20160915Comments.pdf

BRANDON KARPEN
DEPUTY ATTORNEY GENERAL
IDAHO PUBLIC UTILITIES COMMISSION
PO BOX 83720
BOISE, IDAHO 83720-0074
[phone]
IDAHO BAR NO. 7956
Street Address for Express Mail:
472 W. WASHINGTON
BOISE, IDAHO 83702-5918
Attorney for the Commission Staff
r_ • c <'.':-::;) I ~ p
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'r· ~ • t I '01 -l : ;'.! f ! i' ' .•. J , : ·, .. .-d0S,ON
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION OF )
A VISTA CORPORATION FOR AUTHORITY )
TO AMEND ITS ANNUAL POWER COST )
ADJUSTMENT (PCA) RA TES. )
) ___________________ )
CASE NO. AVU-E-16-05
COMMENTS OF THE
COMMISSION STAFF
COMES NOW the Staff of the Idaho Public Utilities Commission, by and through its
Attorney of record, Brandon Karpen, Deputy Attorney General, and in response to the Notice of
Application and Notice of Modified Procedure issued in Order No . 33571 on August 17, 2016, in
Case No. AVU-E-16-05, submits the following comments.
OVERVIEW OF COMPANY APPLICATION
The PCA is an annual cost adjustment mechanism that tracks changes in the Company's
hydroelectric generation, secondary prices, thermal fuel costs, and changes in power contract
revenue and expenses ensuring that customers do not pay more or less than the Company's
actual power supply expense (minus sharing). A vista's annual cost of providing electricity (i.e.,
its power supply costs) vary from year-to-year depending on changes in streamflow, thermal fuel
costs, the market price of power, and changes in power contract revenue and expenses. If the
cost of providing electricity is greater than that recovered through base rates, customers are
surcharged the difference. If the cost is less, customers receive a rebate. The annual PCA rate is
combined with the Company's "base rates" to produce a customer's overall energy rate.
STAFF COMMENTS SEPTEMBER 15, 2016
The Company reports that lower power supply costs than expected were due primarily to
favorable natural gas and wholesale power prices as well as lower net expense for Colstrip and
Kettle Falls generation. Offsetting some of the lower expenses was lower generation from
hydro, Palouse Wind, and Clearwater paper than those reflected in base rates.
The Company asks the Commission to approve a PCA rebate of 0.017¢ per kWh to be
effective October 1, 2016, in place of the 0.032¢ per kWh rebate approved by Order No. 33389.
Under the Company's proposal, the PCA rate for all customers, including residential customers,
would change from a rebate rate of 0.032¢ per kWh to a rebate rate of 0.017¢ per kWh-an
increase in the billing rate of 0.015¢ per kWh. Since PCA rate adjustments are spread on a
uniform cents per kWh basis, the resulting percentage increase varies by rate schedule. The
overall increase is 0.2%. The table below shows the percentage change on billed revenue for
each customer group.
Percent Change on Billed Revenue for Each Type of Service
Types of Service Schedule Numbers Percent Change on Billed Revenue
Residential 1 0.17%
General Service 11 , 12 0.15%
Large General Service 21 ,22 0.19%
Extra Large General Service 25 0.28%
Clearwater 25P 0.29%
Pumping Service 31 ,32 0.15%
Street and Area Lights 41-49 0.06%
Total 0.19%
STAFF REVIEW
Staff has thoroughly examined the Company's PCA Application by reviewing: (1) actual
and authorized expenses making up the deferral; (2) the calculation method of the deferral; (3)
the prudency of actual NPSE incurred during the deferral period ; ( 4) the calculation of balancing
accounts and interest used to determine the final PCA rate; and (5) the calculation of the PCA
rate. The results of Staffs review are summarized below.
Audit of Actual and Authorized Amounts
Staff conducted an onsite audit during the week of August 22, 2016. Staff reviewed and
audited the deferred balance amounts included in the current filing. Additionally, Staff reviewed
STAFF COMMENTS 2 SEPTEMBER 15, 2016
and audited the amounts from the prior PCA deferral that is currently being amortized, and finds
the amortization of the prior year's PCA deferral to be correct.
