20160623AVU to Staff 1 Disk 2.pdf

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AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/01/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 001 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide copies of any and all data requests submitted to you by any party to this proceeding and your corresponding responses to those data requests. This is an ongoing request.

RESPONSE:
Avista has provided and will continue to provide copies of data requests, along with corresponding data
responses, from all parties to this proceeding as they are completed.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 002 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide or grant permission for use of all non-confidential Avista data responses to ICNU in WUTC Dockets UE-150204/UG-150205.

RESPONSE:
Please see ICNU_DR_002 Attachment A for all non-confidential Avista data responses to ICNU in Dockets
UE-150204/UG-150205. Due to the voluminous size the DR’s are being provided on a CD.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 003 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all confidential Avista data responses to ICNU in WUTC Dockets UE-150204/UG-150205. RESPONSE:

Please see Avista’s CONFIDENTIAL response to data request ICNU – 003C. Please note that Avista’s response to ICNU – 003C is Confidential per Protective Order in UTC Dockets UE-160228 and UG-
160229.

Please see ICNU_DR_003C Confidential Attachment A for all confidential Avista data responses to ICNU
in Dockets UE-150204/UG-150205. Due to the voluminous size the DR’s are being provided on a CD.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 004 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
For each of the past five rate years, on a Washington jurisdictional basis, please indicate whether
Avista earned above its authorized return on equity for electric operations. RESPONSE:
(1) 2013-2014 ROE – electric earnings: 2013-2014 authorized electric rates based on
Docket UE-120436; utilizing a 2011 historical test period, established 2-yr rate plan 2013-2014.
In 2013 and 2014 Avista’s normalized results were close to the Return on Equity (ROE) approved
by this Commission for the two-year rate plan established in Docket Nos. UE-120436 and UG-120437. The table below shows the ROE for each year, by service and on a consolidated basis.
2013 and 2014 Earned Return on Equity
Electric Natural Gas Total Utility
ROE ROE (Weighted) 2013 9.9% 7.2% 9.5% 2014 10.6% 6.4% 9.9%
Two-Year Rate Plan Wtd ROE 10.3% 6.9% 9.7%

The table above shows that Avista over-earned for its electric operations and under-earned for its natural gas operations. But for Avista’s Washington utility operations as a whole, the results were 9.5% for 2013 and 9.9% for 2014, as compared to the authorized ROE of 9.8%. Avista’s average

Page 2 of 2
ROE for the two-year period was 9.7% as compared to the authorized return of 9.8%. These results
provide an after-the-fact confirmation that the revenue increases granted based on recognition of
attrition provided earned returns very close to the authorized ROE of 9.8%. Without the recognition of attrition, Avista’s earned returns for 2013 and 2014 would have been substantially below its
authorized return.

The over earnings in 2014 was due, in part, to the impact of actual net pension and post-retirement
medical expenses in that year. For 2013, 2014, and 2015 net Pension and post-retirement medical expenses were $18.7 million, $14.1 million, and $18.7 million, respectively. This unexpected
decrease in 2014 was related to favorable returns on the fund balances in 2014, and changes in
interest rates and discount rates. Removing this one-year aberration in expense for 2014, which was
beyond the control of the Company, reduces the normalized ROE for Washington electric operations
from 10.6% to 10.2%. This 10.2% ROE is reasonably close to the 9.8% authorized level.
ADFIT also played a part in the over earnings in 2014, as the impact of bonus depreciation was not
recorded for 2014 until December 2014. Bonus Depreciation was not approved by the IRS until
December 2014, therefore, this reduction in ADFIT reducing rate base had not been factored into the
rates set for 2014 during the 2012 GRC Docket UE-120436. The impact of the 2014 ADFIT (lowering rate base) was reflected in the 2015 GRC for setting rates in 2016, as has the impact of
2014-2018 been included, impacting the 18 month rate-period 2017 through June 2018 (on an AMA
basis).
(2) 2015 ROR/ROE – electric earnings: 2015 authorized electric rates were based on
Docket UE-140188; utilizing a 2013 historical test period. The results of the filed 2015 electric CBR is 7.38% ROR / 9.50% ROE. The 2015 CB includes Adjustment 2.16 "CB Power Supply,” which normalizes power supply costs
to reflect the authorized level of net power supply costs for the twelve month period. The Energy
Recovery Mechanism (ERM), approved by the Commission, is designed to share all differences in
actual vs authorized net power supply costs within the ERM between customers and the Company based on the pre-determined deadband and sharing bands embedded within the ERM. The customer portion of the difference between actual vs authorized net power supply costs (higher or lower) is
deferred and set aside for future rebate or surcharge to customers. The Company portion of the
deadband and sharing bands (higher or lower) is absorbed by the Company. By normalizing power
supply costs to reflect the authorized level, the Commission Basis Report reflects Company results after removing the agreed-upon treatment of differences in actual vs authorized net power supply costs.

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Electric Natural Gas Total Utility Authorized
ROE ROE (Weighted)ROE
2011 7.50%6.50%7.40%10.20%
2012 8.70%5.20%8.10%10.20%
2013 9.90%7.20%9.50%9.80%
2014 (1)10.60%6.40%9.90%9.80%Two-Year Rate Plan
Wtd ROE 10.30%6.90%9.70%9.80%
2015 (2)9.40%7.00%9.00%9.8% (a)
(a) For 2015, approved rates were based on a "black box," which did not establish a capital
structure or authorized ROE.
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/12/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 004-REVISED TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

For each of the past five rate years, on a Washington jurisdictional basis, please indicate whether Avista earned above its authorized return on equity for electric operations.

RESPONSE:
REVISED: May 12, 2015: The table and response below is revised to reflect electric and natural gas Commission Basis Reports
(CBRs) results. Recently it came to Avista’s attention that its 12.2015 jurisdictional results of
operations (ROO) reports had an incorrect tax amount recorded in December 2015 results.
Correcting this error results in the following revised ROE for 2015.

(1) 2013-2014 ROE – electric earnings: 2013-2014 authorized electric rates based on Docket UE-120436; utilizing a 2011 historical test period, established 2-yr rate plan 2013-2014. In 2013 and 2014 Avista’s normalized results were close to the Return on Equity (ROE) approved
by this Commission for the two-year rate plan established in Docket Nos. UE-120436 and UG-
120437. The table below shows the ROE for each year, by service and on a consolidated basis.

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2013 and 2014 Earned Return on Equity
Electric Natural Gas Total Utility
ROE ROE (Weighted) 2013 9.9% 7.2% 9.5%
2014 10.6% 6.4% 9.9%
Two-Year Rate Plan Wtd ROE 10.3% 6.9% 9.7%

The table above shows that Avista over-earned for its electric operations and under-earned for its natural gas operations. But for Avista’s Washington utility operations as a whole, the results were
9.5% for 2013 and 9.9% for 2014, as compared to the authorized ROE of 9.8%. Avista’s average
ROE for the two-year period was 9.7% as compared to the authorized return of 9.8%. These results
provide an after-the-fact confirmation that the revenue increases granted based on recognition of
attrition provided earned returns very close to the authorized ROE of 9.8%. Without the recognition of attrition, Avista’s earned returns for 2013 and 2014 would have been substantially below its
authorized return.

The over earnings in 2014 was due, in part, to the impact of actual net pension and post-retirement
medical expenses in that year. For 2013, 2014, and 2015 net Pension and post-retirement medical expenses were $18.7 million, $14.1 million, and $18.7 million, respectively. This unexpected
decrease in 2014 was related to favorable returns on the fund balances in 2014, and changes in
interest rates and discount rates. Removing this one-year aberration in expense for 2014, which was
beyond the control of the Company, reduces the normalized ROE for Washington electric operations
from 10.6% to 10.2%. This 10.2% ROE is reasonably close to the 9.8% authorized level.
ADFIT also played a part in the over earnings in 2014, as the impact of bonus depreciation was not
recorded for 2014 until December 2014. Bonus Depreciation was not approved by the IRS until
December 2014, therefore, this reduction in ADFIT reducing rate base had not been factored into the
rates set for 2014 during the 2012 GRC Docket UE-120436. The impact of the 2014 ADFIT (lowering rate base) was reflected in the 2015 GRC for setting rates in 2016, as has the impact of
2014-2018 been included, impacting the 18 month rate-period 2017 through June 2018 (on an AMA
basis).
(2) 2015 ROR/ROE – electric earnings: 2015 authorized electric rates were based on
Docket UE-140188; utilizing a 2013 historical test period. The results of the revised filed 2015 electric CBR is 7.33% ROR / 9.40% ROE. The 2015 CB includes Adjustment 2.16 "CB Power Supply,” which normalizes power supply costs
to reflect the authorized level of net power supply costs for the twelve month period. The Energy
Recovery Mechanism (ERM), approved by the Commission, is designed to share all differences in
actual vs authorized net power supply costs within the ERM between customers and the Company based on the pre-determined deadband and sharing bands embedded within the ERM. The customer portion of the difference between actual vs authorized net power supply costs (higher or lower) is
deferred and set aside for future rebate or surcharge to customers. The Company portion of the
deadband and sharing bands (higher or lower) is absorbed by the Company. By normalizing power
supply costs to reflect the authorized level, the Commission Basis Report reflects Company results after removing the agreed-upon treatment of differences in actual vs authorized net power supply costs.

AVISTA CORPORATION
STATE OF WASHINGTON DOCKET NO. UE-011595
POWER COST DEFERRAL REPORT
MONTH OF FEBRUARY 2016

ERM REPORT MONTH OF FEBRUARY 2016
Page 1 of 36
ICNU_DR_005 Attachment A Page 1 of 36
Accounting Period Beginning Balance Monthly Activity Ending Balance
Beginning Balance ($11,535,183.18)
201601  $          (11,535,183.18) ($32,804.00) $                  (11,567,987.18)
201602  $          (11,567,987.18)$11,567,987.00   $                                    (0.18)
201603  $                           (0.18)$0.00  $                                    (0.18)
201604  $                           (0.18)$0.00  $                                    (0.18)
201605  $                           (0.18)$0.00  $                                    (0.18)
201606  $                           (0.18)$0.00  $                                    (0.18)
201607  $                           (0.18)$0.00  $                                    (0.18)
201608  $                           (0.18)$0.00  $                                    (0.18)
201609  $                           (0.18)$0.00  $                                    (0.18)
201610  $                           (0.18)$0.00  $                                    (0.18)
201611  $                           (0.18)$0.00  $                                    (0.18)
201612  $                           (0.18)$0.00  $                                    (0.18)
201602 ($0.18)
Current Month GL Account Amount Journal ID
Balance 1/31/2016  $                  (11,535,183)
Transfer to Account 196290 11,535,183$                    481 ‐ ERM
Interest  $                                    ‐   481 ‐ ERM
Balance 02/29/2016  $                                    (0)
YTD  Amount Journal ID
Balance 1/31/2016  $                  (11,535,183)
Deferral Year to Date  $                                    ‐   481 ‐ ERM
Transfer to Account 186290  $                    11,535,183 481 ‐ ERM
Interest 481 ‐ ERM
Balance 02/29/2016  $                                    (0)
Total Absorbed Deferred
First $4M at 100%(3,884,944)$                  (3,884,944)$                     ‐$                                         
$4M to $10M at 25% (rebate)‐$                               ‐$                                  ‐$                                         
$4M to $10M at 50% (surcharge)‐$                               ‐$                                  ‐$                                         
Over $10M at 10%‐$                               ‐$                                  ‐$                                         
(3,884,944)$                  (3,884,944)$                     ‐$                                         
STATE OF WASHINGTON
186280 ERM DEFERRAL (CURRENT YEAR)
ERM REPORT MONTH OF FEBRUARY 2016
Page 2 of 36
ICNU_DR_005 Attachment A Page 2 of 36
Accounting Period Beginning Balance Monthly Activity Ending Balance
Beginning Balance $0.00 
201601  $                                 ‐   $0.00 $                                  ‐  
201602  $                                 ‐   ($11,600,791.00) $          (11,600,791.00)
201603  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201604  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201605  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201606  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201607  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201608  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201609  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201610  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201611  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201612  $          (11,600,791.00)$0.00  $          (11,600,791.00)
201602 ($11,600,791.00)
Current Month Amount Journal ID
Balance 1/31/2016  $                                    ‐   
Transfer from 186280 (11,535,183.00)$             481 ‐ ERM
interest (65,608.00)$                     481 ‐ ERM
Balance 02/29/2016  $            (11,600,791.00)
STATE OF WASHINGTON
186290 ERM AMORTIZATION BALANCE (Pending Approval 2015)
ERM REPORT MONTH OF FEBRUARY 2016
Page 3 of 36
ICNU_DR_005 Attachment A Page 3 of 36
Accounting Period Beginning Balance Monthly Activity Ending Balance
Beginning Balance ($6,457,270.71)
201601  $                   (6,457,270.71)$579,345.00   $            (5,877,925.71)
201602  $                   (5,877,925.71)$27,371.00   $            (5,850,554.71)
201603  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201604  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201605  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201606  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201607  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201608  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201609  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201610  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201611  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201612  $                   (5,850,554.71)$0.00  $            (5,850,554.71)
201602 ($5,850,554.71)
Current Month Amount Journal ID
Balance 1/31/2016  $              (5,877,925.71)
Surcharge Amortization $43,974.00 481 ‐ ERM
Transfer From 186290 ‐$                                  481 ‐ ERM
Interest  $                    (16,603.00) 481 ‐ ERM
 $              (5,850,554.71)
STATE OF WASHINGTON
182350 RECOVERABLE DEFERRAL BALANCE (CURRENT YEAR ‐ 2016)
ERM REPORT MONTH OF FEBRUARY 2016
Page 4 of 36
ICNU_DR_005 Attachment A Page 4 of 36
DFIT Associated with ERM Deferrals
Account 283280.ED.WA
Account 186280.ED.WA balance (0.18)$                                             
Account 186290.ED.WA balance (11,600,791.00)$                          
Account 182350.ED.WA balance (5,850,554.71)$                            
   Total (17,451,345.89)$                          
Federal income tax rate ‐35%
Deferred FIT related to deferrals 6,107,971.06$                              
Rounding 0.88$                                              
Balance that should be in account ‐ January 31, 2015 6,107,971.94$                              
GL Check $6,107,971.94 
0.00$                                              
STATE OF WASHINGTON
232380 DFIT ASSOCIATED WITH ERM DEFERRALS
ERM REPORT MONTH OF FEBRUARY 2016
Page 5 of 36
ICNU_DR_005 Attachment A Page 5 of 36
FERC 
Account Accounting Period Beginning Balance Monthly Activity Ending Balance
186322 Beginning Balance $2,038,919.11 
ED.WA 201601  $                  2,038,919.11 $577,521.00 $              2,616,440.11 
201602  $                  2,616,440.11 $506,191.00 $              3,122,631.11 
201603  $                  3,122,631.11 $0.00 $              3,122,631.11 
201604  $                  3,122,631.11 $0.00 $              3,122,631.11 
201605  $                  3,122,631.11 $0.00 $              3,122,631.11 
201606  $                  3,122,631.11 $0.00 $              3,122,631.11 
201607  $                  3,122,631.11 $0.00 $              3,122,631.11 
201608  $                  3,122,631.11 $0.00 $              3,122,631.11 
201609  $                  3,122,631.11 $0.00 $              3,122,631.11 
201610  $                  3,122,631.11 $0.00 $              3,122,631.11 
201611  $                  3,122,631.11 $0.00 $              3,122,631.11 
201612  $                  3,122,631.11 $0.00 $              3,122,631.11 
GL YTD Check 201602 $3,122,631.11 
Current Month Amount Journal ID
Account 186322 Begin Balance  $                 2,616,440.11 
Amortization $491,135.00 475 ‐ WA REC Journal
Interest ‐ 6.340% $                       15,056.00 475 ‐ WA REC Journal
Ending Balance  $                 3,122,631.11 
STATE OF WASHINGTON
186322 REC AMORTIZATION
ERM REPORT MONTH OF FEBRUARY 2016
Page 6 of 36
ICNU_DR_005 Attachment A Page 6 of 36
FERC Account Accounting Period Beginning Balance Monthly Activity Ending Balance
186323 Beginning Balance ($2,022,351.13)
ED WA 201601  $            (2,022,351.13) ($10,685.00) $             (2,033,036.13)
201602  $            (2,033,036.13)($10,685.00) $             (2,043,721.13)
201603  $            (2,043,721.13)$0.00  $             (2,043,721.13)
201604  $            (2,043,721.13)$0.00  $             (2,043,721.13)
201605  $            (2,043,721.13)$0.00  $             (2,043,721.13)
201606  $            (2,043,721.13)$0.00  $             (2,043,721.13)
201607  $            (2,043,721.13)$0.00  $             (2,043,721.13)
201608  $            (2,043,721.13)$0.00  $             (2,043,721.13)
201609  $            (2,043,721.13)$0.00  $             (2,043,721.13)
201610  $            (2,043,721.13)$0.00  $             (2,043,721.13)
201611 $            (2,043,721.13)$0.00  $             (2,043,721.13)
201612 $            (2,043,721.13)$0.00  $             (2,043,721.13)
GL YTD Check 201602 ($2,043,721.13)
Current Month Amount Journal ID
Account 186323 Beginning Balance  $      (2,033,036.13)
Deferral 475 ‐ WA REC Journal
Interest  $           (10,685.00) 475 ‐ WA REC Journal
Ending Balance  $      (2,043,721.13)
STATE OF WASHINGTON
186323 REC DEFERRAL ‐ Prior year (2015)
ERM REPORT MONTH OF FEBRUARY 2016
Page 7 of 36
ICNU_DR_005 Attachment A Page 7 of 36
FERC Account Accounting Period Beginning Balance Monthly Activity Ending Balance
186323 Beginning Balance  $                                   ‐   
ED WA 201601  $                               ‐   ($194,757.00) $                (194,757.00)
201602  $             (194,757.00)($265,349.00) $                (460,106.00)
201603  $             (460,106.00)$0.00  $                (460,106.00)
201604  $             (460,106.00)$0.00  $                (460,106.00)
201605  $             (460,106.00)$0.00  $                (460,106.00)
201606  $             (460,106.00)$0.00  $                (460,106.00)
201607  $             (460,106.00)$0.00  $                (460,106.00)
201608  $             (460,106.00)$0.00  $                (460,106.00)
201609  $             (460,106.00)$0.00  $                (460,106.00)
201610  $             (460,106.00)$0.00  $                (460,106.00)
201611 $             (460,106.00)$0.00  $                (460,106.00)
201612 $             (460,106.00)$0.00  $                (460,106.00)
GL YTD Check 201602 ($460,106.00)
Current Month Amount Journal ID
Account 186323 Beginning Balance  $                (194,757.00)
Deferral ($263,626.00)475 ‐ WA REC Journal
Interest  $                     (1,723.00) 475 ‐ WA REC Journal
Ending Balance  $                (460,106.00)
STATE OF WASHINGTON
186324 REC DEFERRAL (2016)
ERM REPORT MONTH OF FEBRUARY 2016
Page 8 of 36
ICNU_DR_005 Attachment A Page 8 of 36
DFIT Associated with ERM Deferrals
Account 283305.ED.WA
Account 186322.ED.WA balance 3,122,631.11$         1,092,920.89$
Account 186323.ED.WA balance (2,043,721.13)$        (715,302.40)$
Account 186324.ED.WA balance (460,106.00)$           (161,037.10)$
   Total 618,803.98$            
Federal income tax rate ‐35%
Deferred FIT related to deferrals (216,581.39)$           
True up to Tax Return
Balance that should be in account (216,581.39)$          
GL Check 201602 ($369,536.49)
152,955.10$
STATE OF WASHINGTON
232305/283310 DFIT ASSOCIATED WITH REC DEFERRALS
No DFIT was recorded for January or February related to Account 
186324 REC Deferral becuase it is a new account
This will be corrected in March
ERM REPORT MONTH OF FEBRUARY 2016
Page 9 of 36
ICNU_DR_005 Attachment A Page 9 of 36
Attachment A

