HomeMy WebLinkAbout20160526Johnson Exhibit 6.pdf
DAVID J. MEYER
VICE PRESIDENT AND CHIEF COUNSEL FOR
REGULATORY & GOVERNMENTAL AFFAIRS
AVISTA CORPORATION
P.O. BOX 3727
1411 EAST MISSION AVENUE
SPOKANE, WASHINGTON 99220-3727
TELEPHONE: (509) 495-4316
FACSIMILE: (509) 495-8851
DAVID.MEYER@AVISTACORP.COM
BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION
IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-16-03
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC SERVICE ) EXHIBIT NO. 6
TO ELECTRIC CUSTOMERS IN THE )
STATE OF IDAHO ) WILLIAM G. JOHNSON
)
FOR AVISTA CORPORATION
(ELECTRIC)
(Oc) OreSgb;[:sn=Eifi-e€i96=iIJJ iti Ecto 3
EI E.
EI H
ol
oEI N.
El ftolzl
o
Et Ig&
ol
Et ilEl sEI Eoolal
@5EI ui
=6=l N<t
Nto!t"
=t sil N
ooooNOOno_ o_ o. @.@tooONNONiONoJJe
@oooO@FO
o{ooN{FOoooN@,i;a
ootsooo@o@- N- O_ N-@O@rrOOoovsNri,j,ja
-AAo
@oooNOOOst N- o- o.oooo@oooF$SNrtJJa
o
@O-OOOFO$- o_ @_ N-9O@FNO@@o\t*Nc,i -- 'j @
a
to@oooio@_ta-@.ooooooNoo$oNriJJ@
@@N.Fl @
"ul N
NNOO@o$9N_ @- N_ N"
OOOro@N@o{oN
ot--'i@aao
NNNor*.cl .\t
=l N-l
INo_
-@ol N
=l
N
oo@ooo@oo- @- @. N-Oo$FONFOot@NFjJ'je
NOOON@{Ooo6@
dd@dNO00Fi$N
N'j;eo@@
No<r o-cl trEl i\
oriE6l d
EI NOIt!l
oNooNOO6o- o_ o_ o,NOOONO@Os+oN+;--e
@
NOOOOSrOo_ N_ *- o-OONNoNv@\ttoNo-rjJ@ lio6o
6p
ot6g
D0N
6
Eoc
oc6o,!l
oNIEIoo
EE
oI
o
E$l:N
oNtoooooN-@-n"@,>l!tos@oEl ti:3 & R EI R. E
:::: o *' -
=
EoO@OOFOtN_ O. N- O- O_ O ;N@ooN-,-_dreNO@NOOI F@-=o-o_-s.a610_EoNNOOFI OhoF-@O.gEOOES
fil I
=*EI Efil sxEI &Bo 6 ' Pl
=E€
0650tETEEI
tH;SEI*Eg
SEEI ;I pgl
oo@(oElEp3.3El R E 5 3el o@NN
.El iEBE
o@ooEI 8 P 5:tl @oFjo:t ooN9l NOOOSlJoido-1 F66@
NOFOosNohlN_$^N-\El tsNN@
^t66@O6lN_o-(o-qAINNONdoo6
6NON:l oNo@-61 o- o- o. cgl oNFokl o@No:clrooo
s"l bssB
ot@r@NNFot@@9l ,jd6iilA@o{51ts_o-o-q{l oN90-o60a
@t@904o6- O- @- C?!tro@=t 60NN5lo-o.F.qFNOO9666
@oN
@
ocfa
olrJL
TJJtr
NONOooNo@-o_F-qEl oONFXl 6FNO<-l o. N. r: a?@Nta@@o6
so@FF@OOo-i-o-qOl FNoNcl oNoNfl oo@o
"@Nqooa
-OOO@vo@\t- o. O- q!ooN6l !FNF
=l
F. o_ N- ':NrNt6@@O
NOON+@ooooooEl trsiR.gl o- t- 'i c!zloN@t
-6qO
N@OO-. + N O Oz1 @NSNql@{-rtN
/l NF@@Elos-o-qol oN@oql ?@69
@N@NoN$oaio.o.3.\6l <o@$f,l oNo{cl @@s(ool JNN+o@6a
3{NOo6NOo_o-o.\<NOtOl o@FN5l s- o- o. ulFl o6oooN@{?AO@a
9go8o*E;i.ti eEE*;ccs+th:odf23
DFNNoo$*DOott
cccc
ooooooo9oooo
F.8oo6{ (n
EEau
TE,o
E Ee
R I.Xa,I j
o-t
=
EEg] E EOETEoE=oobiz
Ei$H
Exhibit No. 6
Case No. AVU-E-16-03
W. Johnson, Avista
Schedule 2, Page 1 of 6
Avista Corp.