Staffs review of the deferral balance covered expenses incurred for the period of July
2015 through June 2016. 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 54 7), and the Sales for Resale account (FERC 44 7). Based on its
review of these transactions, Staff concludes that the various power cost transactions are
reasonable and were prudently incurred at the time they were made. Staff confirmed that all
transactions comply with A vista Utilities Energy Resources Risk Policy. Staff also verified that
A vista's booked amounts and other calculations have been correctly reflected.
Staff checked authorized amounts used to calculate the deferral and confirmed that they
were the same used to determine base rates that were authorized during the deferral period. Base
rates that were in effect during the deferral period were authorized in Case Nos. AVU-E-12-08
for July 1, 2015 through December 31 , 2015, and A VU-E-15-05 for January 1, 2016 through
June 30, 2016.
Staff recommends in future PCA filings that the Company separate authorized and actual
net power costs (NPC) in the workpapers detailing the calculation of the deferral instead of only
providing the actual less authorized difference . This will facilitate a more efficient Staff review.
Staff has provided an example in Attachment A to these comments.
Calculation of the Deferral
The deferral captures the difference between actual power supply expense and the
revenue that recovers power supply expense through base rates for the twelve months ending
June 30, 2016. It is composed of two components: (1) the difference between actual power
supply expense and the authorized power supply expense; and (2) the load change adjustment
(LCA). The total deferral including interest of $5,054 for the period from July 1, 2015 through
June 30, 2016, is $478,103 and is a rebate to customers. Of this amount (minus interest),
$1 ,232,245 is a result of the LCA, which is a surcharge due to the Company, and the remaining
STAFF COMMENTS 3 SEPTEMBER 15, 2016
is due to the actual versus authorized NPC difference of $1,676,422 which is a credit to
customers. 1
Staff examined each account and item that contributes to the deferral, and also reviewed
the method used in the Company's calculations. Staff believes that the $478,103 deferral
balance is accurate and the method used to derive it complies with past Commission orders. The
amount represents the over-recovery of actual power supply costs through base rates during the
deferral period and is a refund to customers.
The table below shows the accounts and items contributing to the deferral. Positive
values represent a cost to customers, while negative values represent a benefit to customers.
Deferral Activity
Number Accounts and Items Amount
1 FERC Account 555 -Purchased Power with Palouse $20,316,973
2 FERC Account 447 -Sale for Resale (17,957,124)
3 FERC Account 501-Thermal Fuel (1,318,531)
4 FERC Account 54 7 -CT Fuel 170,598
5 Net Transmission Revenue and Expense 3,312
6 FERC Account 557 -Resource Optimization and REC Revenue (4,159,091)
7 Idaho Load Change Adjustment 1,232,245
8 All Clearwater Revenues and Expenses 1,267,440
Net Power Cost Increase (Decrease) $ (444,178)
9 REC Revenue Credit for Washington RPS (38,978)
Net Deferral Balance $ (483,157)
10 Interest on the Deferral Balance 5 054
Deferral Balance with Interest $ (478 103)
1. FERC Account 555 -Purchased Power. Purchased Power costs reflect 90% of the
Idaho jurisdictional share of the difference in costs the Company incurred for power purchases in
the review period compared to authorized 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 is a cost to customers.
Palouse Wind expenses are included in the Purchased Power costs. In the past two
general rate cases, Palouse Wind has been removed from base rates and the expenses have been
required to flow through the PCA accounting mechanism. This expense treatment requires
1 There was an additional $38,978 credit due to Idaho customers for the use of renewable energy credits to meet
Washington's renewable portfolio standards.
STAFF COMMENTS 4 SEPTEMBER 15, 2016
A vista to share 10% of the Idaho jurisdictional costs of Palouse. Had the costs been included in
base rates, customers would have paid 100% of the costs associated with the Palouse Wind
Project.
2. FERC Account 447 -Sale for Resale. Sales for Resale are long-term and short-term
off-system sales. The amount represents 90% of the Idaho jurisdictional share of the difference
between the actual off-system sale revenues and off-system sale revenues included in base rates.
The negative amount in the Company's Application reflects an increase in sales for resale
revenues and is a benefit to customers.
3. FERC Account 501 -Thermal Fuel. Thermal Fuel, primarily coal, is used to produce
electricity. The amount represents 90% 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 actually incurred lower coal costs than are
currently included in base rates. The negative amount in the Application is a benefit to
customers.
4. FERC Account 547 -CT Fuel. Combustion Turbine (CT) Fuel is natural gas burned
in the Company's gas-fired generators. This amount represents 90% of the Idaho jurisdictional
share of the difference in costs the Company actually 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 here is an
additional cost to customers.