Avista Corporation
Monthly Power Cost Deferral Report

Month of February 2016

ERM Deferral Journal

ERM REPORT MONTH OF FEBRUARY 2016
Page 10 of 36
ICNU_DR_005 Attachment A Page 10 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 11 of 36
ICNU_DR_005 Attachment A Page 11 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 12 of 36
ICNU_DR_005 Attachment A Page 12 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 13 of 36
ICNU_DR_005 Attachment A Page 13 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 14 of 36
ICNU_DR_005 Attachment A Page 14 of 36
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5
ERM REPORT MONTH OF FEBRUARY 2016
Page 15 of 36
ICNU_DR_005 Attachment A Page 15 of 36
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3
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1
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0
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2
ERM REPORT MONTH OF FEBRUARY 2016
Page 16 of 36
ICNU_DR_005 Attachment A Page 16 of 36
Li
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ERM REPORT MONTH OF FEBRUARY 2016
Page 17 of 36
ICNU_DR_005 Attachment A Page 17 of 36
Li
n
e
No
.
De
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m
b
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55
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56

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75
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76
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x
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-

3
/
1
4
/
2
0
1
6
4
ERM REPORT MONTH OF FEBRUARY 2016
Page 18 of 36
ICNU_DR_005 Attachment A Page 18 of 36
Lin
e
No
.
De
a
l

N
u
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b
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r
TO
T
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55
5

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n
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19

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21

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3
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22

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3
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1
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5
ERM REPORT MONTH OF FEBRUARY 2016
Page 19 of 36
ICNU_DR_005 Attachment A Page 19 of 36
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3
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1
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0
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6
ERM REPORT MONTH OF FEBRUARY 2016
Page 20 of 36
ICNU_DR_005 Attachment A Page 20 of 36
Lin
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3
/
1
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0
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6
7
ERM REPORT MONTH OF FEBRUARY 2016
Page 21 of 36
ICNU_DR_005 Attachment A Page 21 of 36
Re
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ERM REPORT MONTH OF FEBRUARY 2016
Page 22 of 36
ICNU_DR_005 Attachment A Page 22 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 23 of 36
ICNU_DR_005 Attachment A Page 23 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 24 of 36
ICNU_DR_005 Attachment A Page 24 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 25 of 36
ICNU_DR_005 Attachment A Page 25 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 26 of 36
ICNU_DR_005 Attachment A Page 26 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 27 of 36
ICNU_DR_005 Attachment A Page 27 of 36
Attachment B

Avista Corporation

Monthly Power Cost Deferral Report
Month of February 2016

REC Revenues Deferral Journal

ERM REPORT MONTH OF FEBRUARY 2016
Page 28 of 36
ICNU_DR_005 Attachment A Page 28 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 29 of 36
ICNU_DR_005 Attachment A Page 29 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 30 of 36
ICNU_DR_005 Attachment A Page 30 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 31 of 36
ICNU_DR_005 Attachment A Page 31 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 32 of 36
ICNU_DR_005 Attachment A Page 32 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 33 of 36
ICNU_DR_005 Attachment A Page 33 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 34 of 36
ICNU_DR_005 Attachment A Page 34 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 35 of 36
ICNU_DR_005 Attachment A Page 35 of 36
ERM REPORT MONTH OF FEBRUARY 2016
Page 36 of 36
ICNU_DR_005 Attachment A Page 36 of 36

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/08/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State and Federal Regulation
REQUEST NO.: ICNU – 005 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the Company’s latest calculations and workpapers demonstrating the amount of deferred funds in its ERM balance.

RESPONSE:
Please see ICNU_DR_005 Attachment A for the Washington Monthly ERM filing for February 2016. As
shown in the attached report, as of 2/29/2016, the ERM balance is approximately $11.6 million.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 006 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all Board of Director meeting minutes from 2014 to the present. RESPONSE:

Please see Avista’s CONFIDENTIAL response to data request ICNU – 006C. Please note that Avista’s response to ICNU – 006C is Confidential per Protective Order in UTC Dockets UE-160228 and UG-
160229.

The Company has prepared a Virtual Data Room, as in previous cases, which houses the requested meeting
minutes. Please contact Paul Kimball via email – [e-mail] – to get the required login and password information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 007 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all Board of Director Finance Committee meeting minutes from 2014 to the present. RESPONSE:

Please see Avista’s CONFIDENTIAL response to data request ICNU – 007C. Please note that Avista’s response to ICNU – 007C is Confidential per Protective Order in UTC Dockets UE-160228 and UG-
160229.

The Company has prepared a Virtual Data Room, as in previous cases, which houses the requested meeting
minutes. Please contact Paul Kimball via email – [e-mail] – to get the required login and password information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/08/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 008 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide, from 2014 to the present: a) all minutes from Capital Planning Group (“CPG”) meetings; and b) a chart, graph, spreadsheet, or other form of presentation illustrating the amount
of capital spending approved by the CPG each month.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request ICNU – 008C. Please note that
Avista’s response to ICNU – 008C is Confidential per Protective Order in UTC Dockets UE-
160228 and UG-160229.

Please see ICNU_DR_008C Confidential Attachment A for the 2014 to present minutes. Minutes to the CPG meetings are sent out via email and each email has an excel spreadsheet embedded which
contains additional information. The excel spreadsheets are being provided in electronic format only.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 009 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

From 2005 to the present, please provide the annual amount of Schedule 91 Demand Side Management (“DSM”) funding collected from Schedule 25, including supporting documents.
RESPONSE:

The attachment labeled “ICNU_DR_009 Attachment A” includes the supporting calculations for
the Schedule 25 DSM revenue listed above.

Page 1 of 1
Year Incentive Elec
2005 304,663.00$
2006 139,523.00$
2007 915,154.00$
2008 301,081.50$
2009 1,304,744.78$
2010 736,949.88$
2011 418,132.00$
2012 832,731.13$
2013 336,161.00$
2014 40,244.00$
2015 798,300.00$
2016 YTD 47,138.00$
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 010 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

From 2005 to the present, please provide a quantification of benefits received by Schedule 25 customers from the Company’s DSM programs, including supporting documents.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 010C. Please note that
Attachment A in Avista’s response to ICNU – 010C is Confidential per Protective Order in UTC
Dockets UE-160228 and UG-160229.

Provided below are the energy efficiency incentives paid to Schedule 25 customers from 2005 through 2015, and 2016 year-to-date. Please note that these are the direct incentives paid to Schedule 25 customers
for qualifying electric efficiency measures. The Company has not otherwise performed an analysis showing
the benefits Schedule 25 customers have received from the deployment of the Company’s DSM resources
in terms of reduced power supply costs. In addition, the Company has not quantified the benefits provided
to Schedule 25 customers from their use of the Company’s DSM staff for efficiency consultations, energy audits, or analysis and reporting on potential efficiency measures.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/12/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Karen Schuh
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 011 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 13:12-14. When Mr. Morris states that the cost of utility asset installation was very low, years ago, as compared to the cost of replacement today, does this refer to real/relative cost or
nominal cost? Please provide supporting documentation for the statement.

RESPONSE:
The reference is to nominal costs that were incurred many years ago, i.e., the cost of materials and
labor to construct equipment at that time as compared to the nominal costs of assets today. The cost
to replace equipment that is 50+ years old may cost 10+ times the original cost of the replaced unit.
Please see Company Witness Ms. Schuh’s direct testimony which includes a chart/graph depicting the escalation of costs over time based on the Handy Whitman Index for specific categories of Utility
Plant at pages 12 and 13.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/08/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Mark Thies
REQUESTER: ICNU RESPONDER: Karen Schuh/Margie Stevens
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 012 TELEPHONE: [phone] EMAIL: [e-mail]
[e-mail]

REQUEST:
Refer to 16:13. Please identify the individuals comprising “senior management of Avista,”
including the positions/job titles of those individuals.

RESPONSE:
The excerpt from Company witness Mr. Morris referred to above is as follows:

“After taking into consideration a number of factors, senior
management of Avista establishes a proposed capital budget amount
for each year of the next five years, which is presented to the Finance Committee of the Board of Directors1.”

In this context, the Company is referring to “senior management of Avista” as the Company’s
senior officers that establish the capital investment target as follows: Scott Morris (Chairman,
President & CEO), Mark Thies (Sr. VP and CFO), and Dennis Vermillion (Sr. VP and President, Avista Utilities).

1 The Finance Committee is presented with a five-year plan, but approves the plan for only the next operating year.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 013 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 16:13-19. Does Avista document the establishment of proposed capital budgets by senior management, including the consideration of various factors listed? If yes, please provide all such
documentation and any associated studies.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 013C. Please note
that Attachment A in Avista’s response to ICNU – 013C is Confidential per Protective Order in
UTC Dockets UE-160228 and UG-160229.
The excerpt from Company witness Mr. Morris referred to above is as follows:

After taking into consideration a number of factors, senior management of
Avista establishes a proposed capital budget amount for each year of the next five
years, which is presented to the Finance Committee of the Board of Directors1. These factors include, but are not limited to, the total capital investment requests of
the departments submitted to the Capital Planning Group, the urgency of the
projects, the opportunities and risks associated with delaying the projects to a later
date, and the overall bill impact to customers associated with the annual capital
budgets ultimately approved.
As indicated in Avista’s response to ICNU_DR_012, senior management in this instance consists
of Scott Morris, Mark Thies, and Dennis Vermillion.

In his testimony following the referenced excerpt, Mr. Morris discusses the factors considered in relation to his earlier statement (the statement referenced in this request). Mr. Morris discusses the changes in average utility bills from 2009-2016 at Exhibit No. ___(SLM-1T), page 18, line 20
through page 23, line 21, including the impacts of reduced commodity costs. Mr. Morris discusses
the decreasing cost of debt for Avista from 2009 to 2016 in his testimony at page 23, line 22
through page 24, line 21. These specific items are included within a broader discussion (from page 7, line 14 through page 26, line 7) of the various factors that senior management considers in its management of the company, including capital investment.

1 The Finance Committee is presented with a five-year plan, but approves the plan for only the next operating year.

Page 2 of 2
Mr. Thies discusses the level of capital expenditures in his testimony at Exhibit No. ___(MTT-
1T), page 6, line 21 through page 11, line 11, particularly the factors driving the need for capital
investment.
As mentioned above in Mr. Morris’s testimony, the departmental capital investment requests are
provided to the Capital Planning Group. For 2016, the Capital Planning Group received $450
million in requested investment. Senior Management ultimately established a capital budget of
$375 million for 2016, and relied on the Capital Planning Group to review, prioritize and determine which projects could be deferred from 2016 and completed in later years. The capital
budget for the following years is based upon requested investment in those years, as well the need
to complete previously deferred projects.

The Company’s financial forecast, which is updated on a regular basis, reflects the effects of the planned capital investment, as well as expected revenues and expenses, for the forecasted five-year
period. The five-year financial forecast utilized in this proceeding is provided as INCU_DR_013C
Confidential Attachment A.

The testimony of Mr. Morris and Mr. Thies provides explanation of the factors that influenced senior management’s consideration of the proposed capital budget through the course of day-to-
day managerial discussions based upon their knowledge of and experience with Avista’s historical
and forecasted operations.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Karen Schuh
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 014 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 16:18-19. Please provide specific detail, documentation, and/or further explanation as to how senior management considers “the overall bill impact to customers associated with the annual capital
budgets.”

RESPONSE:
Please see the Company’s response to ICNU_DR_013.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/12/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie
REQUESTER: ICNU RESPONDER: Adrien M. McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 015 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

In recommending an increase to the authorized return on equity for the Company, did Mr. McKenzie consider the “principle of gradualism” (See, e.g., Docket UE-130043, Order 05, ¶¶ 63, 70)? If so, please
explain.

RESPONSE: As discussed in Mr. McKenzie’s direct testimony, the results of his analyses support a fair ROE for
Avista in the range of 9.93% to 10.93%, with the midpoint of this range being 10.43%. Meanwhile,
Avista is requesting an ROE of 9.9%. Considering that this value falls well below the 10.43% midpoint
indicated by Mr. McKenzie’s analyses and is essentially equivalent to the very bottom of Mr. McKenzie’s recommended ROE range, the 9.9% ROE requested by Avista is fully consistent with the concept of gradualism, as discussed by the WUTC in Docket UE-130043, Order 05, ¶¶ 63, 70.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/12/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Adrien M. McKenzie
REQUESTER: ICNU RESPONDER: Adrien M. McKenzie
TYPE: Data Request DEPT: Consultant
REQUEST NO.: ICNU – 016 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 37:8-40:14. Among other justifications for a flotation cost adjustment, Mr. McKenzie cites to and quotes from a Commission order in Docket UE-991606. Did Mr. McKenzie also consider the more
recent order concerning flotation costs in Docket UE-050684, Order 04 at ¶ 122? If yes, please explain
how Mr. McKenzie’s recommendation aligns with the Commission’s determination concerning flotation
costs in that more recent order.
RESPONSE:
Mr. McKenzie is aware of the fact that the WUTC determined not to allow a flotation cost adjustment for
PacifiCorp in Docket UE-050684, Order 04 at ¶ 122; however, the Commission explicitly distinguished its findings in that proceeding from its prior determination for Avista. See, Docket UE-050684, Order 04
at ¶ n. 172, noting that, “We allowed the addition of 25 basis points to Avista’s cost of equity to recover
flotation costs,” and that, “Avista issues common stock on a recurring basis.” The amortization
mechanism proposed by Pacificorp and rejected by the WUTC in the referenced proceeding is not
comparable to the flotation cost methodology recommended in Mr. McKenzie’s testimony, which is directly comparable to that approved by the Commission in WUTC v. Avista Corp., Docket UE-991606,
Third Supplemental Order ¶ 358 (Sept. 29, 2000).

Page 1 of 3
-20%
0%
20%
40%
60%
80%
100%
120%
2006 2007 2008 2009 2010 2011 2012 2013 2014 2015 2016 2017 2018 2019
Av
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Net Plant Investment Non-Fuel O&M/A&G Retail kWh Sales Retail Therm Sales
Utility Investment and Costs are Rising Faster than Sales
Actual
Forecast
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/18/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 017 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Reference Andrews Workpaper “2007-2015 WA 2017 Electric-Attrition.xlsx,” tab “Adj Operating Exp-
2007-2015”: That workpaper shows Adjusted Operating Expenses of $134.6 million in 2012 and $132.6 million in the test period. In addition, the LINEST() Excel function from 2012 – 2015 shows a negative
slope of $0.4 million per year. Does the Company agree that, since 2012, electric operating expenses
have declined and have trended downward? If no, please explain.

RESPONSE: No, the Company does not agree. As explained in Ms. Andrews’ testimony, Exhibit No. __(EMA-1T),
starting at page 16, the non-fuel O&M/A&G costs dip down in 2013, and then grow at somewhat slower
pace than in prior years. This trend was illustrated at page 16, Illustration No. 3 (green line) of Exhibit
No. __(EMA-1T), and reproduced below. Although there is a lower level of costs in 2013 versus 2012
due to reduction in specific costs noted in Ms. Andrews’ testimony and discussed again below, there is a clear increase year-over-year in expenses from 2013 forward. These reductions in costs are also clearly
incorporated into the 2015 “escalation base” to escalate costs through the Attrition Studies to the 2017
and January to June 2018 rate periods. This ensures that the cost saving measures of prior years, including
the drop in the level of expenses from 2012 to 2013, are included in the rates set for the 2017 and January
to June 2018 rate periods.

