20121011Johnson DI.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: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-12-08
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) DIRECT TESTIMONY
AND NATURAL GAS CUSTOMERS IN THE ) OF
STATE OF IDAHO ) WILLIAM G. JOHNSON
)

FOR AVISTA CORPORATION

(ELECTRIC ONLY)

Johnson, Di 1
Avista Corporation
I. INTRODUCTION 1
Q. Please state your name, business address, and 2
present position with Avista Corporation. 3
A. My name is William G. Johnson. My business 4
address is 1411 East Mission Avenue, Spokane, Washington, 5
and I am employed by the Company as a Wholesale Marketing 6
Manager in the Energy Resources Department. 7
Q. What is your educational background? 8
A. I graduated from the University of Montana in 9
1981 with a Bachelor of Arts Degree in Political 10
Science/Economics. I obtained a Master of Arts Degree in 11
Economics from the University of Montana in 1985. 12
Q. How long have you been employed by the Company 13
and what are your duties as a Wholesale Marketing Manager? 14
A. I started working for Avista in April 1990 as a 15
Demand Side Resource Analyst. I joined the Energy 16
Resources Department as a Power Contracts Analyst in June 17
1996. My primary responsibilities involve power contract 18
origination and management, and power supply regulatory 19
issues. 20
Q. What is the scope of your testimony in this 21
proceeding? 22
A. My testimony will 1) identify and explain the 23
proposed normalizing and pro forma adjustments to the July 24
Johnson, Di 2
Avista Corporation
2011 through June 2012 test period power supply revenues 1
and expenses, and 2) describe the proposed level of expense 2
and load change adjustment rate for Power Cost Adjustment 3
(PCA) purposes, using the pro forma costs proposed by the 4
Company in this filing. 5
Q. Are you sponsoring any exhibits to be introduced 6
in this proceeding? 7
A. Yes. I am sponsoring Exhibit 6, including 8
Schedules 1 through 4, which were prepared under my 9
supervision and direction. Schedule 1 identifies the power 10
supply expense and revenue items that fall within the scope 11
of my testimony. A brief description of each adjustment is 12
provided in Schedule 2. Schedule 3 shows the pro forma 13
fuel costs for each thermal plant and short-term purchase 14
and sales by month. The proposed authorized PCA power 15
supply expense and revenue, transmission expense and 16
revenue, and retail sales are shown in Schedule 4. 17
Q. Are there other Company witnesses providing 18
testimony regarding issues you are addressing? 19
A. Yes. Company witness Mr. Kalich provides 20
detailed testimony on the AURORA model used by the Company 21
to develop short-term power purchase expense, fuel expense 22
and short-term power sales revenue included in my exhibits. 23
Johnson, Di 3
Avista Corporation
II. OVERVIEW OF PRO FORMA POWER SUPPLY ADJUSTMENT 1
Q. Please provide an overview of the pro forma power 2
supply adjustment. 3
A. The pro forma power supply adjustment involves 4
the determination of revenues and expenses based on the 5
generation and dispatch of Company resources and expected 6
wholesale market power prices as determined by the AURORA 7
model simulation for the pro forma period under normal 8
weather and hydro generation conditions. In addition, 9
adjustments are made to reflect contract changes between 10
the historical test period and the pro forma period. The 11
table below shows total net power supply expense during the 12
test period and the pro forma period. For information 13
purposes only, the power supply expense1 currently in base 14
retail rates2, which is based on a calendar 2012 pro forma 15
period, is also shown. 16

1 For the remainder of my testimony, for purposes of the power supply
adjustment I will refer to the net of power supply revenues and
expenses as power supply expense for ease of reference.
2 The last general rate case was resolved through a “black-box”
settlement. My figures represent an estimate of the change from the
last case, based on the Power Supply information presented in that
case.
Johnson, Di 4
Avista Corporation
1
The net effect of my adjustments to the test year 2
power supply expense is a decrease of $6,866,000 3
($186,026,000 - $179,160,000) on a system basis (excluding 4
Clearwater power purchase expense in test year). The 5
decrease in power supply expense compared to the authorized 6
level in current base rates is $13,555,000 (system) and 7
$4,711,718 (Idaho allocation). 8
Q. Why is the power supply expense for the pro forma 9
year lower than the level of power supply expense currently 10
in the last rate case? 11
A. The decrease in pro forma power supply expense 12
from the expense included in the last rate case is 13
primarily a result of lower natural gas and power prices. 14
The natural gas price included in the AURORA model has 15
decreased from an annual average of $4.62/dth to $3.44/dth. 16
Power Supply Expense
System
Power Supply Expense in Current Rates (2012 pro forma)$192,715,000
Actual July 2011 - June 2012 Power Supply Expense (excluding Clearwater)$186,026,000
Proposed 2013 Pro forma Power Supply Expense $179,160,000
Proposed 2013 Pro forma vs July 2011 - June 2012 Test Period -$6,866,000
Proposed 2013 Pro forma vs Current Rates -$13,555,000
Johnson, Di 5
Avista Corporation
The average modeled power purchase price has decreased from 1
$40.45/MWh to $28.33/MWh3. 2
Pro forma system load (July 2011 through June 2012 3
weather adjusted loads) is 3.2 average megawatts (aMW) 4
lower (before the Energy Efficiency Load Adjustment4) than 5
the system load included in the last rate case (2010 6
weather adjusted loads). 7
Other than the addition of the power purchase from the 8
Palouse Wind Project and the Spokane Waste to Energy plant, 9
which I will address later, the contracts and resources in 10
this pro forma are the same as those included in the last 11
rate case. 12
13
III. PRO FORMA POWER SUPPLY ADJUSTMENTS 14
Overview 15
Q. Please identify the specific power supply cost 16
items that are covered by your testimony and the total 17
adjustment being proposed. 18
A. Schedule 1 of Exhibit 6, identifies the power 19
supply expense and revenue items that fall within the scope 20