5. Net Transmission Revenue and Expense. In Case No. AVU-E-09-01 , the Commission
approved a multi-party settlement that authorized the Company to include transmission revenues
and expenses in the PCA. A vista incurs third party transmission costs when it purchases power
and has it wheeled or delivered to its service area by a third party. Avista also incurs third party
transmission costs when it sells power and pays a third party to deliver it. Third party
transmission revenues occur when A vista is the third party and is delivering power for others.
Including transmission revenues and expenses in the PCA tracks the variability of these items.
In the review period, the transmission revenues were less than what is included in base
rates by $76,211. Transmission expenses were less than what is included in base rates by
$72,899. Although the Company paid less for transmission expenses, the shortfall in
transmission revenues was larger than the difference in transmission expenses. The net
transmission revenue and expense of $3 ,312 is positive and is an additional cost to customers.
STAFF COMMENTS 5 SEPTEMBER 15, 2016
6. Resource Optimization. Resource Optimization results in a cost or a 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. Ninety percent of the Idaho jurisdictional share of the gain or loss on the
sale of the gas transactions resulting from optimizing Company resources is included in the PCA.
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
utilizes its power plants for economic dispatch, and should not be looked at independently from
the entire optimization of Company resources. Generally, when the Company purchases natural
gas, there is a corresponding sale of electricity and the spread between the cost to produce
electricity with the natural gas purchased and the price that the electricity is sold for (the spark
spread) is a benefit to customers.
Staff has verified that when the Company initially purchased gas, the cost of producing
electricity at A vista's natural gas plants (primarily the Coyote Springs and Lancaster facilities)
was less expensive than purchasing electricity on the open market to meet its native load. Staff
further verified that when the Company resold gas and purchased electricity to meet native load,
the resale and corresponding purchased electricity was the least expensive and most cost­
effective alternative.
Also included in the Resource Optimization amount is REC Revenue. On a system basis,
REC revenue was greater than the amounts authorized in base rates by $2,758,725, and Idaho's
portion, before sharing, is $966,031 . Staff recommends that the Company break out and show
separately the REC revenues and expenses as a line item outside of the Resource Optimization
line item in future PCA filings.
7. Idaho Load Change Adjustment. This adjustment captures the over or under recovery
of net power supply expense through base rates attributable to the difference between actual sales
and sales used to set base rates. The Load Change Adjustment Rate is $26.97/MWh for July
2015 through December 2015, and $22.68/MWh for January 2016 through June 2016. During
the review period, the Company experienced less sales than what was used to set base rates.
This results in a positive adjustment and a cost to customers. The amount is subject to 90%
sharing.
8. All 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
STAFF COMMENTS 6 SEPTEMBER 15, 2016
difference in Clearwater costs and revenues (for its Lewiston facility) relative to the normalized
Clearwater costs and revenues established in the Company's last general rate case. A contract
that expired prior to the beginning of the deferral period (July 2015 -June 2016) is included in
base rates, and it is these base rate costs that are still reflected in the PCA. This contract
included A vista's purchase of Clearwater self-generation at PURP A avoided cost rates.
Clearwater is currently a Schedule 25P customer; however, the revenues and expenses for the
expired Clearwater contract are still included in base rates through December 2015. New base
rates went into effect on January 1, 2016, and this line item will no longer be in the deferral
balance calculation going forward.
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 $1,267,440. This positive amount is an increased
cost to customers.
9. REC Revenue Credit for Washington Renewable Portfolio Standards. This credit is
based on the Idaho allocation of RECs that were retired to meet Washington Renewable Portfolio
Standards that would have otherwise been sold. The Company uses the average amount per REC
received for the sale of RECs to value the revenue credit for the RECs retired to meet the RPS
for Washington. This amount is a benefit to customers.
10. Interest during Deferral Period. The Company calculates interest on the deferral
balance using the methodology authorized in Order No. 29323. Staff reviewed the Company's
interest calculation and verified that the amounts included in the deferral balance are 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 2015 and 2016
is 1%. Although the overall deferral balance results in a credit to customers, due to timing,
interest during the review period is a cost to customers.