Page 2 of 3
The drop in non-fuel O&M expense from 2012 to 2013, and growth in non-fuel O&M expenses from 2013
forward, are shown in Andrews’ Workpaper “2007-2015 WA 2017 Electric-Attrition.xlsx,” tab “Adj
Operating Exp-2007-2015.” This data is reproduced below, however, updated non-fuel O&M expenses for 12.2015 is also included:
9.2015
Updated
12.2015
2012 2013 2014 2015 2015

134,594

128,510

130,891

132,584

134,827 This table above also clearly shows the actual reduction in O&M costs in 2013 versus 2012, and the steady
increases in actual O&M costs year-over-year from 2013 through 2015. As discussed in Ms. Andrews
testimony, the noticeable reductions in O&M costs starting after December 2012 shown in the illustration
and data table above, followed the fourth quarter 2012 implementation of its Voluntary Severance Incentive Plan (VSIP) program to reduce employee complement at the Company, reducing the overall base labor costs starting in 2013 and going forward. The Company’s elimination of its defined benefit pension plan for non-
union new hires beginning in 2014, and the transition away from providing medical coverage for non-union
retirees1 also reduced costs going forward.
Other reduction in costs include a variety of cost reduction measures as described in various testimonies as filed. For example, as discussed further by Ms. Rosentrater, at Exhibit No. __(HLR-1T), Avista’s asset
management programs, are designed, in part, to focus on capital projects that will decrease O&M costs.
Further, Mr. Thies, discusses at Exhibit No. __(MTT-1T), that Avista’s cost-of debt (and resulting interest
expense) has trended downward the last several years.2 Mr. Morris, at Exhibit No. __(SLM-1T), explains that the Company continues to monitor its compensation and benefits practices to ensure that they are competitive with those offered by other similar utilities, including a design in which a portion of all
employees’ compensation is pay-at-risk, which is dependent on achieving cost-saving targets each year for
O&M and A&G. All of these efforts contribute towards managing the Company efficiently and keeping
O&M and A&G costs lower than they otherwise would be over time.
However, as explained by Mr. Morris, as Avista continues to work to control its costs, it is also experiencing
a continuing increase in various compliance and reporting requirements. These requirements involve, among
other things, monitoring, inspecting, testing, reporting, adding redundancy, and increasing security – both
physical security and cyber security. The requirements are driven by, among other things, NERC requirements related to electric reliability, FERC requirements related to assuring the existence of
competitive wholesale markets, environmental requirements to ensure we are being good stewards of the
environment, and financial requirements to ensure full and fair disclosure of information. Compliance with
these important requirements involve people and systems, which, among other factors, is putting upward
pressure on our O&M costs.
To provide further clarification of the increases in O&M, Ms. Andrews provided illustration No. 6 within her
testimony at page 33, reproduced below, which uses the same information from Illustration No. 3 included in
her testimony (reproduced above), isolating the non-fuel O&M and A&G expenses for the period 2006
through 2015 (actual) and expected 2016 through 2019 (forecasted).

1 These changes for the bargaining unit will be subject to future negotiations. 2 Mr. Thies also explains that there is an expected increase in cost of debt expected in 2017 compared to 2015 due to the
maturation of certain debt. See page 22 of Exhibit No. __(MTT-1T).

Page 3 of 3
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Av
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.

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Non-Fuel O&M/A&G 2007-2015 trend through 2019
Utility Non-Fuel O&M % Growth 2006-2019
(O&M excerpt from Illustration No. 3 "Utility Costs are Rising Faster Than Sales")
ACTUAL
Forecast
(1)Blue line shows expected extension
if costs had not been reduced, starting
in 2012 forward, based on Company
efforts to cut costs.
(2) System O&M LinearTrend
Line using 2007-2015 Data.
(3) Extension of 2007-2015 System
Trend Lineto 2017 shows trend is
just below expected O&M per
Forecast.

Included on this chart are trend lines showing: (1) the expected trend (or extension of costs using
2006-2012 data) (blue line) if costs had not been reduced starting in 2012 forward based on Company efforts to reduce costs; (2) the system O&M linear trend (black dashed line) using actual 2007-2015
system data; and (3) extension of the 2007-2015 actual system O&M trend (red dashed line) from
2015 through 2019.
What can be seen from this illustration, again, is the significant reduction in the level of expenses
starting in 2013, which has accomplished two very important results benefiting customers: 1) the slope of the trend in expenses has been reduced; and 2) the starting point or level of expense at 2015
(used by the Company’s Attrition Studies as the “base” for its trend analysis) also reflects this
reduction in expenses, ensuring that customers are benefiting from these reductions. This illustration
also shows the trended increase in O&M expenses beyond 2013, and that the use of 2007 – 2015 data
(as proposed by the Company for O&M, and consistent with all other cost categories) provides a reasonable and appropriate growth trend from 2015 to the 2017 and January to June 2018 rate periods.
Extending the 2007-2015 growth trend beyond 2015, one can see that the red dashed line results in a
level of expense slightly under that expected in 2017 and 2018.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 018 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide copies of all workpapers and modeling files used to develop the AURORA modeling in this proceeding.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 018C. Please note that
Attachment A in Avista’s response to ICNU – 018C is Confidential per Protective Order in UTC
Dockets UE-160228 and UG-160229.

Please see the CD provided with all the workpapers and modeling used to develop the AURORA model for this case. The Company provided this information in its original filing.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: Paul Kimball
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 019 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide copies of all workpapers and modeling files used to develop the Final AURORA modeling in the Company’s prior two general rate case proceedings.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request No. ICNU – 019C. Please note that
Attachment A in Avista’s response to ICNU – 019C is Confidential per Protective Order in UTC
Dockets UE-160228 and UG-160229.

Please see the CD provided with all the workpapers and modeling used to develop the AURORA model for the prior two Washington general rate cases. ICNU_DR_019C Confidential Attachment
A (2015 GRC, Docket No. UE-150204) and B (2014 GRC, Docket No. UE-140188).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 020 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all workpapers used to convert the output of the AURORA model into the net power supply cost tables of Mr. Johnson, such as Exh. No. WGJ-2.

RESPONSE:
There are no workpapers used to convert the output of the AURORA model into the net power
supply cost tables of Mr. Johnson, such as Exh. No. WGJ-2. The relevant AURORA output is
simply copied and pasted into the “AURORA” tab in the Exh. No. WGJ-2 worksheet.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 021 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a comparison of the amount of net power supply cost forecast in rates from the Company’s past three general rate cases and the actual power supply expense incurred by the
Company in the respective rate periods.

RESPONSE:
The table below shows the pro forma power supply expense included in base rates and the actual
power supply expense for the years 2012 through 2015. Power supply expense in base rates was the
same in 2013 and 2014.

The impact of the actual versus approved base net power supply expenses flowed through the
Energy Recovery Mechanism (ERM) subject to the estimated sharing bands.
Pro Forma Power Supply
Expense in General Actual Power
Year Rate Case Supply Expense
(System)(System)
2012 $210,743,000 $203,379,000
2013 $188,771,000 $207,717,000
2014 $188,771,000 $180,012,000
2015 $191,152,000 $160,422,000

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 022 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please describe how the Company intends to determine base net power supply costs, for purposes of the ERM, from the Company’s attrition model. E.g., does the Company intend to use power
supply expense based on 09.2015 loads or based on 2017 loads?

RESPONSE:
As shown within Exhibit No. WGJ-5 the ERM base (and proposed power supply adjustments
included within the electric Attrition models) as proposed by the Company is based on historical
normalized loads for the period Oct 2014 through Sept 2015.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 023 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide transaction or invoice level detail from the Company’s accounting system for the following FERC accounts:
a. 456 – Other Electric Revenues
b. 557 – Other Power Supply Expense
c. 930 – Miscellaneous General Expense
For each database record, please include all fields that are included in the Company’s information system, including but not limited to: the Accounting Year, the Accounting Month, the Posting Date,
the Transaction Date, the Document Number, the FERC Account, the FERC Account Name, the
Location, the Location Name, the Financial Account, the Financial Account Description, the Amount,
as well as a memo or text description of the Amount, the Vendor, the Vendor Name, the Cost Center,
the Cost Center Name, the Profit Center, and the Profit Center Name. Please detail this data on a total-Company basis, and, if possible, on a Washington-allocated basis. Please also indicate how this
data can be tied back to the Company’s filing and workpapers.

RESPONSE:
Please see ICNU_DR_023 Attachment A for the requested information. Due to the size of the file,
the detail transaction spreadsheet is being provided electronically only.

See ICNU_DR_023-Attachment A, pages 1-3 for summaries of accounts 456, 557 and 930.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/27/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth/Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 023 Supplemental TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide transaction or invoice level detail from the Company’s accounting system for the following FERC accounts:
a. 456 – Other Electric Revenues
b. 557 – Other Power Supply Expense
c. 930 – Miscellaneous General Expense
For each database record, please include all fields that are included in the Company’s information system, including but not limited to: the Accounting Year, the Accounting Month, the Posting Date,
the Transaction Date, the Document Number, the FERC Account, the FERC Account Name, the
Location, the Location Name, the Financial Account, the Financial Account Description, the Amount,
as well as a memo or text description of the Amount, the Vendor, the Vendor Name, the Cost Center,
the Cost Center Name, the Profit Center, and the Profit Center Name. Please detail this data on a total-Company basis, and, if possible, on a Washington-allocated basis. Please also indicate how this
data can be tied back to the Company’s filing and workpapers.

RESPONSE:
Please see ICNU_DR_023 Attachment A for the requested information. Due to the size of the file,
the detail transaction spreadsheet is being provided electronically only.

See ICNU_DR_023-Attachment A, pages 1-3 for summaries of accounts 456, 557 and 930.

Supplemental Response April 27, 2016 Based on discussion with Brad Mullin, the data request has been updated to provide Washington’s
share of costs using appropriate allocation factors. Since the test period is the twelve months ended
September 30, 2015, with regards to FERC account 930, two sets of allocation factors were used.
2014 factors are used for the October 1, 2014 – December 31, 2014 expenses and 2015 factors are
used for the January 1, 2015 – September 30, 2015 expenses.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 024 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide accounting detail of the Company’s unadjusted results for the Year Ending September 30, 2015, including FERC sub-account level detail. Please provide the detail on a total-
Company basis (including electric, natural gas, and non-jurisdictional operations of all states).

RESPONSE:
Please see ICNU_DR_024 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 025 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide accounting detail of the Company’s unadjusted results for the Year Ending September 30, 2015, including FERC sub-account level detail. Please provide this detail on a Washington-allocated
basis, with separate detail for electric and gas services.

RESPONSE: Please see ICNU_DR_025 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State and Fed. Regulation
REQUEST NO.: ICNU – 026 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all electronic workpapers, with links intact to the original source data, used to perform inter-jurisdictional cost allocation for purposes of the Company’s filing.
RESPONSE:

The Company provided the calculations of the allocation factors in the original filing and with ICNU_DR_028.

Those calculations were made using the attached data:

ICNU_DR_026-Attachment A, ICNU_DR_026-Attachment B, and ICNU_DR_026-Attachment C are data for the production/transmission (P/T) allocation factor. ICNU_DR_026-Attachment D and
ICNU_DR_026-Attachment E are data used for the 4-factors (Factors 4, 7, 8 and 9). ICNU_DR_026-
Attachment F and ICNU_DR_026-Attachment G are data used for natural gas system contract demand
allocation factor for 2014 and 2015. Due to the size of the files, the spreadsheets are being provided
electronically only.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State and Fed. Regulation
REQUEST NO.: ICNU – 027 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a description of each of the inter-jurisdictional cost allocation factors used by the Company in Washington, including the accounts to which each factor applies.
RESPONSE:

Please see the Company’s response to ICNU_DR_035.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State and Fed. Regulation
REQUEST NO.: ICNU – 028 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide detailed calculation of each of the inter-jurisdictional cost allocation factors used by the Company in this proceeding.
RESPONSE:

The Company provided the electronic version and a pdf version of the allocation factors used in this case with Company witness Ms. Smith’s workpapers. Those documents and files have been provided
electronically only (ICNU_DR_028 Attachment A) with this data request response.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State and Fed. Regulation
REQUEST NO.: ICNU – 029 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

If different than Washington, please provide a description of each of the inter-jurisdictional cost allocation factors used by the Company in Idaho, including the accounts to which each factor applies.
RESPONSE:

The Company uses the same allocation factors in Idaho that are used in Washington.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 030 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the Company’s historical monthly electric loads over the period 2011 through 2015 (inclusive). Please detail the load by jurisdiction (i.e., Washington, Idaho, Alaska).
RESPONSE:
See the attachment labeled “ICNU_030_Attachment A”.
The Company has not provided the requested data for Alaska Electric Light and Power as it is
independent from Avista Utilities.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/20/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 031 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the Company’s historical monthly coincident peak loads over the period 2011 through 2015 (inclusive). Please detail the coincident peak load by jurisdiction (i.e., Washington, Idaho, but
excluding Alaska).

RESPONSE:
Please see ICNU_DR_031 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 032 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the Company’s monthly electric load forecast over the period 2016 through 2019 (inclusive). Please detail the load forecast by jurisdiction (i.e., Washington, Idaho, Alaska).
RESPONSE:

Please see INCU_DR_032 Attachment A. The Company has not provided the requested data for Alaska Electric Light and Power as it is independent from Avista Utilities.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: James Gall
TYPE: Data Request DEPT: Energy Resources
REQUEST NO.: ICNU – 033 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the Company’s monthly coincident peak load forecast over the period 2016 through 2019 (inclusive). Please detail the coincident peak load forecast by jurisdiction (i.e., Washington,
Idaho, but excluding Alaska).

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 033C. Please note
that Avista’s response to ICNU – 033C is Confidential per Protective Order in UTC Dockets
160228 & UG-160229.

Monthly coincident peak load forecasts for Idaho and Washington are included in attachment ICNU_DR_033C Confidential Attachment A. Avista does not develop Washington and Idaho
Peak Load forecasts separately.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: James Gall
TYPE: Data Request DEPT: Energy Resources
REQUEST NO.: ICNU – 034 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please describe how the Clearwater cogeneration facility is reflected in the historical and forecast monthly loads and coincident peak loads provided in the prior requests. Please also provide the
historical and forecast monthly generation of the Clearwater cogeneration facility over the period
2011 through 2019 (inclusive).

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 034C. Please note
that Avista’s response to ICNU – 034C is Confidential per Protective Order in UTC Dockets
150204 & UG-150205.
Avista is responsible to meet the net load from the Clearwater facility beginning July 1, 2013.
Prior to this date Avista met all of Clearwater’s load and purchased the generation. For
forecasting Clearwater peak loads, Avista plans to the 97th percentile of net load between
1/1/2010 and 8/24/2014.
Historical generation is provided in ICNU_DR_034C Confidential Attachment A. Avista does not
forecast future generation.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State and Fed. Regulation
REQUEST NO.: ICNU – 035 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please proved all manuals or documentation that the Company has prepared with respect to performing inter-jurisdictional cost allocation.
RESPONSE:

In Avista’s 2014 Washington general rate cases (Docket Nos. UE-140188 and UG-140189), Company witness Ms. Andrews provided a detailed explanation of the Company’s cost assignment and allocation
methodologies. Please see ICNU_DR_035-Attachment A for this testimony beginning on page 86.

As described in Ms. Andrews’ testimony, the current allocation method used for electric generation and
transmission expenses and net plant investment was reviewed and supported by the Washington and Idaho Commission staffs in 1984. This methodology uses the production/transmission ratio for electric
expense FERC Accounts 500 through 573. Please see ICNU_DR_035-Attachment B for the Study that
was prepared for Avista when it adopted this allocation methodology.

The current method for all other expenses (expense FERC Accounts 580 through 935) and net plant investment (i.e. excluding electric generation and transmission expenses and net plant investment), was
developed and presented to the Commission staffs of Washington, Idaho and Oregon utility commissions
for approval in 1993. The Company obtained approval letters from each jurisdiction and implemented the
new utility codes and allocation methodology in 1994 (Please see ICNU_DR_035-Attachment C). The
cost assignment study prepared in 1993 is provided in ICNU_DR_035-Attachment D.
This allocation methodology and the actual allocation of common costs using the factors computed using
that methodology, have been provided in each general rate case filed by the Company in each of its
jurisdictions since the method was implemented.

Exhibit No. ___(EMA-1T)

BEFORE THE WASHINGTON UTILITIES AND TRANSPORTATION COMMISSION

DOCKET NO. UE-14_____________
DOCKET NO. UG-14_____________

DIRECT TESTIMONY OF
ELIZABETH M. ANDREWS
REPRESENTING AVISTA CORPORATION

ICNU_DR_035 Attachment A Page 1 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 1
Docket Nos. UE-14_______ & UG-14_______
TABLE OF CONTENTS 1
Description Page 2
I. Introduction 2

II. Combined Revenue Requirement Summary 5
Electric and Natural Gas Results Summary 5
Primary Factors Driving Need for WA Electric & Natural Gas Rate Relief 8

III. Attrition Studies 10 9
Electric Attrition Study 14
2015 Electric Attrition Revenue Requirement 17
Natural Gas Attrition Study 24
2015 Natural Gas Attrition Revenue Requirement 27
Electric and Natural Gas Attrition Study Revenue Requirement Summaries 28

IV. Pro Forma Cross Check Studies 29
Electric Pro Forma Cross Check Study 30
Standard Commission Basis and Restating Adjustments 32
Pro Forma Adjustments 49
Natural Gas Pro Forma Cross Check Study 61
Standard Commission Basis and Restating Adjustments 64
Pro Forma Adjustments 74

V. 2016 Information 79 24
25
VI. Compliance with Past Commission Orders 84 26
Tracking of Washington General Rate Case Expenditures 84 27
Internal Audit of Avista Utility Expenditures 85
Tracking of Aldyl-A Natural Gas Pipeline Replacement Program Projects 86
Cost Assignment & Allocation Procedures 86 30
31
Exhibit No.____(EMA-2) Electric Attrition Study (pgs 1-10)
Exhibit No.____(EMA-3) Natural Gas Attrition Study (pgs 1-10)
Exhibit No.____(EMA-4) Electric Pro Forma Cross Check Study (pgs 1-10) 34
Exhibit No.____(EMA-5) Natural Gas Pro Forma Cross Check Study (pgs 1-10)
Exhibit No.____(EMA-6) Electric & Natural Gas 2016 Attrition Studies (pgs 1-16)
Exhibit No.____(EMA-7) Allocation Processes & Methodologies (pgs 1-28) 37

ICNU_DR_035 Attachment A Page 2 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 2
Docket Nos. UE-14_______ & UG-14_______
I. INTRODUCTION 1
Q. Please state your name, business address, and present position with 2
Avista Corporation. 3
A. My name is Elizabeth M. Andrews. I am employed by Avista Corporation
as Manager of Revenue Requirements in the State and Federal Regulation Department.
My business address is 1411 East Mission, Spokane, Washington.
Q. Would you please describe your education and business experience? 7
A. I am a 1990 graduate of Eastern Washington University with a Bachelor of
Arts Degree in Business Administration, majoring in Accounting. That same year, I
passed the November Certified Public Accountant exam, earning my CPA License in
August 19911. I worked for Lemaster & Daniels, CPAs from 1990 to 1993, before
joining the Company in August 1993. I served in various positions within the sections of
the Finance Department, including General Ledger Accountant and Systems Support
Analyst until 2000. In 2000, I was hired into the State and Federal Regulation
Department as a Regulatory Analyst until my promotion to Manager of Revenue
Requirements in early 2007. I have also attended several utility accounting, ratemaking
and leadership courses.
Q. As Manager of Revenue Requirements, what are your 18
responsibilities? 19
A. As Manager of Revenue Requirements, aside from special projects, I am
responsible for the preparation of normalized revenue requirement and pro forma studies

