.MAIL ONLY:
MARV LEWALLEN
CLEARWATER PAPER CORP
marv. lewal len@ clearwaterpaper. com
DAVID J MEYER
VP & CHIEF COUNSEL
AVISTA CORPORATION
PO BOX3727
SPOKANE W A 99220-3727
E-mail : [e-mail]
LARRY A CROWLEY
THE ENERGY STRATEGIES
INSTITUTE INC
5549 S CLIFFSEDGE AVE
BOISE ID 83716
E-mail: [e-mail]
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-mail : [e-mail]
CERTIFICATE OF SERVICE