Net Power Cost Analysis
Staff performed an analysis of Avista's actual net power costs by comparing the unit cost
and amount of each supply source used during the deferral period with the amounts authorized in
base rates. This provides Staff with a determination of the Company's operational prudence by
examining the utilization of specific resources and long-term contracts that were in place to meet
STAFF COMMENTS 7 SEPTEMBER 15, 2016
customer load during the deferral period. Based on this analysis, Staff concludes that the
Company's actual power supply costs were reasonably incurred.
As illustrated by the table below, the reduction in the amount of hydro generation and
lower gas prices were the biggest factors contributing to differences between actual generation
and generation assumed in base rates. Lower precipitation and hydro generation availability
during the first half of the deferral period required the Company to dispatch the next lowest cost
resources to meet customer load. As a result, the Company increased the amount of Kettle Falls
and natural gas-fired generation. While generation at these plants was higher than expected, the
unit price for gas was lower than assumed in base rates. Given that market electric prices have
also declined, the Company was able to utilize significantly more market purchases to make up
for any shortfalls.
Resources aMW Percent Unit Cost Percent
Change Change Difference ($/MWh) Change
Hydro Generation -71.1 -13.1 % n/a n/a
Gas-fired 21.7 5.8% -2.65 -9.8%
Colstrip Generation -5.0 -2.8% -1.06 -7.2%
Kettle Falls 3.1 9.2% -7.45 -27%
Analysis of PCA Rates
As a result of its analysis, Staff believes the Company's proposed rates are accurate and
will fairly reimburse customers for over collection of actual net power cost (minus sharing)
embedded in base rates. Staff identified an error in the Company's rate impact calculation that
has no effect on the Company's proposed rates, but is highlighted for reporting purposes. Staff
also proposes simplifications in the calculation of interest that will add greater consistency,
transparency, and accuracy in the development of rates and PCA filings in the future. Each of
these items is discussed in more detail below.
The PCA rate is calculated by dividing the PCA revenue requirement by the forecasted
Idaho electricity usage during the next PCA billing period. The revenue requirement includes
the ending balances from the previous year's PCA, the current PCA deferrals and amortizations,
and a projected amortization for the time period after the Company submitted its Application but
prior to when rates become effective on October 1, 2016. Interest is calculated based on the
authorized customer deposit rate currently set at 1 % for actuals through the end of June 2016 and
STAFF COMMENTS 8 SEPTEMBER 15, 2016
estimated for future periods. All estimates and projections are replaced with actuals and trued up
in next year's PCA. The sum of these components is subject to a conversion rate adjusting for
Commission fees and uncollectibles to arrive at the PCA revenue requirement. Staff verified the
components of the revenue requirement which currently includes the amounts shown in the table
below.
The $519,030 decrease in revenue requirement results in a proposed 0.017¢ per kWh
PCA rebate rate to customers. Based on its analysis, Staff believes the Company calculated the
PCA rate correctly.
PCA Rate Calculation
2014-15 PCA Ending Balance
2015-16 Incremental Deferral
2015-16 Interest on Deferral
2015-16 Amortization
2015-16 Interest on Amortization
Subtotal
Jul-Sept 2016 Projected Amortization
Jul-Sept 2016 Projected Interest
Subtotal
Oct '15-Sept '17 Projected Interest
Grand Total
Conversion Factor
PCA Revenue Requirement
Forecast Sales during Collection Period (MWh)
Final PCA Rate ($/kwh)
Amount
(483,157)
5,054
(1,438,429)
(3,591)
(1,920, 123)
258,788
(1,909)
256,879
(2,560)
Total
1,149,773
(770,350)
(513,471)
(516,031)
0.994222
(519,030)
3,049,359
(0.00017)
Staff found an error in the Company's residential rate impact calculation. Using 918
kWhs for average customer usage, the Company calculated a 0.16% increase in the customer's
bill from $84.72 to $84.86 using the new PCA rate. Staff believes the Company used incorrect
residential base rates to calculate the average bill impact. Using current residential base rates,
Staff calculates the impact to be an increase from $83.80 to $83 .93 , also a 0.16% difference.