1 Currently I keep a CPA-Inactive status with regards to my CPA license.
ICNU_DR_035 Attachment A Page 3 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 3
Docket Nos. UE-14_______ & UG-14_______
for the various jurisdictions in which the Company provides utility services. Since 2000, I
have assisted or led the Company’s electric and/or natural gas general rate filings in
Washington, Idaho and Oregon.
Q. What is the scope of your testimony in this proceeding? 4
A. My testimony and exhibits in this proceeding will generally cover
accounting and financial data in support of the Company's need for the proposed increase
in rates based on the Company’s electric and natural gas Attrition Studies. I will explain
the overall methodology and results of the Company’s Attrition Studies, providing overall
attrition revenue requirement, rate base and net operating income balances for its electric
and natural gas operations.
In addition, as a form of “cross check,” I will also explain the Company’s electric
and natural gas results based on a pro forma basis for comparison purposes. The electric
and natural gas Pro Forma Cross Check Studies provide operating results, including
expense and rate base adjustments made to actual operating results and rate base.
For informational purposes, I also will provide the results of the Company’s 15
electric and natural gas Attrition Studies for 2016. My testimony will explain how the
Company has complied with past Commission Orders relating to: tracking Washington
general rate case (GRC) expenditures; completing its Internal Audit of Utility
expenditures; tracking separately it’s Aldyl-A natural gas pipeline replacement program

2 Certain adjustments are used in both the Attrition and Pro Forma studies, such as the Pro Forma Power
Supply adjustment sponsored by Company witness Mr. Johnson, and certain transmission revenues, as
discussed by Company witness Ms. Rosentrater, included in the Company’s Energy Recovery Mechanism
(ERM) as a part of net power supply and transmission expenses included in the authorized ERM base.
ICNU_DR_035 Attachment A Page 4 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 4
Docket Nos. UE-14_______ & UG-14_______
projects; and describing the Company’s service and jurisdictional cost allocation
methodologies. 2
Q. Are you sponsoring any exhibits to be introduced in this proceeding? 3
A. Yes. I am sponsoring Exhibit Nos.____(EMA-2) through ___(EMA-7),
which have been prepared under my direction. Exhibit Nos.____(EMA-2) (Electric) and
___(EMA-3) (Natural Gas) present the results of the Company’s electric and natural gas 6
Attrition Studies, as well as trend data used within the Attrition Studies. These exhibits
also show the calculation of the general revenue requirement, the derivation of the
Company’s overall proposed rate of return, the derivation of the net-operating-income-to-
gross-revenue-conversion factor, and the proposed revenue requirement, based on the
Attrition Study analysis.
Exhibit Nos.__(EMA-4) (Electric) and __(EMA-5) (Natural Gas) provide the
Company’s Pro Forma Cross Check Studies and consist of worksheets, which show
actual twelve-month-ending June 30, 2013 operating results, and pro forma electric and
natural gas operating results and rate base for the State of Washington. These exhibits
show the specific restating and pro forma adjustments used as a “cross check” in support 16
of the electric and natural gas Attrition Study analysis.
Lastly, Exhibit No. __(EMA-6) provides the results of the Company’s electric and 18
natural gas Attrition Studies for 2016, and Exhibit No. __(EMA-7) provides the
Company’s Allocation Processes and Methodologies presentation material discussed later 20
in my testimony.

ICNU_DR_035 Attachment A Page 5 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 5
Docket Nos. UE-14_______ & UG-14_______
II. COMBINED REVENUE REQUIREMENT SUMMARY 1
Electric and Natural Gas Results Summary: 2
Q. Would you please summarize the results of the Company’s Attrition 3
Studies for both the electric and natural gas operating systems for the Washington 4
jurisdiction? 5
A. Yes. The results of the electric and natural gas Attrition Studies show
2015 rate period rates of return (“ROR”) for the Company’s Washington jurisdictional 7
operations of 6.88% and 4.61%, respectively. Both return levels are below the
Company’s requested ROR of 7.71%. The incremental revenue requirement over and
above rates currently in effect that is necessary to give the Company an opportunity to
earn its requested ROR in 2015 is $18,201,000 for electric operations and $12,135,000
for natural gas operations. The overall base electric increase associated with this request
is approximately 3.8%. The base natural gas increase is approximately 8.1%.3
Q. What are the Company’s rates of return that were last authorized by 14
this Commission for its electric and natural gas operations in Washington? 15
A. The last authorized rate of return by this Commission for both the
Company’s electric and natural gas operations in its Washington jurisdiction was 7.64%,
approved in Docket Nos. UE-120436 and UG-120437 (Consolidated), effective January
1, 2013.

3 The above revenue requirement amounts for both electric and natural gas operations are the incremental
increases in 2015, reflecting the temporary base rate increases approved for 2014 of $14,054,000 for
electric and $1,358,000 for natural gas. Assuming the 2014 temporary base rate increases would be
permanent going forward (as the Company provides support for this base rate increase continuing on a
permanent basis), produces the overall electric and natural gas incremental revenue requirements necessary
for 2015 reflected above.
ICNU_DR_035 Attachment A Page 6 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 6
Docket Nos. UE-14_______ & UG-14_______
Q. On what test period is the Company basing its need for additional 1
electric and natural gas revenue? 2
A. The test period being used by the Company is the twelve-month period
ending June 30, 2013, presented on an attrition adjusted basis. Current authorized rates
were based upon the twelve-months ending December 31, 2011 test year utilized in UE-
120436 and UG-120437 (Consolidated), adjusted per the settlement agreement approved
by the Commission in those Dockets.
Q. By way of summary, please explain the different rates of return that 8
you will be presenting in your testimony for electric operations. 9
A. There are four different rates of return that are discussed. The actual ROR
earned by the Company during the test period, the normalized or Commission Basis (CB)
ROR results for the test period, the Attrition adjusted ROR determined in my Exhibit
No.___(EMA-2), and the requested ROR. These returns are shown in Illustration No. 1
below:

ICNU_DR_035 Attachment A Page 7 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 7
Docket Nos. UE-14_______ & UG-14_______
Illustration No. 1 1
2

Q. What are these same identified rates of return discussed in your 10
testimony for the natural gas operations? 11
A. These same four rates of return for the natural gas operations (Actual,
Normalized CB, Attrition and Requested) are shown below in Illustration No. 2.
Illustration No. 2 14
15

7.52%7.58%
6.88%
7.71%
6.40%
6.60%
6.80%
7.00%
7.20%
7.40%
7.60%
7.80%
Actual*Normalized CB*Attrition**Requested
Avista Corp
Electric Rates of Return
*Actual and Normalized Commission Basis (CB) rates of return based on twelve-months ended June 30, 2013 results.
** Impact of Attrition on 2015 rate year.
5.03%
5.79%
4.61%
7.71%
0.00%
1.00%
2.00%
3.00%
4.00%
5.00%
6.00%
7.00%
8.00%
9.00%
Actual*Normalized CB*Attrition**Requested
Avista Corp
Natural Gas Rates of Return
*Actual and Normalized Commission Basis (CB) rates of return based on twelve-months ended June 30, 2013 results.
** Impact of Attrition on 2015 rate year.
ICNU_DR_035 Attachment A Page 8 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 8
Docket Nos. UE-14_______ & UG-14_______
Primary Factors Driving Need for Washington Electric and Natural Gas Rate 1
Relief: 2
3
Q. Please explain the primary factors driving the Company’s need for its 4
requested electric and natural gas increases. 5
A. The increase in overall costs to serve customers is driven primarily by two
major factors: 1) the continuing need to replace and upgrade the facilities and technology
we use every day to serve our customers, and 2) low revenue growth.
More specifically, as discussed further by Company witnesses Mr. Morris and Mr.
Thies, in the next five years Avista will need to spend approximately $1.7 billion of
capital on utility generation, transmission and distribution facilities and other
requirements. This $1.7 billion represents over 70% of the current rate base of
approximately $2.4 billion dedicated to serving customers today. As further discussed by
Mr. Morris (and shown in Illustration No. 1 of his testimony), net plant investment for the
last several years has been growing at a much faster pace than retail kilowatt-hour (kWh)
sales and retail therm sales. Furthermore, this mismatch in the growth of net plant
investment and sales is expected to continue to the future, requiring the Company to
request increases in its retail rates to cover this increase in net plant investment since
revenue growth is not sufficient to cover it.
Although the Company is basing its electric and natural gas revenue increases
requested in this case based on its electric and natural gas Attrition Studies, for
informational purposes, the specific 2013 (July-December 2013), 2014 and 2015 planned
capital expenditures undertaken by the Company to expand and replace its generation,
transmission and distribution facilities are explained by Company witness Mr. Kinney
ICNU_DR_035 Attachment A Page 9 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 9
Docket Nos. UE-14_______ & UG-14_______
regarding production assets, and Company witness Ms. Rosentrater regarding
transmission and electric distribution assets. Company witness Mr. Kensok discusses the
Company’s Information Technology capital projects, including the Company’s
replacement of its Customer Information System. Company witness Mr. DeFelice
describes the general plant and gas distribution plant investments, as well sponsors
supporting exhibits for all planned capital investment between July 2013 and 2015
described by each witness noted above.4
Q. Has there been other changes in net costs impacting the Company’s 8
need for rate relief in 2015? 9
A. Yes. As discussed by Company witness Mr. Johnson, production and
transmission net expense changes reflect an overall net reduction to costs related to
decreases in net power supply and transmission expenditures from that currently
authorized. Mr. Johnson explains that the level of Washington’s share of net power
supply expense has decreased by approximately $6.5 million ($9.9 million on a system
basis) from the level currently in base rates.
Our filing reflects an increase in operation and maintenance (O&M) and
administration and general (A&G) expenses. Although the rate of growth in these
expenses has been reduced, as explained by Mr. Morris.

4 For Informational purposes Mr. DeFelice also provides information related to the planned 2016 capital
investments.
ICNU_DR_035 Attachment A Page 10 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 10
Docket Nos. UE-14_______ & UG-14_______
III. ATTRITION STUDIES 1
Q. Before you begin explaining the results of the Company’s electric and 2
natural gas Attrition Study analysis, are other Company witnesses providing 3
testimony relating to the attrition experienced by the Company? 4
A. Yes, Company witness Mr. Norwood discusses the merits of and need for
the electric and natural gas Attrition Studies completed by the Company, and explains the
underearning problem Avista would experience if attrition is not reflected in the rate
making process. My testimony will focus on the calculation and use of the Attrition
Study analysis to determine the requested revenue requirement included in this case.
Q. Please explain the purpose of the electric and natural gas Attrition 10
Study analysis completed by the Company. 11
A. The purpose of the Attrition Studies filed by the Company in this
proceeding are to determine the revenue deficiency in 2015 (as proposed in this filing),
and the need for revenue increases effective January 1, 2015.
As discussed by Washington Utilities and Transportation Commission (WUTC)
staff witness Mr. Elgin in Avista’s rate filing, Docket Nos. UE-120436 and UG-120437,
at Exhibit No. __T (KLE-1T), page 4, lines 7-13:
Staff believes an attrition analysis is the proper approach in circumstances
where a utility allege[s] it persistently fails to realize a fair return. An
attrition study considers all elements of the ratemaking formula: revenues,
expenses, rate base and rate of return in order to judge whether those
relationships in the rate year will be materially different than those in the
test year. An attrition study also is the proper means to adjust rate year
loads for any effects of conservation programs.

ICNU_DR_035 Attachment A Page 11 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 11
Docket Nos. UE-14_______ & UG-14_______
Furthermore, at page 5, lines 9-12, Mr. Elgin adds:

Staff believes an attrition adjustment is a proper tool to use when there is
good evidence that the rate year will be materially different to the test
period impacting the utility’s opportunity to earn a fair return.

Q. Has Avista used an approach in calculating its Attrition Studies that is 7
consistent with attrition study methods previously used in past rate case 8
proceedings? 9
A. Yes. In the Company’s previous 2012 general rate case, the Company
retained Dr. Mark Lowry, President of Pacific Economics Group (PEG) Research, LLC.,
to prepare an electric Attrition Study to determine whether the Company would
experience continued erosion in its earnings through the 2013 rate year (see Exhibit No.
__(MNL-1T) in Docket No. UE-120436).5
As discussed by Dr. Lowry in the previous proceeding, in the early 1980s Avista
[d/b/a Washington Water Power (“WWP”)] had three rate cases in which attrition 16
calculations, and attrition adjustments to the revenue requirement, were approved by the
Commission (see U-81-15 & U-81-16, U-82-10 & U-82-11, and U-83-26). These
attrition calculations accepted by the Commission for Avista were, in all cases, prepared
by witnesses for WUTC Staff in which Staff relied on historical trends. In addition, as
noted by Mr. Elgin in more recent testimony (see Dockets UE-111048 and UG-111049 at
page 67), “An attrition adjustment analyzes actual historical trends in the growth rates of

5The Company used this same approach to produce and file the Company’s 2013 natural gas Attrition Study
(see Andrews’ testimony and exhibits, Exhibit No. __(EMA-1T) in Docket No. UG-120437), and to reflect
the continued erosion expected in 2014 absent additional rate relief (see Company witness Mr. Norwood
discussion at Exhibit No. __(KON-7T), page 10 lines 8-19 in Docket No. UE-120436 and UG-120437
(Consolidated).
ICNU_DR_035 Attachment A Page 12 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 12
Docket Nos. UE-14_______ & UG-14_______
revenues, expenses, and rate base to estimate the erosion in rate of return caused by
disparate growth in these categories.”
As described further in Docket No. UE-120436, Dr. Lowry relied primarily on
Avista’s historical trends in arriving at his attrition calculation, and made use of 4
Commission Basis Reports (CBR’s) for prior years that included normalized cost and
revenue data for Avista’s Washington electric operations. As such, his analysis of
historical cost trends relied on normalizing methods that have been approved by this
Commission and reflected in the CBR’s. M ore specifically, Dr. Lowry used prior
Commission Basis Reports to develop trends in revenues, expenses, and rate base. He
then applied the trends to amounts contained in the 2011 Commission Basis Report to
develop trended values out to the 2013 rate effective period.
In this proceeding, as further described below, Avista has used a similar approach
to prepare its electric and natural gas Attrition Studies using prior Commission Basis
Reports to develop trends in revenues, expenses, and rate base, and then applying these
trends to normalized or Commission Basis adjusted results at June 30, 2013, to develop
trended values out to the rate effective period, or calendar year 2015.
Q. Due to the Settlement agreed to by the Parties in Docket Nos. UE-17
120436 and UG-120437, the revenue requirement approved by the WUTC was not 18
based on a specified attrition study or amount. Did Staff, however, recognize that 19
Avista would experience attrition? 20

ICNU_DR_035 Attachment A Page 13 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 13
Docket Nos. UE-14_______ & UG-14_______
A. Yes. As discussed by Mr. Elgin, starting at page 5 of Exhibit No. __T
(KLE-7T), line 13: 2
Staff conducted a detailed attrition study, and concluded Avista in
all likelihood will experience attrition in the 2013 rate year…. In fact, the
record evidence is clear that attrition is likely to prevail for the foreseeable
future. Avista will continue to experience significant increases in its rate
base at a time when there is little, if any, growth in revenue. The effect of
these circumstances on Avista today and for the next few years will be
attrition. In particular, absent a significant reduction in the amount of its
capital budget, growth in load and decrease in operating expense, the most
likely scenario for Avista in 2014 will be the results Avista is presenting
today: a need for additional rate relief. The record evidence is clear on this
fact.

As the Company continues to experience increases in costs, particularly
significant increases in its rate base, at a time when there is a low growth in revenue, the
Company has prepared electric and natural gas Attrition Studies to support its revenue
requirement requested in this proceeding.
The electric and natural gas Attrition Studies are discussed further in the
testimony that follows and provided in Exhibit Nos. __(EMA-2) (pages 1-10), and
__(EMA-3) (pages 1-10). The Company has also provided workpapers, both in hard copy
and electronic formats, providing the June 30, 2013 ending electric and natural gas
Commission Basis results6 and additional details related to the Attrition Study analysis.