Brief Description of Power Supply Adjustments
Line No.
1 Modeled Short-term Market Purchases – Short-term purchases from the
AURORA Dispatch Simulation Model.
2 Actual ST Market Purchases – Expense is set to zero since no fixed-price
short-term transactions for 2017 are included in the pro forma.
3 Rocky Reach/Rock Island Purchase – The pro forma expense is based on an
anticipated renewal of a purchase of a portion of Rocky Reach and Rock
Island generation. The current contract ends 12-31-2020.
4 Wells – Avista Share – Wells’ costs are based on the Company's 3.34% share
of total cost at project costs.
5 Wells – Colville Tribe’s Share – The test-year expense is based on a
purchase of the Colville Indian Tribe’s portion of the Wells’ dam generation.
The contract ended 3-31-15 so the pro forma expense is zero.
6 Priest Rapids Project – Priest Rapids Project expense includes the expense
related to the purchased power from the Priest Rapids development and power
from the Wanapum development.
7 Douglas Settlement – Douglas Settlement is for power Avista purchases from
Douglas PUD per the 1989 Settlement Agreement.
8 Lancaster Capacity Payment – The Lancaster capacity payment includes a
capital payment and a fixed O&M payment.
9 Lancaster Variable O&M Payments – the Lancaster variable O&M payment
is based on the variable O&M rate in the Lancaster Power Purchase
Agreement multiplied time the MWh of Lancaster generation in the pro forma.
10 WNP-3 – Pro forma costs are based on the actual rate. The pro forma uses the
actual rate for the contract for contract year 2015-2016 escalated at inflation to
the pro forma period.
11 Deer Lake-IP&L – Pro forma expense is for power purchased from Inland
Power to serve Avista customers.
12 Small Power – Pro forma costs are based on 5-year average generation and an
average contract rate.
Exhibit No. 6
Case No. AVU-E-16-03
W. Johnson, Avista
Schedule 2, Page 2 of 6
13 Stimson – This purchase is from the cogeneration plant at Plummer, Idaho.
Pro forma costs are based on 5-year average generation and pro forma period
contract rates.
14 Spokane-Upriver – Pro forma expense is based on a purchase of the net of
pumping (at the plant) generation at the pro forma contract rate.
15 Spokane Waste-to-Energy – Pro forma expense is based on average
generation and the pro forma period contract rate.
16 Non-Monetary – Expense is normalized to $0 in the pro forma.
17 Ancillary Services – Pro forma expense is $0 because this is an intra-utility
expense (matching revenue in Account 447).
18 Palouse Wind – Pro forma expense is based on the expected generation and
the contract rate in the pro forma year, including the apprenticeship credit.
19 Total Account 555
20 Broker Commission Fees – Pro forma expense is associated with purchases
and sales of electricity and natural gas fuel.
21 WA EIA REC Purchases – Pro forma expense is $0 because this is a
Washington only expense.
22 REC Expense – REC expense is expenses associated with the Non-WA EIA
REC Sales revenue.
23 Spokane Energy Capacity Payment Adjustment – The pro forma is $0
because the PGE capacity sale ends 12-31-16.
24 Rathdrum Solar, Buck a Block – This is the value of the energy from the
Rathdrum Solar project for which Buck a Block pays the expense.
25 Natural Gas Fuel Purchases – This is the expense for natural gas purchased
but not consumed for generation. Pro forma expense is $0 because all gas
purchased is assumed to be used for generation, and included in Account 547.