In reviewing the Company's amortization and deferral balancing accounts, Staff observed
that the Company is using two methods for calculating interest. The amortization accounts use
compound interest while the deferral account uses a simple interest method. Staff proposes that
the Company change the interest calculation in the deferral account to the same method used in
the amortization accounts starting with the July 2016 through June 2017 deferral period. Staff
believes this is beneficial for several reasons. First, the interest calculation method used in Idaho
STAFF COMMENTS 9 SEPTEMBER 15, 2016
Power's PCA and PacifiCorp's ECAM both use compound interest calculations exclusively in
their PCA balancing accounts. Implementing the change will provide consistency in the methods
by all three ofldaho's regulated electric utilities. This consistency will eliminate complexity for
the Company, Staff, and interveners as they evaluate the Company's accounting methods. A
single interest calculation method will also enable deferral and amortization amounts to be
combined into a single balance, allowing balancing account information to be included and
linked with the deferral calculations on a single page (see Attachment A) and simplify the rate
impact sheet the Company includes in its filing (see Attachment B). Finally, simplification
would be more transparent and could reduce potential errors. For example, it could potentially
eliminate the need for complicated interest adjustment entries when deferral amounts are posted
incorrectly.
If the change in interest calculation method were made for this year's PCA it would result
in less than a $200 difference supporting the recommended prospective change. The difference
could be larger with larger deferrals and customer discount rates in future PCAs. However, the
impact of the change is symmetrical depending on whether deferral balances are a credit or a
surcharge to customers.
CUSTOMER NOTICE AND PRESS RELEASE
The Company's press release and customer notice were included with its Application.
Staff reviewed the documents and determined that both comply with Rule 125 of the
Commission's Rules of Procedure, IDAPA 31.01.01.125.
The customer notice was included with bills mailed beginning August 3, 2016, and
ending September 1, 2016. Customers have the opportunity to file comments on or before
September 15, 2016.
CUSTOMER COMMENTS
As of September 15, 2016, no comments have been filed with the Commission.
STAFF RECOMMENDATIONS
Staff recommends that the Commission authorize the total deferral balance with interest
in the amount of $478,103 be refunded to ratepayers and approve Schedule 66 as filed in Exhibit
A of the Company's Application to go into effect on October 1, 2015.
STAFF COMMENTS 10 SEPTEMBER 15, 2016
Staff also recommends the following in future PCA filings:
1. The Company calculate interest on its monthly deferral balances using the same
compound interest method used to calculate its monthly amortization balances
beginning July 2016.
2. The Company show a breakdown of authorized and actual net power expenses instead
of just the actual versus authorized differences on its deferral calculation worksheet.
3. The Company include the calculation of the balancing accounts on the deferral
calculation worksheet.
4. The Company break out and show separate line items for actual and authorized REC
Revenue and Resource Optimization.
Respectfully submitted this
Technical Staff: Mike Louis
Daniel Klein
Mark Rogers
Kathy Stockton
Yao Yin
i :umisc/comments/avue 16.Sbkmlklsmrdkyy comments
STAFF COMMENTS
day of September 2016.
11 SEPTEMBER 15, 2016
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Vl
Avista Corporation PCA
July 2015 through June 2016
IPUC Deferral Analysis
1'1:~~f.~J;::-~1;._~~~e1M~
BASE RATE RECOVERY · LOAD CHANGE ADJUSTMENT
Idaho Actual Sales
Idaho Base Sales
Acutal -Base Sales
LCAR
Retail Revenue Adjustment -Under(+)/Over(-)
Base-to-Actual Percent Difference
NET POWER SUPPLY EXPENSE
Actual Ex .