6 Included in these workpapers is a summary listing describing each CB restating and normalizing
adjustment as well as workpapers supporting each adjustment.
ICNU_DR_035 Attachment A Page 14 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 14
Docket Nos. UE-14_______ & UG-14_______
Electric Attrition Study 1
Q. Please explain what is shown on page 1 of the Electric Attrition Study 2
provided as Exhibit No._____(EMA-2). 3
A. Exhibit No._____(EMA-2), page 1, shows the calculation of the electric
general revenue requirement, based on the Company’s electric Attrition Study analysis, to
earn the 7.71% rate of return proposed by the Company for its State of Washington
electric operations. Page 1, shows the 2015 electric revenue requirement of $32,255,000
(column (e)), the temporary revenue increase of $14,054,000 presently in effect (column
(f)), and the incremental revenue increase needed for 2015 of $18,201,000 (column (g)).
The Company’s revenue requirement analysis demonstrates the need for the 10
continuation of the 2014 temporary revenue increase of $14,054,000, and an incremental
revenue increase for 2015 of $18,201,000.
Column (a), of page 1 labeled Attrition Balances shows the electric Attrition
Rate Base and Attrition Net Operating Income balances, from page 5 of Exhibit
No.____(EMA-2), column [K], lines 31 and 49.
Column (b) of page 1 labeled Revenue Growth Factor shows the revenue growth
factor of 1.020771, as reflected from 5 of Exhibit No.____(EMA-2), column [K], line 55.
In the case of retail revenue, my Attrition Study uses the Company’s forecast of loads and
customers for 2015 to estimate the expected revenue in 2015 at base rates effective
January 1, 2013. Since the rate increase in this proceeding will be applied to the twelve-
months-ending June 30, 2013 test period billing determinants, I have divided my rate year
ICNU_DR_035 Attachment A Page 15 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 15
Docket Nos. UE-14_______ & UG-14_______
attrition-adjusted revenue requirement by the revenue growth factor to reflect the amount
needed to be recovered from the test period level of retail loads and customers.
Column (c), labeled Attrition Adjusted Balances shows the calculation of the
$32,541,000 revenue requirement at the requested 7.71% rate of return based on the
electric Attrition Study “Attrition Rate Base” and “Attrition Net Operating Income”
balances in column (a) adjusted for the revenue growth factor from column (b).
Column (d), labeled After Attrition Adjustments includes a reduction of
$287,000 from the Attrition Revenue Requirement amount in column (c) resulting from
adjustments necessary to restate the attrition-adjusted sub-total for offsets that are outside
the attrition-adjusted revenue requirement proposed in this case.7
Column (e) labeled Final Balances shows the electric attrition adjusted revenue
requirement, after reflecting the “After Attrition Adjustments” included in column (d), 12
resulting in an adjusted electric attrition total of $32,255,000.
Column (f) shows the 2014 Temporary Rate Increase approved in Docket UE-
120436 of $14,054,000 currently in effect.8 Due to the revenue requirement need in total,

7 These adjustments include (4.05) Lake Spokane Deferral 3-Year Amortization, which includes an
amortization expense starting in 2015, and (4.06) O&M Offsets, reflecting reductions in operation and
maintenance (O&M) which will occur in 2015 related to capital investments included for the period July
2013 through 2015. These adjustments represent activities which were not included in the 6/30/2013
normalized commission basis results used as the starting point of the Company's attrition analysis. (See
Electric Pro Forma Adjustments section below for detailed description of these adjustments.) However,
after completing our review of this case, the Company realized that the O&M Offset adjustment should have
been included as a Pro Forma Cross Check Study adjustment only, and not included as an offset to the
Attrition adjusted total. 8 Order No. 09, Docket Nos. UE-120436 and UG-120436 (Consolidated), authorized the 2014 rate increase
effective January 1, 2014 to December 31, 2014 on a temporary basis, with rates reverting back to 2013
levels absent any intervening Commission action. While the Commission found the 2014 rate increases to
be fair, just, reasonable and sufficient on a temporary basis, the Commission stated "justification for our
temporary approval lies primarily in Avista's representations that the Company will continue its multi-year
capital expenditure program for 2014."
ICNU_DR_035 Attachment A Page 16 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 16
Docket Nos. UE-14_______ & UG-14_______
as shown in column (e) of $32,255,000, a portion of which relates to 2014 activities, the
2014 revenue increase should continue on a permanent basis, resulting in an incremental
revenue requirement need as shown in column (g).
Column (g) labeled 2015 Revenue Requirement, therefore, produces the final,
2015 incremental revenue requirement requested in this case of $18,201,000. The
resulting percentage revenue increase above 2014 total general business revenues is
3.78%.
Q. Would you please explain page 2 of Exhibit No._____(EMA-2)? 8
A. Yes. Page 2 shows the proposed Cost of Capital and Capital Structure
utilized by the Company in this case resulting in the weighted average cost of capital of
7.71%. Company witness Mr. Thies discusses the Company’s proposed rate of return and 11
the capital structure utilized in this case, while Company witness Mr. McKenzie provides
additional testimony related to the appropriate return on equity for Avista. 13
Q. What does page 3 of Exhibit No._____(EMA-2) show? 14
A. Page 3 shows the derivation of the electric net-operating-income-to-gross-
revenue conversion factor. The conversion factor takes into account uncollectible
accounts receivable, Commission fees and Washington State excise taxes. Federal
income taxes are reflected at 35%.
Q. Would you now please explain pages 4 through 10 of Exhibit 19
No.____(EMA-2)? 20
A. Yes. As further discussed in more detail below: pages 4 and 5 provide
Avista’s 2015 electric attrition revenue requirement calculation; pages 6 and 7 provide 22
ICNU_DR_035 Attachment A Page 17 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 17
Docket Nos. UE-14_______ & UG-14_______
electric cost and revenue trend data for the period 2000-2012 per historical Commission
Basis results of operations; page 8 provides summary data and adjustments to the
historical data, and balances that develop the basis for the escalation factors shown on
page 9; page 9 presents the annual electric growth rate analysis, and the escalation factors
used in the Attrition Study; and the final page, page 10, shows the development of the
electric weighted revenue growth rate from the June 2013 test period to the 2015 rate
period.
2015 Electric Attrition Revenue requirement 8
Q. Please describe in more detail what can be found on pages 4 and 5 of 9
Exhibit No. __(EMA-2). 10
A. Pages 4 and 5 present the normalized income statement and rate base for
Washington electric operations, with the full cost, revenue and rate base detail that is
found in Avista’s June 2013 CBR. This report also provides the final result of the
Company’s electric attrition adjusted revenue requirement proposed in this filing.
Q. What is shown in column [A] on pages 4 and 5? 15
A. The first column labeled [A] 06.2013 Commission Basis Report 16
Restated Totals, provides the results of the June 2013 Commission Basis Report (CBR)
that includes normalized cost and revenue data for Avista’s Washington electric 18
operations for the period twelve-months-ended June 30, 2013. This column shows that on
a CBR, normalized basis for this historical test period, the Company’s earned ROR for its
Washington electric operations was 7.58%, less than its authorized ROR of 7.64% for the
2013 period.
ICNU_DR_035 Attachment A Page 18 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 18
Docket Nos. UE-14_______ & UG-14_______
The next column labeled [B] 06.2013 Normalized Net Power Supply, is
subtracted from column [A], removing all CBR normalized energy related cost and
revenues (e.g. fuel, purchased power, sales for resale revenues) from the 06.2013 CBR
values. (Pro forma level net power supply costs are added back later, as discussed further
below.) This removal ensures only non-energy costs are trended to the 2015 rate period.
The next column labeled [C] 06.2013 Ending Balance Plant Adjustment, is an
addition to column [A], restating plant additions included in the historical CBR test year
on a June 30, 2013 AMA basis to an end of period (EOP) basis, together with the
associated accumulated depreciation and deferred federal income taxes at a June 30, 2013
end of period basis.9 This adjustment also includes the annual level of associated
depreciation expense on all plant-in-service at June 30, 2013. This adjustment, sponsored
by Mr. DeFelice and described further within his testimony, is necessary to represent the
appropriate level of net plant rate base and expense to trend forward to the 2015 rate year.
The next column labeled [D] Incremental Revenue Normalization Adjustment,
is an addition to column [A], adding Avista’s 2013 electric revenue increase granted in its
last general rate case, Docket No. UE-120436 as if it had been in place for the whole 12-
month period. Revenues and expenses associated with the Schedule 91 Tariff Rider
(DSM), Schedule 93 ERM rebate, and Schedule 59 Residential Exchange credit are
excluded (since these items are recovered/rebated by separate tariffs and do not affect

9 New plant investment related to customer growth/revenue growth for the test period was not adjusted to an
EOP basis in this adjustment in column [C]. The revenue-related plant is, however, adjusted to an EOP
basis in column [D].
ICNU_DR_035 Attachment A Page 19 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 19
Docket Nos. UE-14_______ & UG-14_______
attrition). This adjustment, discussed further by Company witness Ms. Knox, is necessary
to include revenues at the 2013 approved base rate level.10
The next column, [E] June 2013 Escalation Base, is the sum of the previous
columns [A] through [D], providing the June 2013 escalation base costs and rate base
excluding net energy costs. This escalation base provides the balances from which the
escalation factors, discussed below, are applied to determine the 2015 final attrition
revenue requirement.
Q. Please now explain columns [F] through [H]. 8
A. The end of period June 2013 plant and related items such as depreciation
and property taxes need to be escalated two years to determine the expected costs for
AMA 2015 (i.e., essentially from June 2013 to June 2015). O&M is not at end of period
levels and therefore needs to be escalated two and one-half years to determine the
expected costs for AMA 2015. Column [F] Escalation Factor shows the two year
escalation rates (for net plant after DFIT, depreciation/amortization, and adjusted taxes
other than income) and the 2 ½ year escalation rates (for adjusted O&M and adjusted
other revenues). The determination of each of these factors is explained below.
These escalation factors are multiplied by the June 2013 base amounts from
column [E], producing column [G] Non-Energy Cost Escalation Amount.
Adding column [G], the non-energy cost escalation amount to column [E], the
June 2013 base amounts, produces column [H] Trended 2015 Non-Energy Cost, which

10 Included in Column [D] "Incremental Revenue Normalization Adjustment," is an adjustment to new plant
investment during the test period related to customer growth/revenue growth, to adjust it to an EOP basis.
Growth in new revenue plant is included here in order to match growth in plant costs with related growth
revenue included in the Attrition Study analysis.
ICNU_DR_035 Attachment A Page 20 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 20
Docket Nos. UE-14_______ & UG-14_______
provides the 2015 trended amounts, prior to including the impact of 2015 pro formed net
power supply and 2015 revenue growth.
Q. Please continue your discussion, describing the final columns [I] 3
through [K]. 4
A. Column, [I] 06.2013 Pro-Formed Net Energy Cost, adds the energy costs
and sales for resale revenue produced by the AuroraXMP model as discussed by Company
witnesses Mr. Johnson and Mr. Kalich. These values reflect fuel prices and market
conditions for the 2015 rate year, but do not include the costs associated with incremental
load growth from the historical test year to the 2015 rate year.
The next column, [J] Revenue Growth, reflects Avista’s revenue growth between
the test year and the 2015 rate year, by multiplying the retail revenue in column [E] times
the weighted revenue growth Escalation Factor in column [F]. The weighted revenue
growth escalation factor is determined on page 10 of Exhibit No. __(EMA-2). The power
supply cost of the incremental load is priced at the pro-forma average sales and purchase
price of power from Mr. Johnson’s Exhibit No. ___(WGJ-4). Incremental revenue
related expenses are computed on the incremental revenue using the components of the
revenue conversion factor provided on page 3 of Exhibit No. __(EMA-2).
Adding columns [I] Pro-Formed Net Energy Cost and [J], Revenue Growth, to
column [H] Trended 2015 Non-Energy Cost, produces the final column [K] 2015 19
Revenue and Cost. This column is the final column of the 2015 electric Attrition Study
calculation, providing the 2015 attrition net operating income ($86,806,000) and attrition
ICNU_DR_035 Attachment A Page 21 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 21
Docket Nos. UE-14_______ & UG-14_______
total rate base ($1,393,325,000), at lines 31 and 49, respectively. These totals are brought
forward to page 1, column (a), of Exhibit No. __(EMA-2).
Q. Would you please explain what is shown on lines 54 to 56 of page 5 of 3
Exhibit No. __(EMA-2)? 4
A. Yes. Line 54 on page 5 of Exhibit No. __(EMA-2), shows the Revenue 5
Requirement of $33,217,000 necessary for the Company to earn its requested 7.71% rate
of return (ROR) in 2015, prior to the application of the growth factor.
Line 55 on page 5, provides the Revenue Growth Factor of 1.020771. Since the
rate increase in this proceeding will be applied to the twelve-months-ended June 30, 2013
test period billing determinants, it is necessary to divide 2015 rate year, attrition-adjusted
revenue requirement, by the revenue growth factor to reduce the revenue requirement to
be applied to the test period level of retail loads. The 1.020771 is produced by dividing
the sum of the retail revenues on lines 1 and 2 in column [K] by the sum of the retail
revenues on lines 1 and 2 in column [E].
Dividing line 54 (2015 revenue requirement) by the electric revenue growth factor
of 1.020771, produces the amount shown on line 56, Attrition Adjusted Revenue 16
Requirement of $32,541,00011, used by the Company in this proceeding.
Q. Please explain pages 6 and 7 of Exhibit No. __(EMA-2). 18
A. Pages 6 and 7 provide the annual normalized Commission Basis Reports,
showing Washington electric expenses and rate base for the periods 2000 through 2012.

11 This revenue requirement amount is prior to recognition of the “After Attrition” adjustments and 2014
temporary base rate increase, as discussed earlier in my testimony, and shown on page 1 of Exhibit No.
__(EMA-2).
ICNU_DR_035 Attachment A Page 22 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 22
Docket Nos. UE-14_______ & UG-14_______
These data are used to determine the trends in rate base and expenses for the Attrition
Study.
Q. What is included on page 8 of Exhibit No. __(EMA-2)? 3
A. Page 8 shows the development of electric adjusted data and balances for
the period 2000-2012 used to calculate the growth rates and escalation factors on page 9.
The escalation factors are intended to be used only on non-energy costs. Therefore it is
necessary to remove the energy-related costs and revenues from the historical data. The
Washington share of the normalized power supply costs and revenues from each year’s 8
Commission Basis Report (CBR) filing are deducted from the O&M and Other Operating
Revenue in the historical reports. Similarly, adder schedule revenues and related
expenses such as the DSM Tariff Rider and the Residential Exchange Credit that were
included in the CBRs are also deducted from the historical results to create equivalent
values for our trend analysis. (For the years 2004 and 2006, the CBR data already
excluded DSM and residential exchange adjustments, so additional adjustments were not
required.)
Results are presented for the following aggregated subtotals: Adjusted Operating
Expenses; Total Depreciation/Amortization; Adjusted Regulatory Amortization; Adjusted
Taxes Other Than Income Taxes; Net Plant After Deferred Income tax; Total Rate Base;
and Adjusted Other Revenues, that are use in my trend calculations.
Q. Please explain page 9 of Exhibit No. __(EMA-2). 20
ICNU_DR_035 Attachment A Page 23 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 23
Docket Nos. UE-14_______ & UG-14_______
A. Page 9 shows the annual electric growth rate analysis, compound annual
growth rates to 2012, the resulting 2 and 2 ½ year escalation factors, and the final
escalation factors selected for use within the Attrition Study.
Q. Please discuss the compound growth rate escalation factors utilized 4
within the Attrition Study, and why these particular growth rates were chosen. 5
A. The Company chose to use the five-year Compound Growth Rate of 2007-
2012. Inspecting the results, it can be seen that the growth in cost categories, such as
depreciation expense and net plant, has tended to be higher since 2007. Based on the
Company’s plan for higher capital expenditures in future years, it is appropriate to use the
compound annual growth rates for the 2007-2012 period for rate base and depreciation
expenses.
The escalation for the O&M expenses, however, has been set at a lower level to
reflect the recent cost-cutting measures implemented by the Company, and the
expectation that Avista will manage the growth in these expenses to a lower level in
future years.12 Although Avista’s O&M/A&G costs have grown at an annual rate of 15
approximately 8% per year for the past five years, we have used an annual growth rate of
4% per year for our Attrition Study.
Q. Please explain the final page of Exhibit No. __(EMA-2), page 10. 18
A. The final page of Exhibit No. __(EMA-2), page 10, shows the calculation
of the growth in Avista’s electric billing determinant index from June 2013 to 2015.

12 Examples include the Voluntary Severance Incentive Plan (VSIP) initiated in 2012, discussed by
Company witness Mr. Morris, and the pension and post retirement medical plan changes effective January
1, 2014, discussed by Company Ms. Feltes.
ICNU_DR_035 Attachment A Page 24 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 24
Docket Nos. UE-14_______ & UG-14_______
Column [A] shows the billing determinants from the June 2013 revenue model supporting
the Incremental Revenue Normalization Adjustment on pages 4 and 5, column [D]
discussed previously. These same billing determinants from the 2015 revenue forecast
are shown in column [B], then the percentage growth in the billing determinants from
June 2013 to 2015 is calculated in column [C]. Column [D] shows the associated
revenues from the June 2013 revenue model that were used to determine the weighting in
column [E]. Finally, the weighted growth for each billing determinant is calculated in
column [F] and the sum on line 19 is the 2015 escalation factor for retail revenue growth.
Natural Gas Attrition Study 9
Q. Before moving on to the Company’s Natural Gas Attrition Study as 10
provided in Exhibit No. __(EMA-3), are there similarities between the electric and 11
natural gas studies? 12
A. Yes. The previous explanation of the exhibit pages and analysis for the
electric Attrition Study are similar for the natural gas Attrition Study. I will describe
briefly what can be found within Exhibit No. __(EMA-3), and any differences between
various exhibit pages and analysis.
Q. Please explain what is shown on page 1 of the Natural Gas Attrition 17
Study provided as Exhibit No._____(EMA-3). 18
A. Exhibit No._____(EMA-3), page 1, shows the calculation of the natural
gas general revenue requirement based on the Company’s natural gas Attrition Study
analysis required to earn the 7.71% ROR proposed by the Company for its State of
Washington natural gas operations. Page 1, shows the 2015 natural gas revenue
ICNU_DR_035 Attachment A Page 25 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 25
Docket Nos. UE-14_______ & UG-14_______
requirement of $13,493,000 (column (e)), the 2014 temporary revenue increase of
$1,358,000 (column (f)), and the incremental revenue increase needed for 2015 of
$12,135,000 (column (g)).
Column (a), of page 1 labeled Attrition Balances shows the natural gas Attrition
Rate Base and Attrition Net Operating Income balances, from page 5 of Exhibit
No.____(EMA-3), column [K], lines 31 and 47.
Column (b) of page 1 labeled Revenue Growth Factor shows the revenue growth
factor of 1.021600, from page 5 of Exhibit No.____(EMA-3), column [K], line 55. As
explained in the electric Attrition Study discussion above, my Attrition Study uses the
Company’s forecast of loads and customers for 2015 to determine the revenue in 2015. I
have divided my rate year, attrition-adjusted revenue requirement by the revenue growth
factor to reduce the revenue requirement to be applied to the test period level of retail
loads and customers.
Column (c), labeled Attrition Adjusted Balances shows the calculation of the
$13,506,000 revenue requirement at the requested 7.71% rate of return based on the
natural gas Attrition Study “Attrition Rate Base” and “Attrition Net Operating Income” 16
balances in column (a) adjusted for the revenue growth factor from column (b).
Column (d), labeled After Attrition Adjustments includes a reduction of
$13,000 from the Attrition Revenue Requirement amount in column (c) to reflect O&M
ICNU_DR_035 Attachment A Page 26 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 26
Docket Nos. UE-14_______ & UG-14_______
offsets.13
Column (e) labeled Final Balances reflects the natural gas attrition adjusted
revenue requirement, after reflecting the “After Attrition Adjustments” included in 3
column (d), resulting in an adjusted natural gas attrition total of $13,493,000.
Column (f) shows the 2014 Temporary Rate Increase approved in Docket UE-
120437 of $1,358,000 currently in effect. Due to the revenue requirement need in total,
as shown in column (e) of $13,493,000, a portion of which relates to 2014 activities, the
2014 revenue increase should continue on a permanent basis, resulting in an incremental
revenue requirement need as shown in column (g).
Column (g) labeled 2015 Revenue Requirement, therefore, produces the final,
2015 incremental revenue requirement requested in this case of $12,135,000. The
resulting percentage revenue increase above 2014 total general business revenues is
8.09%.
Q. Would you please explain page 2 of Exhibit No._____(EMA-3)? 14
A. Yes. Page 2 shows the proposed Cost of Capital and Capital Structure
utilized by the Company in this case, and the weighted average cost of capital 7.71%.
Q. What does page 3 of Exhibit No._____(EMA-3) show? 17
A. Page 3 shows the derivation of the natural gas net-operating-income-to-