3 The natural gas price included in the AURORA model and the modeled
power purchase price does not include the actual natural gas and power
transactions that have been entered into for the 2013 pro forma period.
4 The Energy Efficiency Load Adjustment is described by Company witness
Ehrbar. The reduction in load was not included in the AURORA model in
this filing, but was calculated outside the model and is included as a
reduction in power supply expense for purposes of the Power Cost
Adjustment.
Johnson, Di 6
Avista Corporation
of my testimony. These revenue and expense items are 1
related to power purchases and sales, fuel expenses, 2
transmission expense, and other miscellaneous power supply 3
expenses and revenues. 4
Q. What is the basis for the adjustments to the test 5
period power supply revenues and expenses? 6
A. The purpose of the adjustments to the test period 7
is to normalize power supply expenses for normal weather 8
and normal hydroelectric generation and to reflect recent 9
forward natural gas prices and other known and measurable 10
changes for the pro forma period. 11
The AURORA Model, as explained by Mr. Kalich, 12
dispatches Company resources using the recent forward 13
natural gas prices and calculates the level of generation 14
from the Company’s thermal resources, fuel costs for 15
thermal resources, and the short-term purchases and sales 16
necessary to balance system requirements and resources. 17
Q. Are there any changes in how the pro forma in 18
this case was developed versus the authorized power supply 19
expense proposed in the last rate case? 20
A. No. The process to develop the pro forma net 21
power supply expense in this case is the same as the 22
process used to develop power supply expense in the last 23
rate case. 24
Johnson, Di 7
Avista Corporation
A brief description of each adjustment is provided in 1
Schedule 2. Detailed workpapers have been provided to the 2
Commission coincident to this filing to support each of the 3
pro forma revenues and expenses. The detailed workpapers 4
for each adjustment show the actual revenue or expense in 5
the test period, and the pro forma revenue or expense. 6
Long-Term Contracts 7
Q. How are long-term power contracts included in the 8
pro forma? 9
A. Long-term power contracts are included in the pro 10
forma by including the energy receipt or obligation 11
associated with the contract in the AURORA model and 12
including the cost or revenue in the pro forma net power 13
supply expense. 14
Q. Are there any new long-term power purchases or 15
sales in the pro forma that were not included in the last 16
rate case? 17
A. Yes. This pro forma includes the expenses and 18
generation related to the purchase from the Palouse Wind 19
Project, a 105 MW capacity (39 aMW energy) wind facility 20
located 30 miles south of Spokane. Additional information 21
regarding this purchase is contained in Mr. Lafferty’s 22
testimony. The pro forma also includes a purchase from the 23
Spokane Waste-to-Energy plant located on the west side of 24
Johnson, Di 8
Avista Corporation
Spokane. The plant produces approximately 15 aMW of 1
energy. 2
Q. Why did the Company enter into a power purchase 3
agreement with the City of Spokane’s Waste-to-Energy plant? 4
A. The output from the Waste-to-Energy plant had 5
been purchased by Puget Sound Energy for the past 20 years. 6
That contract with Puget expired December 31, 2011. As a 7
PURPA resource, Avista is required to purchase the output 8
if the generator so requests, which they did. The purchase 9
price is at the avoided cost rates in Avista’s 2011 10
Integrated Resource Plan. 11
Q. Are there any long-term power purchases or sales 12
that were included in the last rate case, but are not in 13
this pro forma? 14
A. No. 15
Short-Term Power Purchases and Sales 16
Q. How are short-term transactions included in the 17
pro forma? 18
A. After including the actual physical forward long-19