555 Ptxchased Power
44 7 Sales for Resale
501 Thermal Fuel
547 CT Fuel
456 Transmission Revenue
Sale
Idaho Actual Net Expense
Clearwater Purchase
Clearwater Revenue
Clearwater Net Revenue
Authorized Net Ex nse
555 Purchased Power
555 Exclucde Palouse
44 7 Sales for Resale
501 Thermal Fuel
547 CT Fuel
456 Transmission Revenue
565 Transmission E nse
Authorized Net Expense
Idaho Alocation Factor
Idaho Authorized Net Expense
Clearwater Ptxchase
Clearwater Revenue
Clearwater Net Revenue
RENEWABLE ENERGY CREDIT REVENUE
Actual REC Revenue
Authorized REC Revenue
Actual -Authorized REC Revenue
Idaho Anocation Factor
Actual -Autohrized 1daho REC Revenue
COST RECOVERY SUBJECT TO SHARING
Actual -Authorized Net Expense (Idaho share)
Retail Revenue Adjustment
REC Revenue
Total Cost (Subject to Sharing)
Sharin Percenta
Total Cost Recovery Subject to Sharing
COST RECOVERY NOT SUBJECT TO SHARING
Clearwater Actual 4 Authorized Net Revenue
Total Cost Recovery Not Subject to Sharing
Total Power Cost Deferral wrth Ad"ustments
PCA Deferral Balance
Monthly Interest Rate
2014-15 PCA Ending Balances
Account 182386 June 2015 Ending Balance
Account 182387 June 2015 Endin Balance
2015-2016 Be . Balance
2015-2016 Incremental Deferral
RPS Compliance Adjustment
Amortization -Account 182386
Amortization -Account 182387
201 S-16 Ending Balance w/out Previous Month Interest
Interest
2015-16 Encf
Balance
DehrTal Balance
Jul-15 ~
MWh 259,631 267,056
MWh 242,247 2396-41
MWh 17,384 27,415
SIMWh 26.97 26.97 s (468,846) (739,383)
% 7.18% 11.44%
s 13,032,881 15,967,109 s (6,398,663) (8,995,718)
s 2,423,826 2,729,503 s 8,992,329 9,090,520
s (1,569,451) {1,433,184) s 1,678,«2 1,420,148 s (1,619,642) (1 ,969,918) s s 16,539,722 16,808,460 s 34.76% 34.76% s 5,749,207 5,842,621
s 0 0 s 0 0 s 0 0
s 5,648,618 7,939,502
s (6,033,100) (3,115,032) s 2,715,972 2,948,383 s 6,893,937 8,303,984 s (1,563,830) (1 ,439,516) s 1432251 1 480 124 s 9,093,848 16,117,445 s 34.76% 34.76% s l,161,022 5,602,424
s 1,665,897 1,673,537 s 1 875,474 1 884 078 s (209,577) (210,541)
s 0 0 s 0 0 s 0 0 s 34.76% 34.76% s 0 0
s 2,588,185 240,197 s (468,846) (739,383) s 0 0 s 2,119,339 (499,186)
" 90% 90% s 1,907,405 (449,267)
s 209 577 210 541 s 209,577 210,541
s 2116982 238 726
J!!!:1.§ ~ % 0.0833% 0.0833%
s 2,352,377 s 1202604 s 1 149 773 2 578 420 s 2,116,982 (238,726) s (38,978)
s (650,315) (659,235) s s 2,577,462 1,680,459 s 958 2148
$ 2 578 420 1682607
s s s s 0 0
I ~ Oct-15 I ~ Dec-15
211,4 .. 5 227,4-41 248,786 302,427
218 705 210 03-4 262 809 299 304
(7,260) 17,407 (14,023) 3,123
26.97 26.97 26.97 26.97
195,802 (469,467) 378,200 (84,227)
-3.32% 8.29% -5.34% 1.04%
11,448,945 11,753,765 14,963,692 16,760,121
(9,044,467) (10,680,728) (12,102,755) (12,494,264)
2,755,735 2,870,435 2,162,141 2,565,011
8,385,184 9,119,087 8,760,178 8,725,707
(1,480,437} (1,486,322) (1 ,395,586) (1,271,979)
1,417,125 1,443,829 1,406,502 1,462,172
(1 ,305,599) (714,081) (738,921) (390,259)
12,176,486 12,305,985 13,055,251 15,356,509
34.76% 34.76% 34.76% 34.76%
4,232,547 4,277,560 4,538,005 5,337,923
0 0 0 0
0 0 0 0
0 0 0 0
5,551,282 5,789,904 8,437,276 8,726,282