26 Total Account 557
27 Kettle Falls Wood Fuel Cost – Pro forma fuel expense is based on the
generation of the Kettle Falls plant in the AURORA Model and the unit cost
of available fuel.
Exhibit No. 6
Case No. AVU-E-16-03
W. Johnson, Avista
Schedule 2, Page 3 of 6
28 Kettle Falls-Start-up Gas – Pro forma expense is for start-up gas at Kettle
Falls and is based on the test-year expense.
29 Colstrip Coal Cost – Pro forma fuel expense is based on the generation of the
Colstrip plant in the AURORA Model and the unit cost of fuel under the
contract.
30 Colstrip Oil – Pro forma expense is for start-up oil expense. Pro forma is
based on the test-year expense.
31 Total Account 501
32 Coyote Springs Gas – Pro forma expense is an output of the AURORA
Model based on the pro forma unit cost of fuel and the dispatch of the plant,
which determines the volume of fuel consumed.
33 CS2 Gas Transportation – This expense is for natural gas transportation for
the Coyote Springs 2 plant.
34 Lancaster Gas – Pro forma expense is an output of the AURORA Model
based on the pro forma unit cost of fuel and the dispatch of the plant, which
determines the volume of fuel consumed.
35 Lancaster Gas Transportation – This expense is for natural gas
transportation for the Lancaster plant.
36 Gas Transportation Optimization – This credit to expense is based on
optimizing the gas transportation contracts for Coyote Springs 2 and
Lancaster. In general, this involves trading the gas price spread between
AECO (Canada) and Malin.
37 Gas Transportation for BP, NE and KFCT – This expense is for
transportation of natural gas to serve Boulder Park, Northeast and Kettle Falls
Combustion Turbine gas-fired plants.
38 Rathdrum Gas – Pro forma expense is an output of the AURORA Model
based on the pro forma unit cost of fuel and the dispatch of the plant, which
determines the volume of fuel consumed.
39 Northeast CT Gas – Pro forma expense is an output of the AURORA Model
based on the pro forma unit cost of fuel and the dispatch of the plant which
determines the volume of fuel consumed.
40 Boulder Park Gas – Pro forma expense is an output of the AURORA Model
based on the pro forma unit cost of fuel and the dispatch of the plant which
determines the volume of fuel consumed.
Exhibit No. 6
Case No. AVU-E-16-03
W. Johnson, Avista
Schedule 2, Page 4 of 6
41 Kettle Falls CT Gas – Pro forma expense is an output of the AURORA
Model based on the pro forma unit cost of fuel and the dispatch of the plant,
which determines the volume of fuel consumed.
42 Total Account 547
43 WNP-3 Transmission – Pro forma WNP-3 wheeling is based on 32.22 MW
at the BPA tariff rate.
44 Wheeling for System Sales and Purchases – Pro forma expense is for short-
term transmission purchases.
45 PTP for Colstrip and Coyotes Springs 2 and Lancaster – Pro forma
expense is based on 568 MW of capacity at the BPA tariff rate.
46 BPA Townsend-Garrison Wheeling – This expense is for the transmission of
Colstrip power from the Townsend substation to the Garrison substation.
47 Avista on BPA Borderline – This expense is to serve Avista load off of BPA
transmission. Expense is based on Avista’s borderline loads priced at BPA’s
NT transmission rates plus ancillary services cost and use of facilities charges.
48 Kootenai for Worley – This expense is for Avista load served using
Kootenai’s facilities.
49 Sagle-Northern Lights – Expense is for transmission purchased from
Northern Lights Utility to serve Avista customers.
50 Northwestern for Colstrip – Northwestern for Colstrip wheeling is an
expense for the transmission of Colstrip energy above 196 MW from the
Garrison substation over Northwestern Energy’s transmission system to the
interconnection of Northwestern Energy and Avista.
51 PGE Firm Wheeling – PGE Firm wheeling reflects the cost of transmission
from the John Day substation to COB (Intertie South) purchased from Portland
General Electric.