13 This adjustment includes (4.04) O&M Offsets, reflecting reductions in operation and maintenance
(O&M) expense expected to occur in 2015 related to capital investments included for the period July 2013
through 2015. This adjustment represents activities which were not included in the 6/30/2013 normalized
commission basis results used as the starting point of the Company's attrition analysis. However, after
completing our review of this case the Company realized that the O&M Offset adjustment should have been
included as a Pro Forma Cross Check Study adjustment only, and not included as an offset to the Attrition
adjusted total.
ICNU_DR_035 Attachment A Page 27 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 27
Docket Nos. UE-14_______ & UG-14_______
ross-revenue conversion factor. The conversion factor takes into account uncollectible
accounts receivable, Commission fees and Washington State excise taxes. Federal
income taxes are reflected at 35%.
Q. Would you now please explain pages 4 through 10 of Exhibit 4
No.____(EMA-3)? 5
A. Yes. Pages 4 and 5 provide Avista’s 2015 natural gas attrition revenue 6
requirement calculation; pages 6 and 7 provide natural gas cost and revenue trend data for
the period 2000-2012 per historical Commission Basis results of operations; page 8
provides summary data and the development of the escalation factors shown on page 9;
page 9 presents the annual natural gas growth rate analysis, and includes the escalation
factors used in the Attrition Study on pages 4 and 5; and the final page, page 10, shows
development of the natural gas weighted growth rate for the retail revenue from the June
2013 test period to the 2015 rate period.
2015 Natural Gas Attrition Revenue Requirement 14
Q. You stated before that the natural gas Attrition Study is very similar 15
to the electric Attrition Study. Please point out any conceptual differences on pages 16
4 through 10 of Exhibit No. __(EMA-3) compared to the same pages of Exhibit 17
No.___(EMA-2). 18
A. Gas costs are treated somewhat differently in the Company’s natural gas 19
rates compared to electric rates because of the Purchased Gas Adjustment (PGA) process.
The cost of gas provided to natural gas customers is tracked through a deferral process
which means that to the extent actual costs of gas are higher or lower than the amount
ICNU_DR_035 Attachment A Page 28 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 28
Docket Nos. UE-14_______ & UG-14_______
included in customer revenue, the difference is set aside to be examined in the annual
PGA filings, where updated gas costs are determined. The gas cost portion of rates is
now entirely included in Schedule 150 that will not be changed as part of this general rate
case, and there is no proposed change to gas costs through the Attrition Study.
Pages 4 and 5 include the June 2013 Ending Balance Plant Adjustment in
column [B], Incremental Revenue Normalization Adjustment in column [C], and the
exclusion of Normalized Gas Costs and Revenues is in column [D]. The weighted
revenue growth escalation factors on page 10 include PGA revenue, therefore in order to
determine the correct Revenue Growth in column [J] (pages 4 and 5), the gas cost related
retail revenue was added back to the base before multiplying it by the Escalation Factor
in column [F]. Transportation revenue growth was treated as a separate category,
resulting in two revenue growth escalation factors; one for sales and one for
transportation. Otherwise in all material respects the process is the same as the electric
Attrition Study.
Electric and Natural Gas Attrition Study Revenue Requirement Summaries 15
Q. Referring back to Illustrations No. 1 and 2 on page 7, what were the 16
actual and attrition-adjusted rates of return realized by the Company during the 17
test period for its electric and natural gas operations? 18
A. For the State of Washington, the actual test period rates of return were
7.52% for electric and 5.03% for natural gas. The attrition-adjusted rates of return are
6.88% and 4.61% for electric and natural gas, respectively, under present rates. Thus, the
ICNU_DR_035 Attachment A Page 29 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 29
Docket Nos. UE-14_______ & UG-14_______
Company does not, on an attrition-adjusted basis for the test period, realize the 7.71% rate
of return requested by the Company in this case.
Q. How much additional 2015 revenue requirement would be required 3
for the State of Washington electric and natural gas operations to allow the 4
Company an opportunity to earn its proposed 7.71% rate of return on an attrition-5
adjusted basis in 2015? 6
A. The revenue requirement deficiency totals $18,201,000 for electric and
$12,135,000 for natural gas, as shown on line 7, page 1 of Exhibit Nos._____(EMA-2)
and __(EMA-3), or an increase of 3.78% and 8.09%, for electric and natural gas
respectively, over general business revenues as of 2014.

IV. PRO FORMA CROSS CHECK STUDIES 12
Q. Before explaining each of the Electric and Natural Gas Pro Forma 13
Cross Check Studies prepared by the Company, please explain the purpose of these 14
Pro forma Studies. 15
A. The purpose of the electric and natural gas Pro Forma Cross Check Studies
is to provide a revenue requirement analysis based on individual restating and pro forma
adjustments, and a separate independent analysis of Avista’s need for revenue increases in
2015. These Pro Forma Studies act as a “cross check” to the reasonableness of the
electric and natural gas Attrition Study results discussed previously in Section III.
Attrition Studies. The Pro Forma Electric and Pro Forma Natural Gas Cross Check
Studies are provided as Exhibit Nos. ___(EMA-4) and ___(EAM-5), respectively.
ICNU_DR_035 Attachment A Page 30 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 30
Docket Nos. UE-14_______ & UG-14_______
Electric Pro Forma Cross Check Study 1
Q. Would you please explain what is shown on page 1 of Exhibit 2
No._____(EMA-4)? 3
A. Yes. Exhibit No.____(EMA-4), page 1, shows actual and pro forma
electric operating results and rate base for the test period for the State of Washington.
Column (b) of page 1 of Exhibit No.____(EMA-4) shows twelve-months ending June 30,
2013 actual operating results and components of the average-of-monthly-average rate
base as recorded; column (c) is the total of all adjustments to net operating income and
rate base; and column (d) is the pro forma adjusted results of operations, all under 2014
existing rates. Column (e) shows the revenue increase required which would allow the
Company to earn a 7.71% rate of return for the 2015 rate period. Column (f) reflects total
pro forma electric operating results.
Q. Would you please explain page 2 of Exhibit No._____(EMA-4)? 13
A. Yes. Page 2 shows the calculation of the $18,201,000 revenue
requirement at the requested 7.71% rate of return based on the electric Pro Forma Cross
Check Study.
Q. What does page 3 of Exhibit No._____(EMA-4) show? 17
A. Page 3 shows the proposed Cost of Capital and Capital Structure utilized
by the Company in this case, and the weighted average cost of capital 7.71%, as
previously explained in Section III. Attrition Studies. 20
Q. Please explain page 4 of Exhibit No._____(EMA-4). 21
ICNU_DR_035 Attachment A Page 31 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 31
Docket Nos. UE-14_______ & UG-14_______
A. Page 4 shows the same derivation of the net-operating-income-to-gross-
revenue conversion factor as previously explained in Section III. Attrition Studies.
Q. Now turning to pages 5 through 10 of your Exhibit No._____(EMA-4), 3
would you please explain what those pages show? 4
A. Yes. Page 5 begins with actual operating results and rate base for the
twelve-months-ending June 30, 2013 test period in column (1.00). Individual
normalizing and restating adjustments that are standard components of our annual
reporting to the Commission begin in column (1.01) on page 5 and continue through
column (2.17) on page 7. Individual pro forma adjustments are shown on page 8 in
columns (3.00) though (3.07). The first column on page 9, labeled “Pro Forma Sub-total” 10
is the subtotal of the previous columns (1.00) through (3.07).
Columns (4.00) through (4.03), on page 9 of Exhibit No._____(EMA-4), represent
additional pro forma adjustments related to capital additions for July through December
2013, 2015 and 2015, as well as the pro forma adjustment related to energy efficiency
(DSM). The last column on page 9, labeled “Pro Forma Cross Check Total,” reflects the 15
total electric revenue requirement for 2015 of $32,602,000 based on the use of restating
and pro forma adjustments from the historical test year to the 2015 rate year.
This revenue requirement can be compared as a “cross check” to the revenue 18
requirement determined using the Attrition Study of $32,541,000, which is shown at the
bottom of the second column on page 10 of Exhibit No. __(EMA-4).
Column (4.04) on page 10 represents the difference of ($61,000) between the Pro
Forma Cross Check Study and the Attrition Study.
ICNU_DR_035 Attachment A Page 32 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 32
Docket Nos. UE-14_______ & UG-14_______
Additional columns, shown on page 10 of Exhibit No._____(EMA-4), (4.05) and
(4.06) are final pro forma adjustments to restate the attrition-adjusted sub-total for known
offsets that are outside the attrition-adjusted revenue requirement proposed in this case.
The final pro forma adjustment (4.07) reduces the revenue requirement for current 2014
revenues approved on a temporary basis, leaving the final column “Final Revenue
Requirement Total” representing the proposed operating results and rate base for the test 6
period, and the necessary incremental 2015 rate relief.
The Pro Forma Cross Check revenue requirement is reconciled to the Attrition
Study revenue requirement in order to establish revenue, expenses and rate base numbers
that can be used as inputs to the Company’s cost of service study prepared by Ms. Knox.
Each of the Commission Basis, restating and pro forma adjustments are discussed
in the testimony that follows, and the Company has also provided workpapers, both in
hard copy and electronic formats, outlining additional details related to each of the
adjustment.
Standard Commission Basis and Restating Adjustments 15
Q. Would you please explain each of these adjustments, the reason for 16
the adjustment and its effect on test period State of Washington net operating 17
income and/or rate base? 18
A. Yes, but before I begin, I will note the Results of Operations column
(1.00), reflects the Company’s actual operating results and total net rate base experienced
by the Company for the twelve-month period ending June, 30 2013 on an average-of-
ICNU_DR_035 Attachment A Page 33 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 33
Docket Nos. UE-14_______ & UG-14_______
monthly-average (AMA) basis.14 Columns following the Results of Operations column
(1.00) reflect normalizing and restating adjustments necessary to: restate the actual
results based on prior Commission orders; reflect appropriate annualized expenses;
correct for errors; or remove prior period amounts reflected in the actual June 30, 2013
results.
Q. Please continue with your explanation of each adjustment and its 6
effect on test period net operating income and/or rate base. 7
A. The first adjustment, column (1.01) on page 5, entitled Deferred FIT Rate 8
Base, adjusts the DFIT rate base balance included in the Results of Operations column
(1.00) to the adjusted DFIT balance, as shown within my workpapers provided with the
Company’s filing. This adjustment to rate base is necessary to reflect various revisions
related to the final 2012 tax return filed in 2013 and certain prior period tax return audit
adjustments. Accumulated DFIT reflects the deferred tax balances arising from
accelerated tax depreciation (Accelerated Cost Recovery System, or ACRS, and Modified
Accelerated Cost Recovery, or MACRS) and bond refinancing premiums. These amounts
are reflected on the average-of-monthly-average balance basis. The effect on Washington
rate base for this adjustment is a decrease of $1,890,000. A decrease to Washington net

14 This column, reflects an actual results of operations rate of return of 7.71% as shown on page 1 of Exhibit
No. __(EMA-4), at line 49. This 7.71% excludes the Voluntary Severance Incentive Program (VSIP) costs,
however, as non-recurring and was excluded from recovery from customers in 2013 and 2014. However,
the benefits of the VSIP initiative are reflected in the electric and natural gas operating results in this
proceeding as the labor expense of those individuals who participated in the VSIP initiative were excluded
from the 2015 pro forma level of labor expense. Although the VSIP costs were excluded from recovery
from customers and the operations column (1.00), it is appropriate to include the VSIP costs in the
calculation of actual operating results at twelve-months-period-ending June 30, 2013, resulting in an actual
ROR of 7.52%, as shown on page 1 of Exhibit No. __(EMA-4), at line 50.
ICNU_DR_035 Attachment A Page 34 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 34
Docket Nos. UE-14_______ & UG-14_______
operating income of $18,000 is due to the Federal income tax (FIT) expense on the
restated level of interest on the change in rate base15.
The adjustment in column (1.02), Deferred Debits and Credits, is a
consolidation of previous Commission Basis or other restating rate base adjustments and
their net operating income (NOI) impact. The net impact on a consolidated basis of this
adjustment decreases Washington rate base by $8,768,000. Washington net operating
income (NOI) decreases by a total of $169,000; including reductions to operating income
of $129,000 for expenses, and $85,000 of FIT expense related to the restated level of
interest on the change in rate base, and an increase in operating income for FIT expense of
$45,000.
Adjustments included in the Deferred Debits and Credits consolidated adjustment
are those necessary to reflect restatements from actual results based on prior Commission
orders, and are explained below. For consistency with prior rate case filings, a description
of each previously separated adjustment is included below.
The following items are included in the consolidation: 15
Colstrip 3 AFUDC Elimination reflects the reallocation of rate base and
depreciation expense between jurisdictions. In Cause Nos. U-81-15 and U-82-10,
the UTC allowed the Company a return on a portion of Colstrip Unit 3
construction work in progress (“CWIP”). A much smaller amount of Colstrip 19
Unit 3 CWIP was allowed in rate base in Case U-1008-144 by the Idaho Public
Utilities Commission (“IPUC”). The Company eliminated the AFUDC associated 21
with the portion of CWIP allowed in rate base in each jurisdiction. Since
production facilities are allocated on the Production/Transmission formula, the
allocation of AFUDC is reversed and a direct assignment is made. The rate base
adjustment reflects the average-of-monthly-averages amount for the test period.

15 The net effect of Federal Income Tax (FIT) expense on the restated level of interest expense due to a
change in rate base, is shown within each individual adjustment. The restated debt interest impact per
individual rate base adjustment can be seen on Line 27 of Exhibit No. EMA __(EMA-4).
ICNU_DR_035 Attachment A Page 35 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 35
Docket Nos. UE-14_______ & UG-14_______
There is no adjustment necessary for the effect of the reallocation on Washington
rate base, as the appropriate amount is accurately reflected in the results of
operations column.
Colstrip Common AFUDC is associated with the Colstrip plants in
Montana, and impacts rate base. Differing amounts of Colstrip common facilities
were excluded from rate base by this Commission and the IPUC until Colstrip
Unit 4 was placed in service. The Company was allowed to accrue AFUDC on
the Colstrip common facilities during the time that they were excluded from rate
base. It is necessary to directly assign the AFUDC because of the differing
amounts of common facilities excluded from rate base by this Commission and
the IPUC. In September 1988, an entry was made to comply with a Federal
Energy Regulatory Commission (“FERC”) Audit Exception, which transferred 12
Colstrip common AFUDC from the plant accounts to Account 186. These
amounts reflect a direct assignment of rate base for the appropriate average-of-
monthly-averages amounts of Colstrip common AFUDC to the Washington and
Idaho jurisdictions. Amortization expense associated with the Colstrip common
AFUDC is charged directly to the Washington and Idaho jurisdictions through
Account 406 and is a component of the actual results of operations. The rate base
amount is also included in the results of operations accurately reflecting the
average-of-monthly-averages amount for the test period. No adjustment is
necessary.
Kettle Falls Disallowance reflects the Kettle Falls generating plant
disallowance ordered by this Commission in Cause No. U-83-26. The disallowed
investment and related depreciation, FIT expense, accumulated depreciation and
accumulated deferred FIT on an AMA basis are accurately reflected in the results
of operations column, removing these amounts from actual results of operations.
No adjustment is necessary.
Settlement Exchange Power reflects the rate base associated with the
recovery of 64.1% of the Company’s investment in Settlement Exchange Power.
The 64.1% recovery level was approved by the Commission’s Second 30
Supplemental Order in Cause No. U-86-99 dated February 24, 1987.
Amortization expense and deferred FIT expense recorded during the test period
are accurately reflected in results of operations. However, the production rate
base and accumulated deferred FIT amounts within results of operations are
reflected on an twelve-months ending June 30, 2013 test period AMA basis. The
use of AMA for the rate period was ordered in Order No. 01 in Docket No. U-
071805. To adjust the production rate base and accumulated deferred FIT
amounts to reflect an AMA 2015 rate period basis, the effect on Washington rate
base is a decrease of $5,024,000.
Restating CDA Settlement Deferral adjusts the net assets and DFIT
balances reflected in results of operations associated with the 2008/2009 past
storage and §10(e) charges deferred for future recovery, to a 2015 AMA basis. A
ten-year amortization expense, as approved in Docket No. UE-100467, of the
ICNU_DR_035 Attachment A Page 36 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 36
Docket Nos. UE-14_______ & UG-14_______
CDA Settlement Deferral is accurately reflected in results of operations. The
effect on Washington rate base is a decrease of $247,000.
Restating CDA/SRR (Spokane River Relicensing) CDR Deferral
adjusts the net assets and DFIT balances reflected in results of operations
associated with the CDA Tribe settlement 4(e) Spokane River relicensing
conditions deferred for future recovery, to the proper 2015 AMA basis. A ten-
year amortization expense of the CDA/SRR CDR Deferral, as approved in Docket
No. UE-100467 is accurately reflected in results of operations. The effect on
Washington rate base is a slight increase of $3,000 to remove the effect of DFIT
previously included, but removed per the 2012 Tax Return Audit.
Restating Spokane River Deferral adjusts the net asset and DFIT
balances reflected in results of operations related to the Spokane River deferred
relicensing costs deferred for future recovery, to a 2015 AMA basis. A ten-year
amortization expense of the Spokane River Deferral, as approved in Docket No.
UE-100467 is accurately reflected in results of operations. The effect on
Washington rate base is a decrease of $119,000.
Restating Spokane River PM&E Deferral adjusts the net asset and DFIT
balances reflected in results of operations related to the Spokane River deferred
PM&E costs deferred for future recovery, to a 2015 AMA basis. A ten-year
amortization expense of the Spokane River PM&E Deferral, as approved in
Docket No. UE-100467 is accurately reflected in results of operations. The effect
on Washington rate base is a decrease of $75,000.
Restating Montana Riverbed Lease adjusts the net asset and DFIT
balances reflected in results of operations related to the costs associated with the
Montana Riverbed lease settlement deferred for future recovery, to a 2015 AMA
basis. In the Montana Riverbed lease settlement, the Company agreed to pay the
State of Montana $4.0 million annually beginning in 2007, with annual inflation
adjustments, for a 10-year period for leasing the riverbed under the Noxon Rapids
Project and the Montana portion of the Cabinet Gorge Project. The first two
annual payments were deferred by Avista as approved in Docket No. UE-072131.
In Docket No. UE-080416 (see Order No. 08), the Commission approved the
Company’s accounting treatment of the deferred payments, including accrued
interest, to be amortized over the remaining eight years of the agreement starting
on January 1, 2009. This restating adjustment also includes the increase in the
annual lease payment expense for the additional annual inflation. This adjustment
decreases Washington net operating income by $156,000 and decreases rate base
by $1,100,000.
Restating Lancaster Amortization adjusts the net asset and DFIT
balances reflected in results of operations related to the 2010 ($6.8 million
Washington) deferred Lancaster plant Power Purchase Agreement (PPA), to a
2015 AMA basis. A five-year amortization expense of the Lancaster deferral ends
in November 2015, therefore a reduction in expense for the pro forma period from
that reflected in results of operations reduces expense and increases Washington
ICNU_DR_035 Attachment A Page 37 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 37
Docket Nos. UE-14_______ & UG-14_______
net operating income by $73,000. The effect on Washington rate base is a
decrease of $2,207,000.
Customer Advances decreases rate base for money advanced by
customers for line extensions, as they will be recorded as contributions in aid of
construction at some future time. The reduction to rate base per results of
operations is accurately reflected at approximately $250,000; therefore no
adjustment is necessary to rate base.
Customer Deposits reduces electric rate base by the average-of-monthly-
averages of customer deposits held by the Company, as ordered by this
Commission in Docket UE-090134. The reduction to rate base per results of
operations is accurately reflected at approximately $1,710,000; therefore no
adjustment is necessary to rate base. The corresponding interest paid on customer
deposits is reclassified to utility operating expense, at the current UTC interest rate
of 0.14%. The effect on Washington operating income is a decrease of $1,000.