(4,649,875) (4,672,288) (5,573,841) (6,089,913)
2,925,528 3,051,784 2,909,636 3,002,771
8,561,441 9,099,171 9,713,701 10,900,577
(1 ,361,638) (1,498,286) (1 ,294,553) (1,278,524)
1 483 239 1 547 809 1 665 262 1635447
12,509,977 13,318,094 15,857,481 16,896,640
34.76% 34.76% 34.76% 34.76%
4,348,468 4,629,369 5,512,060 5,873,272
1,533,746 1,650,145 1,669,545 1,770,021
1 733 585 1 857 742 1 886 753 1 992 699
(199,839) (207,597) (217,208) (222,678)
0 0 0 0
0 0 0 0
0 0 0 0
34.76% 34.76% 34.76% 34.76%
0 0 0 0
(115,921) (351,809) (974,055) (535,349)
195,802 (469,467) 378,200 (84,227)
0 0 0 0
79,881 (821,276) (595,855) (619,576)
90% 90% 90% 90%
71,893 (739,148) (536,270) (557,618)
199 839 207 597 217 208 222 678
199,839 207,597 217,208 222,678
271 732 531 551 319 062 334 940
I ~ ~ I ~ ~ 0.0833% 0.0833% 0.0833% 0.0833%
1682607 1 366 648 666 170 419 580
271,732 (531,551) (319,062) (334,940)
(589,093) (170,065)
71 917 92 918
1,365,246 665,032 419,025 177,558
1 402 1138 555 350
1366S.S 666170 419 580 177 908
0 0 0 0
Ju4-1Sthru
Jan-16 Felr16 I Mar-16 ~ I May-16 Jun-16 J~16
287,600 247,551 242,490 21s.s•• 211,312 218,387 2,942,770
299 392 263 761 268 236 243 401 23-4 981 228 959 3 011 470
(11,792) (16,210) (25,746) (24,757) (23,669) (10,572) (68,700)
22.68 22.68 22.68 22.68 22.68 22.68
267,443 367,643 583,919 561,489 536,813 239,773 1,369,159
-3.94% -6.15% ·9.60% -10.17% -10.07% -'1.62% ·2.3%
13,649,153 13,452,207 13,762,455 11,810,638 10,399,522 10,545,763 157,546,251
(10,291,009) (10,637,878) (11,228,965) {9,817,050) (10,187,127) (9,220,527) {121,099,151)
2,753,922 2,300,883 2,083,055 2,266,480 662,548 1,809,764 27,383,303
9,063,065 6,579,384 5,500,996 3,000,674 3,859,806 3,886,295 84,963,225
(1,324,359) (1,112,794) (1.154,350) (1,298,500) (1,403,137) (1,567,883) (16,.497,982)
1,376,369 1,599,865 1,438,139 1,405,327 1,375,315 1,371,935 17,395,168
(1,971,230) (531,977) (926,365) (1,090,951) (1,719,080) (1,604,664) (14,582.687)
13,255,911 11,649,690 9,474,965 6,276,618 2,987,847 5,220,683 135,108,127
35.29% 35.29% 35.29% 35.29% 35.29% 35.29%
4,678,011 4,111,176 3,343,715 2,215,018 1,054,411 1,842,379 47,222,573
0 0 0 0 0 0 0
0 0 0 0 0 0 0
0 0 0 0 0 0 0
12,161,272 11,404,620 9,963,402 8,809,523 6,740,586 6,706,571 97,878,838
(821,526) (821,526) (821,526) (821,526) (821,526) (821 ,526)
(5,920,050) (4,854,311) (5,165,161) (6,554,606) (6,515,727) (4,972,680) (64,116,584)
2,775,328 2,612,937 2,619,359 2,265,736 2,033,267 1,704,765 31,565,466
8,051,247 7,027,863 6,561,435 4,369,417 2,748,054 2,201 ,271 84,432,098
(1,405,733) (1,166,326) (1 ,222,888) (1,264,428) (1,579,616) (1,659,588) (16,734,926)
1 452 738 1 372 806 1 509 572 1 336,193 1 369 317 1 346 174 17 630 932
16,293,276 15,576,063 13,444,193 8,140,309 3,974,355 4,504,987 145,726,668
3529% 35.29% 35.29% 3529% 35.29% 35.29%
5,749,897 5,496,793 4,744,456 2,872,715 1,402,550 1,589,810 50,982,836
9,962,891
11230331
0 0 0 0 0 0 (1,267,440)
0 0 0 0 0 0 0
236 220 220 980 236 220 228 283 236 220 228 600 1 386 523
236,220 220,980 236,220 228,283 236,220 228,600 1,386,523
35.29% 35.29% 35.29% 35.29% 35.29% 35.29%
83,362 77,984 83,362 80,561 83,362 80,673 489,304