term transactions as resources and obligations in the 20
AURORA model, the balance of the short-term electric power 21
purchases and sales are an output of the AURORA model. The 22
model calculates both the volumes and price of short-term 23
purchases and sales that balance the system’s generation 24
Johnson, Di 9
Avista Corporation
and long-term purchases with retail load and other 1
obligations. The price of the short-term transactions 2
represents the price of spot market power as determined by 3
the AURORA model. 4
Q. Actual forward short-term transactions are 5
included in the pro forma? 6
A. No. The AURORA model calculates both the volumes 7
and price of short-term purchases and sales that balance 8
the system’s generation and long-term purchases with retail 9
load and other obligations. 10
Thermal Fuel Expense 11
Q. How are thermal fuel expenses determined in the 12
pro forma? 13
A. Thermal fuel expenses include Colstrip coal 14
costs, Kettle Falls wood-waste costs, and natural gas 15
expense for the Company’s gas-fired resources including 16
Coyote Springs 2, Lancaster, Rathdrum, Northeast, Boulder 17
Park, and the Kettle Falls combustion turbine. Unit coal 18
costs at Colstrip are based on the long-term coal supply 19
and transportation agreements. Unit wood fuel costs at 20
Kettle Falls are based on multiple shorter-term contracts 21
with fuel suppliers and inventory. Total fuel costs for 22
each plant are based on the unit fuel cost and the plant’s 23
level of generation as determined by the AURORA model. 24
Johnson, Di 10
Avista Corporation
Schedule 3 shows the pro forma fuel costs by month for 1
each plant. Mr. Kalich provides details and supporting 2
workpapers regarding the level of generation for the 3
Company’s thermal plants, and the fuel cost for thermal and 4
natural gas-fired plants. 5
Transmission Expense 6
Q. What changes in transmission expense are in the 7
pro forma compared to the expense in the last rate case? 8
A. The only change in transmission expense are some 9
increases in all BPA transmission expenses beginning 10
October, 1, 2013 based on BPA’s proposed rate increases. 11
Summary of Power Supply Expense 12
Q. Please summarize your proposed pro forma power 13
supply expense that is provided to witness Andrews. 14
A. The proposed pro forma power supply expense as 15
shown in Schedule is a $25,953,000 reduction in expense on 16
a system basis ($9,021,263 Idaho allocation) from the July 17
2011 through June 2012 actual test-year expense and a 18
$13,555,000 (system)/$4,711,718 (Idaho allocation) 19
reduction in expense from the power supply expense in the 20
last rate case. 21
PCA Related Revenues and Expenses, Retail Sales and 22
Proposed Load Change Adjustment Rate 23
Johnson, Di 11
Avista Corporation
Q. What is Avista’s proposed authorized power supply 1
expense and revenue for the PCA? 2
A. The proposed authorized level of annual system 3
power supply expense is $157,095,545. This is the sum of 4
Accounts 555 (Purchased Power), 501 (Thermal Fuel), 547 5
(Fuel), less Account 447 (Sale for Resale) less $2,806,911 6
for the Energy Efficiency Load Adjustment5. The proposed 7
level of Transmission Expense is $17,970,479. The proposed 8
level of Transmission Revenue is $14,192,399. 9
Q. What is the level of retail sales and the 10
proposed load change adjustment rate for the PCA? 11
A. The proposed authorized level of retail sales to 12
be used in the PCA is the July 2011 through June 2012 13
weather adjusted retail sales adjusted for the Energy 14
Efficiency Load Adjustment. The proposed load change 15
adjustment rate is $27.68/MWh, which is the energy 16
classified portion of the fixed and variable production and 17
transmission revenue requirement in this filing developed 18
by Company witness Ms. Knox. 19
The proposed authorized PCA power supply expense and 20
revenue, transmission expense and revenue, and retail sales 21
is shown in Schedule 4. 22