In summary, as noted above, the net impact on a consolidated basis of the
adjustments described above decreases Washington net operating income by $169,000,
and decreases Washington rate base by $8,768,000.
Q. Please continue describing the remaining adjustments on page 5. 19
A. The adjustment in column (1.03), Working Capital, restates the working
capital balance reflected in the Company’s Results of Operations column (1.00), to the
adjusted working capital balance proposed below.
The Company uses the Investor Supplied Working Capital (ISWC) methodology
to calculate the amount of working capital reflected in its actual results of operations at
twelve-months-ended June 30, 2013 on an AMA basis, resulting in an electric working
capital balance of $18.753 million. This methodology is consistent with the ISWC
methodology utilized in the past three general rate cases, Docket Nos. UE-100467, UE-
110876 and UE-120436. The Company, however, in this proceeding is proposing a few
refinements in its calculation, which increases the Company’s actual working capital 29
balance to $33.968 million, an increase in net rate base of $15.215 million.
ICNU_DR_035 Attachment A Page 38 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 38
Docket Nos. UE-14_______ & UG-14_______
Q. Please describe the refinements to the methodology used to calculate 1
the Company’s working capital proposed in this proceeding. 2
A. The Company proposes the following refinements to its calculation of
working capital as set forth below:
(1) The Company proposes that pension and other post-retirement benefits
liabilities and the associated regulatory asset balances be included as current assets and
current liabilities rather than in investments.
(2) The Company proposes that accumulated deferred income tax balances
associated with its pension and other post-retirement benefits liabilities and regulatory
assets be classified as current assets and current liabilities, along with those underlying
balances.
Q. Please describe the rationale supporting these refinements as 12
proposed to the classification of pension and other post-retirement benefits liabilities 13
and associated regulatory assets. 14
A. The Company proposes that pension and other post-retirement benefits
liabilities, associated regulatory asset balances, and associated accumulated deferred
income tax balances be included as current assets and current liabilities rather investments
because investors have supplied the necessary capital through contributions to its plans in
excess of its accounting expense.
Pension and other post-retirement benefits liabilities (FERC account 228.3) and
the associated regulatory assets (included in FERC account 182.3) represent the
difference between the amount the Company has contributed to its pension and post-
ICNU_DR_035 Attachment A Page 39 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 39
Docket Nos. UE-14_______ & UG-14_______
retirement benefit plans and the amount the Company has recorded to expense for those
same plans. Differences between cumulative expense and contributions can arise as a
result of funding requirements and funding policies. For example, the federal Pension
Protection Act of 2006, as amended, has required the Company to contribute significant
amounts to its pension plan since enacted, and cumulative contributions exceed
cumulative expense recognized to date.
For ratemaking purposes, the Company recovers pension and post-retirement costs
based on the amount recorded to expense. Investor capital is impacted for any difference
between the amounts contributed to the plans and the amounts included in rates as
expense, therefore investors have borne the cost of financing any incremental
contributions.
Although the FERC Uniform System of Accounts requires classification of these
balances as non-current, contributions are made to the plans and amounts are amortized to
expense each year. Thus, there are current activities associated with these balances
despite their non-current balance sheet classification.
Q. Has the WUTC Staff supported and the Commission approved a 16
similar methodology in other proceedings? 17
A. Yes. Most recently, in WUTC v. PacifiCorp, Docket UE-130043,
Pacificorp, through Company witness Mr. Stuver, proposed this same treatment of post-
retirement benefits of current assets and liabilities. WUTC Staff witness Mr. Zawislak, in
Exhibit No. ___(TWZ-1), at page 3, lines 20-22, fully supported the reclassification of
post-retirement benefits to the current assets and liabilities, stating:
ICNU_DR_035 Attachment A Page 40 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 40
Docket Nos. UE-14_______ & UG-14_______
Mr. Stuver’s treatment of post-retirement benefits achieves a
proper balance of ratepayer interests and allows investors to earn a return
on the net unamortized funds they have contributed to Company
employees’ post-retirement benefits.”

The Commission supported this refinement to Pacificorp’s ISWC methodology, 6
approving this change at Order 05, page 93, paragraph 240, which stated:
As Mr. Zawislak testifies, PacifiCorp’s ISWC adjustment is a 8
refinement to the methodology that corrects the calculation of ISWC with
respect to pensions and other post-retirement benefit liabilities including
the associated regulatory assets and derivative assets and liabilities. We
determine that PacifiCorp’s adjustment to working capital relying on the 12
ISWC approach is supported by the record and should be allowed.

An additional example showing support that this classification is consistent with
prior WUTC Commission precedent can be found in Docket UT-950200. In that case, the
Commission allowed U S WEST Communications, Inc. a $70 million increase in rate
base for the prudently incurred Pension Asset (offset by a $38 million decrease in rate
base as a result of a negative ISWC calculation).16
As noted above, the effect of this adjustment on Washington rate base is an 20
increase of $15,215,000. An increase to Washington net operating income of $147,000 is
due to the FIT expense of the restated level of interest on the change in rate base.
Q. Please continue describing the remaining adjustments on page 5, 23
starting at column (2.01).
A. The next adjustment, included after Working Capital, is labeled column
(2.01), Eliminate B & O Taxes, and eliminates the revenues and expenses associated

16 WUTC v. U S WEST Communications, Inc., Docket UT-950200, Fifteenth Suppl. Order at 70 (April 11,
1996).
ICNU_DR_035 Attachment A Page 41 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 41
Docket Nos. UE-14_______ & UG-14_______
with local business and occupation (B & O) taxes, which the Company passes through to
its Washington customers. The adjustment eliminates any timing mismatch that exists
between the revenues and expenses by eliminating the revenues and expenses in their
entirety. B & O taxes are passed through on a separate schedule, which is not part of this
proceeding. The effect of this adjustment is to decrease Washington net operating income
by $45,000.
The adjustment in column (2.02), Restate 2013 Property Tax, restates the
accrued property tax during the test period to actual property tax paid during 2013.
Property tax expense for 2013 was based on actual plant balances as of December 31,
2012. The effect of this adjustment is to decrease Washington net operating income by
$655,000. Please see pro forma discussion below, Adjustment (3.06) Pro Forma Property
Tax, for additional amounts pro formed, increasing the property tax expense included in
the Company’s filing to the 2015 rate year level of expense.
The last adjustment on page 5, shown in column (2.03) Uncollectible Expense,
restates the accrued expense to the actual level of net write-offs for the test period. The
effect of this adjustment is to decrease Washington net operating income by $462,000.
Q. Please turn to page 6 and explain the adjustments shown there. 17
A. The first adjustment shown on Page 6 in column (2.04), Regulatory 18
Expense, restates recorded regulatory expense for the twelve-months-ended June 30,
2013 to reflect the UTC assessment rates applied to revenues for the test period and the
actual levels of FERC fees paid during the test period. The effect of this adjustment is an
ICNU_DR_035 Attachment A Page 42 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 42
Docket Nos. UE-14_______ & UG-14_______
increase to Washington net operating income of $34,000.
The adjustment in column (2.05), Injuries and Damages, which is a restating
adjustment that replaces the accrual with actuals to obtain the six-year rolling average of
injuries and damages payments not covered by insurance. As a result of the
Commission's Order in Docket No. U-88-2380-T, the Company changed to the reserve
method of accounting for injuries and damages not covered by insurance. The effect of
this adjustment is to decrease Washington net operating income by $183,000.
The adjustment in column (2.06), FIT/DFIT/ITC/PTC Expenses, adjusts the FIT
and DFIT calculated at 35% within Results of Operations by removing the effect of
certain Schedule M items, revising the Section 199 Manufacturing Permanent M
Deduction accrued during the test period to the actual Schedule M deduction taken per the
2012 tax return filed in September 2013, and adjusts the appropriate level of production
tax credits and investment tax credits on qualified generation.
The net FIT and production tax credit adjustments increase Washington net
operating income by $735,000. Adjusting for the proper level of deferred tax expense for
the test period increases Washington net operating income by $18,000. This adjustment
also reflects the proper level of amortized investment tax credit for the test period
decreasing Washington net operating income by an additional $2,000. Therefore, the net
effect of this adjustment, all based upon a Federal tax rate of 35%, is to increase
Washington net operating income by $751,000.
The adjustment in column (2.07), Office Space Charged to Subsidiaries,
removes a portion of the office space costs (including, but not limited to office building
ICNU_DR_035 Attachment A Page 43 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 43
Docket Nos. UE-14_______ & UG-14_______
operating and fixed costs, utilities, administrative, security, HVAC, depreciation and
property taxes, as well as other costs related to employee use of phones, laptops, etc.)
using the relationship of labor hours charged to subsidiary/non-utility activities by
employee compared to total labor hours by employee. These percentages are applied to
the employees’ office space (expressed in square feet) and multiplied by office space 5
costs/per square foot. This restating adjustment is made as a result of the Commission's
Third Supplemental Order in Docket No. U-88-2380-T. The effect of this adjustment is
to increase Washington net operating income by $15,000.
The adjustment in column (2.08), Restate Excise Taxes, removes the effect of a
one-month lag between collection and payment of taxes. The effect of this adjustment is
to increase Washington net operating income by $112,000.
The adjustment in column (2.09), Net Gains/Losses, reflects a ten-year
amortization of net gains realized from the sale of real property disposed of between 2003
and June 30, 2013. This restating adjustment is made as a result of the Commission's
Order in Docket No. UE-050482. The effect of this adjustment is to increase Washington
net operating income by $49,000.
The adjustment in column (2.10), Revenue Normalization 2013, is an adjustment
taking into account known and measurable changes that include revenue repricing
(including the 2013 authorized rates approved in Docket No. UE-120436), weather
normalization and a recalculation of unbilled revenue for 2013 base rate increases.
Revenues associated with the Schedule 91 Tariff Rider and Schedule 59 Residential
Exchange are excluded from pro forma revenues, and the related amortization expense is
ICNU_DR_035 Attachment A Page 44 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 44
Docket Nos. UE-14_______ & UG-14_______
eliminated as well.17 Ms. Knox is sponsoring this adjustment. The effect of this
particular adjustment is to increase Washington net operating income by $4,683,000. (A
pro forma adjustment reflecting the 2014 temporary base rate increase currently in effect
is discussed later in my testimony.)
The last adjustment on page 6 included as column (2.11), Eliminate WA Power 5
Cost Deferral, removes the effects of the financial accounting for the Energy Recovery
Mechanism (ERM.) The ERM normalizes and defers certain net power supply and
transmission revenues and costs pursuant to the commission-approved deferral and
recovery mechanism. The adjustment removes the ERM surcharge revenue as well as the
deferral and amortization amounts and certain directly assigned power costs and net
transmission costs associated with the ERM. The effect of this adjustment is to increase
Washington net operating income by $4,387,000.
Q. Please turn to page 7 and explain the adjustments shown there. 13
A. Page 7 starts with the adjustment in column (2.12), Nez Perce Settlement 14
Adjustment, which reflects an increase in production operating expenses. An agreement
was entered into between the Company and the Nez Perce Tribe in 1999 to settle certain
issues regarding earlier owned and operated hydroelectric generating facilities of the
Company. This adjustment directly assigns the Nez Perce Settlement expenses to the
Washington and Idaho jurisdictions. This is necessary due to differing regulatory
treatment in Idaho Case No. WWP-E-98-11 and Washington Docket No. UE-991606.

17 The impact of this adjustment is also included in the Company’s electric Attrition Study. See column [D],
page 4 of Exhibit No. __(EMA-2).
ICNU_DR_035 Attachment A Page 45 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 45
Docket Nos. UE-14_______ & UG-14_______
This restating adjustment is consistent with Docket No. UE-011595. The effect of this
adjustment is to decrease Washington net operating income by $8,000.
The adjustment in column (2.13), Miscellaneous Restating Adjustments,
removes a number of non-operating or non-utility expenses associated with dues and
donations, etc., included in error in the test period actual results, and removes or restates
other expenses incorrectly charged between service and or jurisdiction totaling
approximately $22,600.
The Company also removed 50% of director meeting expenses, as ordered in
Docket No. UE-090134, and restates director fee expenses to reflect a 90% Utility / 10%
non-utility split, totaling approximately $18,600. The effect of this adjustment is to
increase Washington net operating income by $27,000.
Q. As noted above, the Company removed 10% of Director Fee expenses. 12
What is the basis for removing 10% of these costs? 13
A. In 2013, the Company requested each of its Directors, based on their actual
experience, to estimate the time they spend on utility versus non-utility duties and
responsibilities. The responses from the Directors indicated that, in the aggregate,
approximately 90% of the Directors’ time is dedicated to utility matters, and 17
approximately 10% to non-utility. This 90/10 split is consistent with the average split that
has been used in recent years by Avista’s officers.
Q. Please continue with your explanation of adjustments on page 7. 20
A. The adjustment in column (2.14), Restating Incentive Expenses, restates
actual incentives included in the Company’s test period ending June 30, 2013, reducing 22
ICNU_DR_035 Attachment A Page 46 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 46
Docket Nos. UE-14_______ & UG-14_______
overall expense by approximately $3.0 million. This reduction in incentive expense is, in
part, due to a change in Company policy regarding incentive allocation between Capital
and O&M. In prior years, 100% of the incentive plan payout was charged to O&M
accounts. Effective January 1, 2013 approximately 40% is being charged to Capital
projects, consistent with actual employee overall labor charges.
The overall incentive expense included in the Company’s filing is also reduced 6
from that included in the test year, as the expense amount included is based on the
expected incentive payout in 2015 allocated to expense, reduced to reflect a six-year
average of payout percentages. For non-officer incentives, this is calculated by using the
2015 level of labor expense (determined in Pro Forma Labor adjustment 3.02) multiplied
by the payout incentive opportunity per the Company’s current incentive plan (or 12% 11
overall) to determine the incentive payout opportunity, multiplied by the six-year average
of actual percentage payouts for the periods 2007-2012 (or 72%). For officers, the
incentive amount included in the Company’s filing is based on 2013 incentives accrued
for officers (paid Q-1 of 2014), based on operating performance metrics defined in the
Officer Short-Term Incentive Plan (STIP) related to O&M targets18. This amount was
then multiplied by the six-year average of actual percentage payouts for the periods 2007-
2012 (or 28.84%). The net effect of this adjustment increases Washington net operating
income by $1,979,000.
Q. Please continue with your explanation of adjustments on page 7. 20

18 Officer STIP based on earnings per share targets are excluded from this calculation. All long-term
incentives and short-term incentives based on earnings per share targets are borne by shareholders.
ICNU_DR_035 Attachment A Page 47 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 47
Docket Nos. UE-14_______ & UG-14_______
A. The adjustment in column (2.15), Colstrip/CS2 Maintenance, annualizes
the amortization expense included in the Company’s test period related to the 2012
deferred Colstrip and Coyote Springs 2 thermal maintenance expense. A 4-year
Amortization of the 2012 deferral amount approved in Docket No. UE-120436 started
January 1, 2013, expiring on December 31, 2016. The effect of this adjustment is to
decrease Washington net operating income by $358,000.
The adjustment in column (2.16), Restate Debt Interest, restates debt interest
using the Company’s pro forma weighted average cost of debt, as outlined in the
testimony and exhibits of Mr. Thies, on the Results of Operations level of rate base
shown in column (1.00) only, resulting in a revised level of tax deductible interest
expense on actual test period rate base. The Federal income tax effect of the restated
level of interest or the test period decreases Washington net operating income by
$1,203,000.
The Federal income tax effect of the restated level of interest on all other rate base
adjustments included in the Company’s filing are included and shown as an income
impact of each individual rate base adjustment described elsewhere in this testimony.
The last restating adjustment shown on page 7 is included in column (2.17),
Restating June 30, 2013 Capital EOP. This adjustment restates plant additions
included in the test year on a June 30, 2013 AMA basis to an end of period basis, together
with the associated accumulated depreciation and deferred federal income taxes at a June
ICNU_DR_035 Attachment A Page 48 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 48
Docket Nos. UE-14_______ & UG-14_______
30, 2013 end of period basis, as described further by Mr. DeFelice.19 This adjustment
also includes the annual level of associated depreciation expense on all plant-in-service at
June 30, 2013. The effect of this adjustment on Washington net operating income is a
decrease of $415,000. The effect on Washington rate base is an increase of $35,200,000.
The last column on page 7, entitled Restated Total, subtotals all the preceding
columns (1.00) through column (2.17). These totals represent actual operating results and
rate base plus the standard normalizing adjustments that the Company includes in its
annual Commission Basis reports. However, the Restated Total column does not
represent June 30, 2013 test period results of operation on a normalized commission
basis. Differences between certain restating adjustments included in normalized
Commission Basis Reports (CBRs) versus those included here, include but not limited to,
removal of CBR Power Supply (as the Power Supply net expense adjustment is included
later as Pro Forma Power Supply Adjustment (3.0)); inclusion of 2013 annualized
revenues (described in adjustment (2.10) Revenue Normalization above); inclusion of
debt interest restated based on the Company’s proposed weighted cost of debt (described
in adjustment (2.16) Restate Debt Interest above) and inclusion of net plant investment on
an end-of-period basis (described in adjustment (2.17) Restating June 30, 2013 Capital