52 Total Account 565
53 Headwater Benefits Expense – Pro forma expense is based on the expense
for contract year September 2015 through August 2016.
54 Total Expenses – Sum of Accounts 555, 557, 501, 547, 565, and 536.
Exhibit No. 6
Case No. AVU-E-16-03
W. Johnson, Avista
Schedule 2, Page 5 of 6
55 Modeled Short-Term Market Sales – Short-term market sales from the
AURORA Model simulation.
56 Actual ST Market Sales - Physical – Revenue is zero because no fixed-price
short-term transactions for 2017 are included in the pro forma.
57 PGE Capacity Sale – This pro forma revenue is $0 because the contract ends
12-31-16.
58 Nichols Pumping Sale – This is a sale of energy to other Colstrip Units 3 and
4 owners at the Mid-Columbia index price less $2.16/MWh. Pro forma
revenue is based on approximately 7 aMW at the market price (less
$2.16/MWh) as determined by the AURORA model.
59 Sovereign/Kaiser DES – This contract provides load control services to
Kaiser’s Trentwood plant. A new contract began 10-1-2015.
60 Pend Oreille DES & Spinning Reserves – This contract provides load
regulation and reserves for Pend Oreille PUD. A new contract began 10-1-
2015.
61 Energy America – Pro forma revenue includes a 50 aMW sale of energy at
the Mid C index plus $3/MWh.
62 COB Optimization – Pro forma revenue is based on the COB minus Mid C
price spread in the AURORA model.
63 Intercompany Generation – Pro forma revenue is $0 because it is intra-
utility revenue (matching expense in Account 555).
64 Total Account 447
65 Non WA EIA REC Sales – This is the expected REC revenue in the pro
forma period.
66 WA EIA REC Sales – Pro forma revenue is $0 because WA EIA compliant
RECs are not being sold in the pro forma period.
67 Gas Not Consumed Sales Revenue – This is the revenue for natural gas
purchased but not consumed for generation. Pro forma revenue is $0 because
all gas purchased is assumed to be used for generation, and included in
Account 547.
68 Total Account 456
Exhibit No. 6
Case No. AVU-E-16-03
W. Johnson, Avista
Schedule 2, Page 6 of 6
69 Upstream Storage Revenue – Pro forma revenue is based on the revenue for
contract year September 2015 through August 2016.
70 Total Revenue – Sum of Accounts 447, 456, 453 and 454.
71 Total Net Expense – Total expense minus total revenue.
Avista Corp.
Market Purchases and Sales, Plant Generation and Fuel Cost Summary
Idaho Pro Forma January 2017 - December 2017
744 672 743 720 744 720 744 744 720 744 721 744
Total Jan-17 Feb-17 Mar-17 Apr-17 May-17 Jun-17 Jul-17 Aug-17 Sep-17 Oct-17 Nov-17 Dec-17
Market Sales - Dollars -$35,219,577 -$3,365,428 -$2,866,543 -$3,111,337 -$4,464,391 -$3,314,947 -$1,831,846 -$2,127,505 -$1,713,007 -$2,114,053 -$1,697,124 -$3,765,771 -$4,847,625
Market Sales - MWh (1,601,018)-123,167 -113,931 -136,609 -240,313 -230,043 -147,828 -88,924 -58,763 -82,343 -72,359 -142,794 -163,943
Average Market Sales Price -$/ MWh $22.00 $27.32 $25.16 $22.78 $18.58 $14.41 $12.39 $23.93 $29.15 $25.67 $23.45 $26.37 $29.57