5 The reduction in power supply expense for the Energy Efficiency Load
Adjustment is explained by Company witness Ehrbar.
Johnson, Di 12
Avista Corporation
Q. Does that conclude your pre-filed direct 1
testimony? 2
A. Yes. 3

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: [phone]
FACSIMILE: [phone]
[e-mail]

BEFORE THE IDAHO PUBLIC UTILITIES COMMISSION

IN THE MATTER OF THE APPLICATION ) CASE NO. AVU-E-12-08
OF AVISTA CORPORATION FOR THE )
AUTHORITY TO INCREASE ITS RATES )
AND CHARGES FOR ELECTRIC AND )
NATURAL GAS SERVICE TO ELECTRIC ) EXHIBIT NO. 6
AND NATURAL GAS CUSTOMERS IN THE )
STATE OF IDAHO ) WILLIAM G. JOHNSON
)

FOR AVISTA CORPORATION

(ELECTRIC ONLY)

Avista Corp.
Power Supply Pro forma - Idaho Jurisdiction
System Numbers - Jul 2011 - Jun 2012 Actual and Jan 2013 - Dec 2013 Pro Form
July 2011 - June 2012 Weather Normalized Load
Line Jul 11 - Jun 12 Jan 13 - Dec 13
No.Actual Adjustment Pro forma
555 PURCHASED POWER
1 Modeled Short-Term Market Purchases $0 $12,450 $12,450
2 Actual ST Market Purchases 122,152 -122,152 0
3 Rocky Reach 875 -875 0
4 Rocky Reach/Rock Island Purchase 10,915 910 11,825
5 Wells - Avista Share 1,616 184 1,800
6 Wells - Colville Tribe's Share 4,287 -4,287 0
7 Priest Rapids Project 5,712 1,122 6,834
8 Grant Displacement 1,437 -1,437 0
9 Douglas Settlement 998 -204 794
10 Lancaster Capacity Payment 21,413 647 22,060
11 Lancaster Variable O&M Payments 2,382 663 3,045
12 Palouse Wind 0 19,217 19,217
13 WNP-3 15,663 -2,033 13,630
14 Deer Lake-IP&L 6 0 6
15 Small Power 1,295 -231 1,064
16 Stimson 1,865 169 2,034
17 Spokane-Upriver 2,213 201 2,414
18 Spokane Waste-to-Energy 2,918 3,367 6,285
19 Black Creek Index Purchase 118 -118 0
20 Non-Monetary 84 -84 0
21 Clearwater Paper Co-Gen Purchase (1) 0 0 0
22 Ancillary Services 628 -628 0
23 Stateline Wind Purchase 3,435 -187 3,248
24 Total Account 555 200,012 -93,306 106,706
557 OTHER EXPENSES
25 Broker Commission Fees 828 0 828
26 Non WA EIA REC Purchase 348 -174 174
27 Optional Renewable Power Expense Offset -141 141 0
28 Natural Gas Fuel Purchases 153,292 -153,292 0
29 Total Account 557 154,327 -153,325 1,002
501 THERMAL FUEL EXPENSE
30 Kettle Falls - Wood Fuel 9,014 1,041 10,055
31 Kettle Falls - Start-up Gas 6 0 6
32 Colstrip - Coal 17,625 2,940 20,565
33 Colstrip - Oil 291 0 291
34 Total Account 501 26,936 3,980 30,916
547 OTHER FUEL EXPENSE
35 Coyote Springs Gas 23,454 14,569 38,023
36 Coyote Springs 2 Gas Transportation 6,785 429 7,214
37 Lancaster Gas 26,826 8,428 35,254
38 Lancaster Gas Transportation 5,764 387 6,151
39 Gas Transportation Optimization 0 -3,501 -3,501
40 Gas Transportation for BP, NE and KFCT 20 0 20
41 Rathdrum Gas 260 2,249 2,509
42 Northeast CT Gas 20 28 48
43 Boulder Park Gas 252 183 435
44 Kettle Falls CT Gas 74 405 479
45 Total Account 547 63,455 23,176 86,631
565 TRANSMISSION OF ELECTRICITY BY OTHERS
46 WNP-3 789 15 804
47 Black Creek Wheeling 39 -39 0
Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 1, p. 1 of 2
Avista Corp.
Power Supply Pro forma - Idaho Jurisdiction
System Numbers - Jul 2011 - Jun 2012 Actual and Jan 2013 - Dec 2013 Pro Form
July 2011 - June 2012 Weather Normalized Load
Line Jul 11 - Jun 12 Jan 13 - Dec 13
No.Actual Adjustment Pro forma
48 Wheeling for System Sales & Purchases 197 0 197
49 BPA PTP for Colstrip, Coyote & Lancaster 12,826 260 13,086
50 BPA Townsend-Garrison Wheeling 1,424 84 1,508
51 Avista on BPA - Borderline 1,216 9 1,225
52 Kootenai for Worley 45 0 45
53 Sagle-Northern Lights 134 0 134
54 Northwestern for Colstrip 328 0 328
55 PGE Firm Wheeling 643 0 643
56 Total Account 565 17,641 329 17,970
536 WATER FOR POWER
57 Headwater Benefits Payments 1,034 -99 935
549 MISC OTHER GENERATION EXPENSE
58 Rathdrum Municipal Payment 160 0 160
59 TOTAL EXPENS 463,565 -219,245 244,320
447 SALES FOR RESALE
60 Modeled Short-Term Market Sales 0 38,401 38,401
61 Actual Short-Term Market Sales 109,163 -109,163 0
62 Peaker (PGE) Capacity Sale 1,751 0 1,751
63 Nichols Pumping Sale 1,060 438 1,498
64 Sovereign/Kaiser DES 80 0 80
65 Pend Oreille DES & Spinning 412 0 412
66 Northwestern Load Following 335 -335 0
67 NaturEner 222 -222 0
68 SMUD Sale - Energy and REC 20,291 1,919 22,210
69 Ancillary Services 628 -628 0
70 Total Account 447 133,942 -69,590 64,352
456 OTHER ELECTRIC REVENUE
71 Non WA EIA REC Sales 2,366 -1,988 378
72 Gas Not Consumed Sales Revenue 140,649 -140,649 0
73 Total Account 456 143,015 -142,637 378
453 SALES OF WATER AND WATER POWER
74 Upstream Storage Revenue 582 -152 430
75 TOTAL REVENU 277,539 -212,379 65,160
76 TOTAL NET EXPENS 186,026 -6,866 179,160
(1) Directly assigned to Idaho $19.087 million
Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 1, p. 2 of 2

Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 2, p. 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-Physical – Expense of the actual term physical
power transactions entered into for the pro forma period as of 01-20-12.

3 Rocky Reach - The pro forma cost for Rocky Reach is $0 because the contract
ends 10-31-11.

4 Rocky Reach/Rock Island Purchase – The pro forma expense is based on a
purchase of a portion of Rocky Reach and Rock Island generation beginning
July 1, 2011.

5 Wells – Avista Share - Wells’ costs are based on the Company's 3.34% share of
total cost at project costs.

6 Wells – Colville Tribe’s Share - The 2011 test-year included 4.5% of Well’s
output purchased from the Colville Indian Tribe.

7 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.

8 Grant Displacement – The 2011 test-year expense included a purchase from
Grant PUD that ended 9-30-11.

9 Douglas Settlement – Douglas Settlement is for power Avista purchases from
Douglas PUD per the 1989 Settlement Agreement.

10 Lancaster Capacity Payment – The Lancaster capacity payment includes a
capital payment and a fixed O&M payment.

11 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.

12 Palouse Wind – Pro forma expense is based on expected generation and the pro
forma period contract rate including the adder for apprenticeship credit.

Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 2, p. 2 of 6
13 WNP-3 - Pro forma costs are based on the midpoint. The pro forma uses the
actual price identified in the contract for contract year 2011 through 2012
escalated at the 5-year average escalation rate to the pro forma period.

14 Deer Lake-IP&L - Pro forma expense is for power purchased from Inland
Power to serve Avista customers.

15 Small Power – Pro forma costs are based on 5-year average generation and an
average contract rate.

16 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.

17 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.

18 Spokane Waste-to-Energy - Pro forma expense is based on a purchase of the
plant generation at the pro forma contract rate. This purchase began 1-1-12.

19 Black Creek Index Purchase - Pro forma expense is $0 because the contract
ended March 25, 2011, with the power received in October 2011.

20 Non-Monetary - Expense is normalized to $0 in the pro forma.

21 Clearwater Paper Co-Gen Purchase - Pro forma expense is $0 because
Potlatch purchase expense is directly assigned to the Idaho jurisdiction and is
not included in system power supply expense.

22 Ancillary Services – Pro forma expense is $0 because this is an intra-utility
expense (matching revenue in Account 447).

23 Stateline Wind Purchase – Pro forma expense based on 5-year average
generation and the pro forma period contract rate less $1/MWh for the
Renewable Energy Credit, which is assigned to the Buck-a-Block.

24 Total Account 555

25 Broker Commission Fees – Pro forma expense is associated with purchases
and sales of electricity and natural gas fuel.

26 Non WA EIA REC Purchases – Expense is for the purchase of California
certifiable renewable Energy Credits to support the SMUD Sale.

Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 2, p. 3 of 6
27 Optional Renewable Power Expense Offset – This test year credit was to
remove the REC cost of the Stateline Wind purchase that was assigned to the
Buck-a-Block program. The pro forma credit is $0 because the Stateline Wind
purchase expense already removes the REC expense.

28 Natural Gas Fuel Purchases – This is the expense for natural gas purchased for
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.

29 Total Account 557

30 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.

31 Kettle Falls-Start-up Gas – Pro forma expense is for start-up gas at Kettle Falls
and is based on the test-year expense.

32 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.

33 Colstrip Oil – Pro forma expense is for start-up oil expense. Pro forma is based
on the test-year expense.

34 Total Account 501

35 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.

36 CS2 Gas Transportation – This expense is for natural gas transportation for the
Coyote Springs 2 plant.

37 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.

38 Lancaster Gas Transportation – This expense is for natural gas transportation
for the Lancaster plant.

39 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.

Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 2, p. 4 of 6

40 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.

41 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.

42 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 (including
test firing), which determines the volume of fuel consumed.