(1,071,886) (1,385,617) (1,400,741) (657,697) (348,139) 252,569 (3,760,263)
267,443 367,643 583,919 561,489 536,813 239,773 1,369,159 _Lill.ill
83 362 77 964 83 362 80 561 83 362 80673 489 304
(721 ,081) (939,990) (733,460) (15,647) 272,036 573,015 (1,901,800)
90% 90% 90% 90% 90% 90%
(648,973) (845,991) (660,114) (14,082) 244,832 515,714 (1,711,619)
0 0 0 0 0 0 1 267 440
0 0 0 0 0 0 1,267,440
648 973 845 991 660 114 14 082 244 832 515 714 444179 (1676422\
~ Feb-16 I M!ill ~ I M!ill ~ Ml§ ~ I ~
0.0833% 0.0833% 0.0833% 0.0833% 0.0833% 0.0833% 0.0833% 0.0833% 0.0833%
2,352,377
1 202 604
177 908 374 583 1137 409 1 722 495 1 665 056 1 354 680
(648,973) (845,991) (660,114) (14,082) 244,832 (444,179)
(38,978)
(2,068,708)
96 334 83 477 75 975 72 956 66 931 630 279
(374,731) (1,137,097) (1,721,548) (1,663,621) (1,353,293) (769,195)
148 312 947 1 435 1 387 1 490
374 583 1137409 1722495 1 665 056 1354680 70323
739 207 660 433 582 780 582 780
79,390 78,203 69,339 258,048
616 550 485 1 651
0 0 0 0 0 39,20 660433 582 780 513 926 513 926
(OOOs of Dollars)
(OOOs of kWh)
Line Type of
No. Service
(a)
1 Residential
2 General Service
3 Large General Service
4 Extra Large General Service
5 Clearwater
6 Pumping Service
7 Street & Area Lights
AVISTA UTILITIES
IDAHO ELECTRIC
IMPACT OF PROJECTED SCHEDULE 66 PCA DECREASE
PROPOSED RATE TO BE EFFECTIVE OCTOBER 1. 2016
Schedule Forecasted
Number Kilowatt-hours
(b) (c)(1)
1 1,186,226
11, 12 366,159
21 ,22 651,417
25 368,180
25P 405,418
31 ,32 58,273
41-49 13,686
$
$
$
$
$
$
$
8 Total 3,049,359 $
9 Proposed rate
10 Present rate
11 Rate Change
Pro.12.osed rate
12 Total Amortization and Deferral Balance including interest thru 9/30/16
Forecasted Interest (Deferral and Amert )10/1/16-9/30/17
Total Balance with Forecasted Interest
13 Conversion factor
14 Revenue requirement
15 kWh's from above
Proposed rate:
$ (0.00017) $
$ (0.00032) $
$ 0.00015 $
$
$
$
$
$
(1) Source: Calendar Load forecast for the twelve month period October 1, 2016 -September 30, 2017
ocnn:i> ~ S""' ;:I: ~~~~ ---n z ::r a: 0 0 3 3 . (1)
;3 > ;:;.
(1) < t:O ;:;. s=:
en tTl
' °' b Ul
(518)
(979)
461
(513.926000)
(2.569630)
(516.495630)
0.994222
(516.912722)
3,049,359
(0.000170)
Total Billed Percent
Revenue Proposed change
at Present Sch.66 on Billed
Rates Change Revenue
(d) (e) (f)
106,676 $ 178 0.17%
36,545 $ 55 0.15%
52,697 $ 98 0.19%
19,487 $ 55 0.28%
21 ,280 $ 61 0.29%
5,817 $ 9 0.15%
3,592 $ 2 0.06%
246,094 $ 458 0.19%
CERTIFICATE OF SERVICE
I HEREBY CERTIFY THAT I HAVE THIS 15TH DAY OF SEPTEMBER 2016,
SERVED THE FOREGOING COMMENTS OF THE COMMISSION STAFF, IN
CASE NO. AVU-E-16-05 , BY MAILING A COPY THEREOF, POSTAGE PREPAID,
TO THE FOLLOWING:
KELLY NORWOOD
VP-STATE & FED REG
AVISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220-3727
E-mail: [e-mail]
PETER J RICHARDSON
GREGORY MADAMS
RICHARDSON ADAMS PLLC
PO BOX 7218
BOISE ID 83702
E-mail: [e-mail]
[e-mail]
DAVID J MEYER
VP & CHIEF COUNSEL
AVISTA CORPORATION
PO BOX 3727
SPOKANE WA 99220-3727
E-mail: david.meyer(a),avistacorp.com
DR DON READING
6070 HILL ROAD
BOISE ID 83703
E-mail: [e-mail]
CERTIFICATE OF SERVICE