Market Purchases - Dollars $8,624,743 $416,370 $458,899 $762,467 $139,240 $120,365 $79,103 $940,190 $2,394,871 $1,259,248 $1,056,248 $518,167 $479,574
Market Purchases - MWh 390,494 21,363 24,889 41,540 11,904 7,716 6,476 46,255 98,354 50,009 46,409 19,103 16,476Average Market Purchase Price - $/MWh $22.09 $19.49 $18.44 $18.36 $11.70 $15.60 $20.33 $24.35 $25.18 $22.76 $27.13 $29.11
Net Market Purchases (Sales) MWh -1,210,524 -101,803 -89,043 -95,069 -228,409 -222,327 -141,352 -42,669 39,590 -32,334 -25,949 -123,692 -147,467
Net Market Purchases (Sales) aMW -138.2 -137 -133 -128 -317 -299 -196 -57 53 -45 -35 -172 -198
Average Sale and Purchase Price - $/MWh $22.02 $26.17 $23.96 $21.74 $18.25 $14.45 $12.38 $22.69 $26.15 $25.49 $23.18 $26.46 $29.53
Colstrip MWh 1,555,766 143,138 129,312 140,344 119,608 97,606 84,951 128,755 142,584 140,693 143,139 140,286 145,348
Colstrip Fuel Cost $/MWh $14.97 $14.40 $14.95 $14.53 $15.49 $16.96 $18.14 $15.08 $14.42 $14.48 $14.41 $14.50 $14.32Colstrip Fuel Cost $23,295,270 $2,061,843 $1,932,850 $2,039,502 $1,853,134 $1,655,021 $1,540,994 $1,941,201 $2,056,705 $2,037,203 $2,062,148 $2,033,841 $2,080,828
Kettle Falls MWh 267,889 29,023 24,593 22,692 17,649 12,371 707 19,871 27,998 27,265 24,847 29,002 31,870
Kettle Falls Fuel Cost $/MWh $18.95 $18.75 $18.88 $19.06 $19.76 $19.99 $19.06 $18.76 $18.82 $19.03 $18.68 $18.62
Kettle Falls Fuel Cost $5,075,794 $544,151 $464,292 $432,503 $348,818 $247,339 $13,892 $378,757 $525,136 $513,085 $472,718 $541,762 $593,341
Coyote Springs MWh 1,694,604 192,955 165,888 164,389 124,685 63,122 45,550 100,403 150,237 159,580 159,812 169,057 198,926
Coyote Springs Fuel Cost $/MWh $17.74 $18.63 $18.56 $18.24 $15.67 $15.81 $16.06 $16.81 $16.94 $16.93 $16.97 $18.64 $19.64
Coyote Springs Fuel Cost $30,059,005 $3,595,635 $3,079,227 $2,997,826 $1,953,516 $997,663 $731,468 $1,687,648 $2,545,650 $2,701,124 $2,712,223 $3,151,032 $3,905,994
Lancaster MWh 1,505,392 175,845 149,927 153,325 114,141 55,885 39,357 84,394 122,957 134,375 146,532 151,808 176,846
Lancaster Fuel Cost $/MWh $18.35 $19.12 $19.08 $18.78 $16.22 $16.52 $16.98 $17.57 $17.69 $17.58 $17.55 $19.20 $20.19Lancaster Fuel Cost $27,621,233 $3,361,985 $2,860,744 $2,879,427 $1,851,249 $923,239 $668,419 $1,482,598 $2,174,571 $2,362,625 $2,572,024 $2,913,962 $3,570,388
Boulder Park MWh 28,850 3,248 1,822 906 958 547 1,180 3,793 5,149 2,808 1,532 2,624 4,282
Boulder Park Fuel Cost $/MWh $23.64 $25.05 $25.03 $24.41 $20.96 $20.99 $21.44 $22.25 $22.50 $22.46 $22.63 $24.84 $26.36
Boulder Park Fuel Cost $682,039 $81,357 $45,615 $22,127 $20,089 $11,475 $25,300 $84,402 $115,857 $63,066 $34,682 $65,181 $112,887
Kettle Falls CT MWh 8,338 691 466 66 100 86 396 999 1,981 1,009 480 703 1,362Kettle Falls CT Fuel Cost $/MWh $22.85 $24.26 $24.02 $23.68 $20.32 $20.49 $20.77 $21.57 $21.82 $21.76 $21.92 $24.08 $25.58