43 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.

44 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.

45 Total Account 547

46 WNP-3 Transmission – Pro forma WNP-3 wheeling is based on 32.22 MW at a
rate of $2.04/kW/mo through 9-30-13 and $2.20/kW/mo 10-1-13 through 12-31-
13 based on BPA’s proposed rate increase.

47 Black Creek Wheeling – Pro forma expense is $0 because the contract ended
March 25, 2011.

48 Wheeling for System Sales and Purchases – Pro forma expense is for short-
term transmission purchases.

49 PTP for Colstrip and Coyotes Springs 2 and Lancaster– This wheeling is for
the transmission of 196 MW from Colstrip, 272 MW from Coyote Springs 2 and
250 MW from Lancaster. Pro forma expense is based on 718 MW of capacity at
a rate of $1.501/kW/mo. through 9-30-13 and $1.622/kW/mo 10-1-13 through
12-31-13 based on BPA’s proposed rate increase.

50 BPA Townsend-Garrison Wheeling – This expense is for the transmission of
Colstrip power from the Townsend substation to the Garrison substation.

51 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.

Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 2, p. 5 of 6
Pro from expense is based on test-year expense through 9-30-13 and is increased
by 2.89% for 10-1-13 through 12-31-13 based on BPA’s proposed rate increase.

52 Kootenai for Worley – This expense is for Avista load served using Kootenai’s
facilities.

53 Sagle-Northern Lights – Expense is for transmission purchased from Northern
Lights Utility to serve Avista customers.

54 Garrison Burke – Garrison Burke 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.

55 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.

56 Total Account 565

57 Headwater Benefits Expense – Pro forma expense is based on the expense for
contract year September 2011 through August 2012.

58 Rathdrum Municipal Payment – This includes a payment in Jan. 2011 of
$160,000 to the city of Rathdrum for mitigation related to the Rathdrum
generating facility.

59 Total Expenses – Sum of Accounts 555, 557, 501, 547, 565, 536, and 549.

60 Modeled Short-Term Market Sales - Short-term market sales from the
AURORA Model simulation.

61 Actual ST Market Sales - Physical – Revenue from the actual term
transactions entered into for the pro forma period as of 01-20-12.

62 Peaker (PGE) Capacity Sale – This pro forma revenue is based on 150 MW of
capacity at a price of $1/kW/mo less a contract servicing fee. This contract is
related to the sales of capacity to Portland General Electric, which was
monetized in 1998.

63 Nichols Pumping Sale – This is a sale of energy to other Colstrip Units 3 and 4
owners at the Mid-Columbia index price less $2.05/MWh. Pro forma revenue is
based on approximately 8 aMW through 10-31-13 at the market price (less
$2.05/MWh) as determined by the AURORA model.

Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 2, p. 6 of 6
64 Sovereign/Kaiser DES – This contract provides load control services to
Kaiser’s Trentwood plant. (Contract details are provided in a CONFIDENTIAL
workpaper).

65 Pend Oreille DES & Spinning Reserves – This contract provides load control
and spinning reserves for Pend Oreille PUD. (Contract details are provided in a
CONFIDENTIAL workpaper).

66 Northwestern Load Following – Pro forma revenue is $0 because there is no
contract for the pro forma period.

67 NaturEner – This contract provides load following capacity to a Montana wind
facility. Pro forma revenue is $0 because there is no contract for the pro forma
period.

68 SMUD Sale – Pro forma revenue is the sale of energy and associated renewable
energy credits.

69 Ancillary Services – Pro forma revenue is $0 because it is intra-utility revenue
(matching expense in Account 555).

70 Total Account 447

71 Non WA EIA REC Sales – Pro forma revenue is based on contracted REC
sales during the pro forma period.

72 Gas Not Consumed Sales Revenue - This is the revenue for natural gas
purchased for 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.

73 Total Account 456

74 Upstream Storage Revenue – Pro forma revenue is based on the revenue for
contract year September 2011 through August 2012.

75 Total Revenue – Sum of Accounts 447, 456, 453 and 454.

76 Total Net Expense – Total expense minus total revenue.

Avista Corp.
Market Purchases and Sales, Plant Generation and Fuel Cost Summary
Idaho Pro forma January 2013 - December 2013
744 672 743 720 744 720 744 744 720 744 721 744
Total Jan-13 Feb-13 Mar-13 Apr-13 May-13 Jun-13 Jul-13 Aug-13 Sep-13 Oct-13 Nov-13 Dec-13
Market Sales - Dollars -$38,400,506 -$2,501,590 -$2,378,831 -$2,818,487 -$3,736,394 -$3,309,704 -$1,701,010 -$4,482,036 -$1,289,603 -$2,967,290 -$3,319,771 -$4,659,989 -$5,235,801
Market Sales - MWh (1,374,609) -77,745 -73,627 -95,646 -138,204 -179,880 -159,594 -145,487 -40,746 -92,766 -104,660 -131,530 -134,724Average Market Sales Price -$/ MWh $27.94 $32.18 $32.31 $29.47 $27.04 $18.40 $10.66 $30.81 $31.65 $31.99 $31.72 $35.43 $38.86
Market Purchases - Dollars $12,449,764 $2,199,825 $1,612,815 $1,359,776 $511,810 $270,045 $371,442 $675,189 $2,986,828 $771,565 $670,315 $451,910 $568,245
Market Purchases - MWh 439,497 79,078 56,093 54,967 33,758 17,464 27,363 17,515 83,550 22,198 18,952 12,260 16,299Average Market Purchase Price - $/MWh $28.33 $27.82 $28.75 $24.74 $15.16 $15.46 $38.55 $35.75 $34.76 $35.37 $36.86 $34.86
Net Market Purchases (Sales) MWh -935,112 1,333 -17,534 -40,678 -104,446 -162,416 -132,231 -127,973 42,804 -70,568 -85,708 -119,270 -118,426Net Market Purchases (Sales) aMW -106.7 2 -26 -55 -145 -218 -184 -172 58 -98 -115 -165 -159
Average Sale and Purchase Price - $/MWh $28.03 $29.98 $30.77 $27.74 $24.70 $18.14 $11.09 $31.64 $34.41 $32.52 $32.28 $35.55 $38.43
Colstrip MWh 1,511,799 133,671 128,234 134,083 100,622 87,653 77,256 131,031 141,337 141,739 147,735 143,119 145,320
Colstrip Fuel Cost $/MWh $13.60 $13.56 $13.54 $13.61 $13.79 $13.83 $14.01 $13.68 $13.56 $13.50 $13.49 $13.49 $13.49Colstrip Fuel Cost $20,564,618 $1,812,553 $1,736,715 $1,825,240 $1,387,575 $1,212,631 $1,082,479 $1,792,781 $1,916,323 $1,913,921 $1,992,935 $1,930,445 $1,961,020
Kettle Falls MWh 333,613 31,741 29,278 31,305 21,208 16,653 10,072 28,429 32,921 32,458 33,594 32,522 33,433Kettle Falls Fuel Cost $/MWh $30.14 $30.12 $30.11 $30.16 $30.33 $30.34 $30.19 $30.10 $30.07 $30.07 $30.06 $30.07
Kettle Falls Fuel Cost $10,054,701 $956,027 $881,653 $944,048 $643,254 $505,242 $305,986 $858,326 $990,970 $975,952 $1,010,021 $977,750 $1,005,470
Coyote Springs MWh 1,538,453 143,469 134,119 132,442 77,518 50,844 34,312 127,341 154,918 161,724 170,561 171,537 179,669
Coyote Springs Fuel Cost $/MWh $24.72 $24.22 $24.22 $24.03 $23.47 $23.77 $24.27 $24.37 $24.44 $24.28 $24.47 $25.75 $27.00Coyote Springs Fuel Cost $38,023,143 $3,474,829 $3,248,722 $3,183,149 $1,818,986 $1,208,316 $832,649 $3,103,629 $3,786,146 $3,926,418 $4,172,972 $4,416,450 $4,850,877
Lancaster MWh 1,498,508 149,055 136,302 140,599 87,258 31,202 23,307 112,631 139,868 158,164 174,476 170,402 175,245
Lancaster Fuel Cost $/MWh $23.53 $22.73 $22.67 $22.68 $22.52 $22.84 $23.47 $23.60 $23.37 $23.05 $23.22 $24.56 $25.98
Lancaster Fuel Cost $35,253,634 $3,388,553 $3,089,494 $3,188,899 $1,965,061 $712,587 $547,122 $2,658,120 $3,268,848 $3,645,657 $4,050,861 $4,185,537 $4,552,896
Boulder Park MWh 11,807 2,553 2,137 1,451 1,037 531 47 226 507 434 149 1,205 1,530Boulder Park Fuel Cost $/MWh $36.81 $36.11 $36.25 $35.99 $35.15 $35.38 $35.71 $36.13 $36.33 $36.36 $36.70 $38.36 $40.34
Boulder Park Fuel Cost $434,561 $92,209 $77,468 $52,214 $36,440 $18,799 $1,673 $8,151 $18,412 $15,761 $5,476 $46,245 $61,712
Kettle Falls CT MWh 13,456 1,859 1,680 1,232 1,173 859 273 703 1,012 1,231 958 1,060 1,415