Kettle Falls CT Fuel Cost $190,536 $16,759 $11,190 $1,563 $2,024 $1,763 $8,231 $21,546 $43,221 $21,949 $10,515 $16,941 $34,835
Rathdrum MWh 49,314 4,577 3,033 66 444 192 2,667 6,597 14,864 4,260 1,538 2,664 8,412
Rathdrum Fuel Cost $/MWh $30.94 $31.62 $31.45 $31.22 $27.67 $27.94 $28.13 $29.35 $29.66 $30.26 $31.41 $33.99 $34.35
Rathdrum Fuel Cost $1,525,966 $144,729 $95,384 $2,058 $12,293 $5,362 $75,004 $193,634 $440,813 $128,925 $48,292 $90,558 $288,911
Northeast MWh 2,460 223 93 0 0 0 230 400 1,071 183 46 51 163
Northeast Fuel Cost $/MWh $33.00 $35.86 $35.33 $30.79 $31.96 $32.26 $32.10 $32.45 $35.86 $38.54
Northeast Fuel Cost $81,199 $7,982 $3,299 $0 $0 $0 $7,085 $12,777 $34,566 $5,870 $1,485 $1,845 $6,290
Total Fuel Expense $88,531,041 $9,814,441 $8,492,602 $8,375,005 $6,041,124 $3,841,862 $3,070,392 $5,802,564 $7,936,519 $7,833,848 $7,914,087 $8,815,122 $10,593,475
Net Fuel and Purchase Expense $61,936,207
Exhibit No. 6
Case No. AVU-E-16-03
W. Johnson, Avista
Schedule 3, Page 1 of 1
Avista Corp
Pro forma January 2017 - December 2017
PCA Authorized Expense and Retail Sales
2015 Normalized Loads
PCA Authorized Power Supply Expense - System Numbers
Total January February March April May June July August September October November December
Account 555 - Purchased Power $109,404,394 $11,634,906 $10,578,647 $10,017,942 $8,959,852 $7,140,461 $6,531,514 $7,354,561 $8,761,369 $7,490,368 $7,797,297 $11,208,093 $11,929,383
Account 501 - Thermal Fuel $28,582,064 $2,623,577 $2,414,726 $2,489,588 $2,219,535 $1,919,943 $1,572,469 $2,337,541 $2,599,424 $2,567,872 $2,552,450 $2,593,186 $2,691,753
Account 547 - Natural Gas Fuel $63,615,977 $7,496,448 $6,383,459 $6,191,000 $4,127,172 $2,227,503 $1,803,506 $3,770,606 $5,642,678 $5,571,559 $5,667,221 $6,527,519 $8,207,306
Account 447 - Sale for Resale $48,524,705 $4,644,732 $3,967,296 $4,220,552 $5,351,293 $4,111,983 $2,577,097 $3,226,384 $3,017,817 $3,305,362 $2,836,739 $5,010,115 $6,255,336
Power Supply Expense $153,077,730 $17,110,199 $15,409,537 $14,477,978 $9,955,267 $7,175,922 $7,330,393 $10,236,325 $13,985,654 $12,324,438 $13,180,228 $15,318,683 $16,573,106
Transmission Expense $17,696,508 $1,494,602 $1,475,745 $1,463,502 $1,469,692 $1,454,063 $1,425,853 $1,474,893 $1,469,493 $1,450,695 $1,483,230 $1,490,253 $1,544,488
Transmission Revenue $17,163,284 $1,258,554 $1,342,410 $1,380,906 $1,325,245 $1,456,540 $1,614,866 $1,670,553 $1,520,946 $1,466,611 $1,406,355 $1,406,387 $1,313,910
Net REC Revenue $3,423,000 $290,850 $262,050 $290,850 $281,250 $290,850 $281,250 $290,850 $290,850 $281,250 $290,850 $281,250 $290,850
$157,033,954
PCA Idaho Retail Sales
Total January February March April May June July August September October November December
Total Retail Sales, MWh 3,011,312 287,473 258,568 271,002 228,286 228,974 224,777 245,462 255,918 214,673 238,519 248,276 309,383
Load Change Adjustment Rate $24.96 /MWh
Exhibit No. 6
Case No. AVU-E-16-03
W. Johnson, Avista
Schedule 4, Page 1 of 1