Kettle Falls CT Fuel Cost $/MWh $35.56 $35.01 $35.14 $34.90 $34.08 $34.30 $34.62 $35.03 $35.22 $35.25 $35.58 $37.19 $39.11Kettle Falls CT Fuel Cost $478,540 $65,076 $59,058 $43,002 $39,986 $29,479 $9,461 $24,611 $35,657 $43,402 $34,074 $39,417 $55,319
Rathdrum MWh 58,431 10,482 5,660 2,109 3,816 679 16 7,447 10,066 2,531 23 3,857 11,743Rathdrum Fuel Cost $/MWh $42.95 $41.53 $41.96 $41.92 $40.47 $41.78 $43.14 $41.75 $41.98 $42.15 $43.15 $44.39 $47.03
Rathdrum Fuel Cost $2,509,445 $435,352 $237,499 $88,418 $154,440 $28,381 $706 $310,927 $422,520 $106,690 $1,013 $171,209 $552,290
Northeast MWh 933 216 127 97 291 47 1 15 47 18 2 29 45
Northeast Fuel Cost $/MWh $51.26 $51.32 $51.51 $51.15 $49.95 $50.27 $50.75 $51.34 $51.62 $51.66 $52.15 $54.52 $57.32Northeast Fuel Cost $47,847 $11,061 $6,529 $4,968 $14,553 $2,370 $37 $753 $2,428 $914 $81 $1,572 $2,581
Total Fuel Expense $107,366,488 $10,235,660 $9,337,139 $9,329,939 $6,060,294 $3,717,804 $2,780,112 $8,757,299 $10,441,304 $10,628,715 $11,267,433 $11,768,625 $13,042,165
Net Fuel and Purchase Expense $81,415,746
Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 3, p. 1 of 1
Avista Corp
Pro forma January 2013 - December 2013
PCA Authorized Expense and Retail Sales (with Energy Efficiency Load Adjustment)
July 2011 - June 2012 Normalized Loads
PCA Authorized Power Supply Expense - System Numbers (1)
Total January February March April May June July August September October November December
Account 555 - Purchased Power $106,706,470 $12,526,478 $10,806,995 $10,336,714 $8,592,752 $6,927,512 $6,593,636 $6,791,045 $8,867,711 $6,752,418 $7,236,266 $10,357,318 $10,917,624
Account 501 - Thermal Fuel $30,916,732 $2,789,917 $2,632,215 $2,785,057 $2,031,330 $1,718,372 $1,405,767 $2,715,972 $2,948,383 $2,925,528 $3,051,784 $2,909,636 $3,002,771
Account 547 - Natural Gas Fuel $86,631,151 $8,264,229 $7,537,533 $7,376,233 $4,927,841 $2,851,219 $2,201,285 $6,893,937 $8,303,984 $8,561,441 $9,099,171 $9,713,701 $10,900,577
Account 447 - Sale for Resale $64,351,897 $5,243,329 $4,871,731 $5,375,103 $5,885,551 $5,398,583 $3,447,153 $6,470,154 $3,363,867 $5,136,150 $5,299,000 $6,549,513 $7,311,763
Energy Efficiency Load Adjustment -$2,806,911 -$273,886 -$250,672 -$242,982 -$212,229 -$209,628 -$200,167 -$234,185 -$231,449 -$211,558 -$201,508 -$254,873 -$283,773
Power Supply Expense $157,095,545 $18,063,408 $15,854,340 $14,879,918 $9,454,142 $5,888,892 $6,553,367 $9,696,616 $16,524,762 $12,891,679 $13,886,714 $16,176,270 $17,225,436
Transmission Expense $17,970,479 $1,495,284 $1,530,877 $1,480,538 $1,427,248 $1,371,518 $1,420,882 $1,432,251 $1,480,124 $1,483,239 $1,547,809 $1,665,262 $1,635,447
Transmission Revenue $14,192,399 $1,181,058 $975,106 $1,088,154 $1,016,354 $1,087,976 $1,266,618 $1,420,627 $1,296,313 $1,218,435 $1,355,084 $1,151,351 $1,135,323
PCA Authorized Idaho Retail Sales (2)
Total January February March April May June July August September October November December
Total Retail Sales (w/o Clearwater), M 2,920,316 288,551 259,938 251,710 220,893 215,129 211,357 242,246 239,640 218,704 210,033 262,811 299,304
Clearwater Paper Gen/Load 444,563 39,257 35,848 26,604 38,658 38,512 33,557 38,814 38,992 35,735 38,447 38,899 41,240
Load Change Adjustment Rate $27.87 /MWh
1) Multiply system numbers by 34.76% to determine Idaho share.
2) 2011 weather normalized Idaho retail sales. (with Energy Efficiency Load Adjustment)
Exhibit No. 6
Case No. AVU-E-12-08
W. Johnson, Avista
Schedule 4, p. 1 of 1