19 The impact of this adjustment is also included in the Company’s electric Attrition Study. See column [C],
page 4 of Exhibit No. __(EMA-2).
20 As noted by Staff witness Mr. Elgin in his testimony related to the PSE rate case (Docket Nos. UE-
111048 and UG-111049), Exhibit No. KLE-1T, pp. 65-66, the Commission has, under certain
circumstances, accepted end-of-period balances for rate base to address growing investments, rising costs
and regulatory lag. (See WUTC v. Washington Natural Gas Co., Cause No. U-80-111). He also referred to
language from an earlier Order for Puget Sound Power & Light which, while rejecting year-end rate base,
provided that, "[The Commission] has not, however, discounted the validity of year-end rate base where
special conditions exist, such as unusual growth in plant at a faster pace than customer growth and
customary rate making is deficient." (See WUTC v. Puget Sound Power & Light Co., Cause No. U-73-57,
6th Supp. Order at 9 (Oct. 25, 1974).)
ICNU_DR_035 Attachment A Page 49 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 49
Docket Nos. UE-14_______ & UG-14_______
EOP above).21 Each of the adjustments noted above have been included consistent with
past general rate case filings by the Company. For Commission Basis Report results of
operations for test period ending June 30, 2013 (resulting in a 7.58% rate of return),
please see Exhibit No. __(EMA-2), page 5, line 50.
Pro Forma Adjustments 5
Q. Please explain each of the pro forma adjustments shown on page 8. 6
A. The adjustment in column (3.00), Pro Forma Power Supply, was made
under the direction of Mr. Johnson and is explained in detail in his testimony. This
adjustment includes pro forma power supply related revenue and expenses to reflect the
twelve-month period January 1, 2015 through December 31, 2015, using historical
loads.22 Mr. Johnson’s testimony outlines the system level of pro forma power supply
revenues and expenses that are included in this adjustment. This adjustment calculates
the Washington jurisdictional share of those figures, and also, eliminates power supply
costs related to the Clearwater Paper cogeneration purchase directly assigned to Idaho,
and directly assigned Washington Energy Independence Act (EIA) renewable energy
credits (RECs), tracked in a separate REC deferral. The net effect of the power supply
adjustments increase Washington net operating income by $1,483,000.
The adjustment in column (3.01), Pro Forma Transmission Revenue/Expense,18

21 The restated total also includes additional updates, such as increases in expense necessary to annualize
certain expenses included in the test period as restating adjustments, (i.e. Colstrip/CS2 maintenance),
includes proposed changes to working capital related to inclusion of pension related regulatory assets and
liabilities, and reductions to incentive expense recognizing portions capitalized starting 1/1/2013 and to
reflect a 6-year average pay-out for the level of expense included. 22 The impact of this adjustment is also included in the Company’s electric Attrition Study. See column [I],
page 4 of Exhibit No. __(EMA-2).
ICNU_DR_035 Attachment A Page 50 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 50
Docket Nos. UE-14_______ & UG-14_______
was made under the direction of Ms. Rosentrater and is explained in detail in her
testimony. This adjustment includes pro forma transmission-related revenues and
expenses to reflect the twelve-month period January 1, 2015 through December 31,
2015.23 The net effect of the transmission revenue and expense adjustments decrease
Washington net operating income by $3,531,000.
The adjustment in column (3.02), Pro Forma Labor-Non-Exec, reflects known
and measurable changes to test period union and non-union wages and salaries24,
excluding executive salaries, which are handled separately in adjustment (3.03). For non-
union employees, test period wages and salaries are restated to include the March 2013
overall actual increase of 2.8% on an annualized basis, the March 2014 overall increase of
2.8% (approved by the Compensation Committee of the Board of Directors25), and 10
months of the planned March 2015 increase of 2.8%. Ms. Feltes discusses the
Company’s overall compensation plan and notes that a minimum increase in 2015 will be
presented to the Compensation Committee of the Board of Directors for approval at the
Board’s May 2014 Board meeting.

23 The impact of certain transmission revenues (i.e. transmission revenues included in authorized ERM net
energy costs) included in this adjustment are also included in the Company’s electric Attrition Study. See
column [I], page 4 of Exhibit No. __(EMA-2). 24VSIP labor expense, as previously discussed, of those individuals who participated in the VSIP initiative
were excluded in adjustment (3.02) for determining the 2015 pro forma level of labor expense included in
this adjustment. The costs of the VSIP initiative were already excluded from actual results of operations, as
previously noted. 25 In May, 2013, the Compensation Committee agreed to set a minimum salary increase for non-union
employees of 2.5% for 2014, based on the survey data received. In November 2013 based on updated
market data, 2.8% for non-union employees was ultimately approved to be effective March 1, 2014.
ICNU_DR_035 Attachment A Page 51 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 51
Docket Nos. UE-14_______ & UG-14_______
Also included in this adjustment are the actual 2013, and planned 2014 and 2015 union
contract increases for each year.26 The methodology behind this adjustment is consistent
with that used in the Company’s previous Docket No. UE-120436. The effect of this
adjustment on Washington net operating income is a decrease of $1,096,000.
The adjustment in column (3.03), Pro Forma Labor-Executive, reflects known
and measurable changes to reflect an annualized 2013 level of allocated executive officer
salaries (effective March 2013). However, the Company has included utility and non-
utility allocation percentages planned for 2015. The net result of these changes increases
the executive compensation expense slightly from that included in the Company’s 9
historical test period. No additional increases in executive labor for 2014 or 2015
planned expenses have been included in this filing.
The basis for labor allocations in the current rate case is based on an estimate by
each executive of the time to be spent on non-utility activities based on their historical
actual experience and plans for future time periods (including AERC and AEL&P)27. As
we progress through the year, each executive updates the timekeeping system bi-weekly
with actual time spent on non-utility and utility activities. Due to changes within the
organization (such as AERC & AELP discussed by Mr. Thies), the expected 2015
average percentage to be allocated to non-utility for all officers has increased to
approximately 12.2%. Therefore, while there have been no changes to the executive

26 Union increases are governed by contract terms. Negotiations are currently underway with the current
contract expiring on March 25, 2014. 27 See discussion on acquisition of Alaska Energy and Resources Company (AERC) and Alaska Electric
Light & Power (AEL&P) by Mr. Thies at Exhibit No. __(MTT-1T).
ICNU_DR_035 Attachment A Page 52 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 52
Docket Nos. UE-14_______ & UG-14_______
officers salaries in this filing, the weighting of utility/non-utility has been updated to be
approximately 87.8% utility and 12.2% non-utility.
Ms. Feltes discusses Company executive compensation, providing support for the
level of executive compensation included in the Company’s filing. The impact of this
adjustment on Washington net operating income is a slight decrease of $16,000.
The adjustment in column (3.04), Pro Forma Employee Benefits, adjusts for
changes in both the Company’s pension and medical insurance expense, increasing
Washington net operating income by $563,000.
Q. Please describe the pension expense portion of the Employee Benefits 9
adjustment and Washington’s share of this expense. 10
A. As discussed by Ms. Feltes, the Company’s pension expense portion of 11
this adjustment is determined in accordance with Accounting Standard Codification 715
(ASC-715), and has decreased on a system basis from approximately $26.6 million for the
actual test year costs for the twelve months ended June 30, 2013, to $19.8 million for
2015. The decrease in pension expense ($1.7 million Washington electric) is primarily
due to ongoing Company contributions to the Plan (to improve the funded status) and an
increase in the discount rate used in calculating the pension expense and liability. Ms.
Feltes also discusses cost measures the Company has undertaken to reduce pension
expense into the future.
At this time the amounts included in this case are based on the most current
available data. Preliminary pension expense is determined by an outside actuarial firm, in
accordance with ASC-715, and provided to the Company late in the first quarter of each
ICNU_DR_035 Attachment A Page 53 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 53
Docket Nos. UE-14_______ & UG-14_______
year. These calculations and assumptions are reviewed by the Company’s outside 1
accounting firm annually for reasonableness and comparability to other companies. Due
to the timing of this report, additional information may become known during the course
of these proceedings that may require a modification to this adjustment.
Q. Please now describe the medical insurance and post-retirement 5
expense portion of the Employee Benefits adjustment and Washington’s share of 6
this expense. 7
A. The Company’s medical insurance and post-retirement expense portion of
this adjustment ($0.8 million Washington electric) adjusts for the medical-related costs
planned for 2015 above the test period. As discussed by Ms. Feltes, net medical
insurance and post-retirement expense has increased on a system basis from $30.8 million
for the actual test year costs for the twelve months ended June 30, 2013, to $34.1 million
for 2015. The increase in 2014 represents medical trend and utilization expectations as
well as accounting for Health Care Reform mandates. Furthermore, our aging population
within our plan continues to impact our claims experience and retiree utilization and
expense continues to be a concern. Ms. Feltes discusses the actions the Company is taking
to help mitigate some of these increased costs. In addition, these increases in Medical
have been offset by a decrease in ASC715 post-retirement medical expenses. The primary
drivers in this decrease are related to the increase in the discount rate and the changes to
the retiree medical plan discussed by Ms. Feltes. The net impact of the increases in
pension and medical costs is an increase in Washington electric expense of approximately
$866,000.
ICNU_DR_035 Attachment A Page 54 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 54
Docket Nos. UE-14_______ & UG-14_______
The adjustment in column (3.05), Pro Forma Insurance, adjusts actual test
period insurance expense related to the utility for general liability, directors and officers
(“D&O”) liability, and property to reflect the expected 2015 level of insurance, resulting
in an increase in expense of $556,000 Washington share.28 Insurance costs that are
properly charged to non-utility operations have been excluded from this adjustment. In
addition, Avista has removed a total of 10% of the total Directors’ and Officers’ insurance
expense as ordered in Docket No. UE-090134. This adjustment decreases Washington
net operating income by $361,000.
Q. Please briefly explain the causes of the increases in insurance expense. 9
A. The Company is seeing an increase in each of these insurance categories.
General liability insurance is increasing due to primary insurance policy providers seeking
increases due to adverse impacts over the last several years from increased claim history
and due to suspension by insurance providers of the continuity credit provided in previous
years. Property insurance premiums are being driven up by two primary factors: 1)
projected increases in asset values for the Company, and 2) increases in the rate per $100
of coverage of these assets caused by weather related catastrophe losses associated with
Super Storm Sandy in 2012, and significant losses related to a few refinery explosions in
the industry in 2013. Director’s & Officer’s (D&O) insurance premiums are also
expected to increase, driven by a significant reduction in our continuity credit combined
with an increase in premium rates.

28 The increase in insurance expense noted above is net of the offset to reduce D&O insurance expense for
the 10% portion removed.
ICNU_DR_035 Attachment A Page 55 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 55
Docket Nos. UE-14_______ & UG-14_______
Q. Please continue with your explanation of the pro forma adjustments 1
shown on page 8. 2
A. The adjustment in column (3.06), Pro Forma Property Tax, restates the
2013 level of property tax expense (previously discussed in the Restating Adjustment
section above, see Adjustment (2.02) Restate 2013 Property tax), to the 2015 level of
expense. As can be seen from my workpapers provided with the Company’s filing, the 6
property on which the tax is calculated is the property value as of December 31, 2014,
reflecting the 2015 level of expense the Company will experience during the rate period.
The effect of this adjustment decreases Washington net operating income by $1,325,000.
Q. With regards to the 2013 level of property tax expense included prior 10
to this pro forma adjustment, what date is used to determine the property value and 11
tax? 12
A. The tax basis for the 2013 period expense is based on plant balances as of
December 31, 2012.
Q. What does this mean for ratemaking purposes and the impact of 15
property tax expense in this case? 16
A. The restated property tax expense for 2013, prior to this pro forma
adjustment, is understated for ratemaking purposes, because it only captures the property
taxes on property owned by the Company at December 31, 2012. For ratemaking
purposes, this filing must capture the property tax associated with all property that will be
assessed property taxes during the rate year. A property tax that captures only property
owned on December 31, 2012 will not serve to match costs with benefits.
ICNU_DR_035 Attachment A Page 56 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 56
Docket Nos. UE-14_______ & UG-14_______
Q. How has Avista calculated its property tax adjustment in this filing? 1
A. The Company’s pro forma property tax calculation captures all assets 2
owned on December 31, 2014. This adjustment is necessary, because the 2013 level of
property tax expense represents an understated estimate of the property taxes associated
with the rate year for two reasons. First, the 2013 level of property tax does not include
any actual additions to plant for 2013 or 2014. These additions are the basis for the actual
expenses the Company will incur in 2015. Second, the methodology used to produce the
tax value included in the historical test year violates the matching principle, because it
fails to match the costs in the rate year with the benefits derived from the assets owned
during the rate year.
Q. Please summarize how Avista has calculated the property tax expense 11
included in this filing. 12
A. The system tax basis was determined by using the actual tax basis used to
compute the 2013 actual property tax expense, which was the net book value of Company
owned property as of December 31, 2012. This amount was increased approximately
$107 million, to reflect actual plant additions for 2013, net of 2013 actual depreciation
expense. In addition, the tax basis was increased by approximately $87 million to reflect
2014 plant additions and depreciation expense. The most current tax rates were applied to
this computed tax basis to determine the 2015 property tax expense. The effect of this
adjustment decreases Washington net operating income by $1,325,000.
Q. Please continue with your discussion of the pro forma adjustments 21
included on page 8 of Exhibit No. __(EMA-4). 22
ICNU_DR_035 Attachment A Page 57 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 57
Docket Nos. UE-14_______ & UG-14_______
A. The last column on page 8, includes the adjustment in column (3.07), Pro 1
Forma Information Technology/Services Expense, which includes the incremental
costs associated with software development, application licenses, maintenance fees, and
technical support for a range of information services programs. As discussed further by
Company witness Mr. Kensok, these incremental expenditures are necessary to support
Company cyber and general security, emergency operations readiness, electric and natural
gas facilities and operations support, and customer services. The effect of this adjustment
decreases Washington net operating income by $692,000.
Q. Turning to page 9 of Exhibit No. __(EMA-4), what is shown in the 9
first column on that page? 10
A. The first column on page 9, labeled Pro Forma Sub-Total, reflects total pro
forma results of operations and rate base consisting of test period actual results (twelve-
months ending June 30, 2013) and the restating and pro forma adjustments explained thus
far.
Q. Please briefly explain each of the adjustments included on page 9 of 15
Exhibit No. __(EMA-4).
A. The first adjustment included in column (4.00), Planned Capital 17
Additions December 2013 EOP, reflects the additional July through December 2013
capital additions29 together with the associated accumulated depreciation (A/D) and

29 For each of the periods July-December 2013, 2014, and 201, distribution-related capital expenditures
associated with connecting new customers to the Company’s system was excluded. The Pro Forma Cross
Check Analysis does not include the increase in revenues from growth in the number of customers from the
historical test year to the 2015 rate year and therefore, the growth in plant investment associated with
customer growth was also excluded.
ICNU_DR_035 Attachment A Page 58 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 58
Docket Nos. UE-14_______ & UG-14_______
accumulated deferred federal income taxes (ADFIT) at a December 2013 EOP basis.
This adjustment also includes associated depreciation expense for these July through
December 2013 additions. In addition, the plant-in-service at June 30, 2013 end-of-
period, was adjusted to a December 31, 2013 EOP basis. Mr. DeFelice describes this
adjustment in detail within his testimony. The effect of this component decreases
Washington net operating income by $2,422,000 and increases rate base by $33,588,000. 6
The next adjustment included in column (4.01), Planned Capital Additions 2014 7
EOP, reflects the additional 2014 capital additions30 together with the associated A/D and
ADFIT at a December 31, 2014 EOP basis. This adjustment also includes associated
depreciation expense for these 2014 additions. In addition, the plant-in-service at
December 31, 2013 end-of-period was adjusted to a December 2014 EOP basis. Mr.
DeFelice describes this adjustment in detail within his testimony. The effect of this
adjustment decreases Washington net operating income by $3,655,000 and increases rate
base by $74,587,000. 14
Column (4.02), Planned Capital Additions 2015 AMA, reflects all 2015 capital
additions31 together with the associated A/D and ADFIT at a 2015 AMA basis. This
adjustment includes associated depreciation expense for the 2015 additions. In addition,
the plant-in-service at December 31, 2014 was adjusted to a December 31, 2015 AMA
basis. Mr. DeFelice also describes this adjustment in detail within his testimony. The
effect of this adjustment decreases Washington net operating income by $1,680,000 and

30 Id.
31 Id.
ICNU_DR_035 Attachment A Page 59 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 59
Docket Nos. UE-14_______ & UG-14_______
increases rate base by $19,440,000.
Column (4.03), labeled DSM. As explained by Mr. Ehrbar, one of the reasons
Avista is experiencing attrition is due to our success in assisting our customers with
electric energy efficiency through our DSM programs. Mr. Ehrbar quantifies how much
of Avista’s attrition problem is being caused by electric energy savings through DSM,
which is included in this component. The effect of this component decreases Washington
net operating income by $3,323,000.
As previously discussed, the last column on page 9, labeled “Pro Forma Cross 8
Check Total,” reflects the total electric revenue requirement for 2015 of $32,602,000 9
based on the use of restating and pro forma adjustments from the historical test year to the
2015 rate year. This revenue requirement can be compared or “cross checked” to the 11
revenue requirement determined using the Attrition Study of $32,541,000, shown at the
bottom of the second column on page 10 of Exhibit No. __(EMA-4).
Q. Please describe the individual adjustments shown on page 10. 14
A. The first column on page 10, labeled (4.04), Reconcile Pro Forma To 15
Attrition, represents the difference of ($61,000 revenue requirement) between the Pro
Forma Cross Check Study and the Attrition Study. This adjustment records the reduction
in expense of $438,000, increasing Washington net operating income by $320,000, and
additional net rate base of $3,656,000 necessary to equate with the total level of attrition
deficiency as determined by the Company’s Attrition Study.
The next adjustment in column (4.05), is labeled Lake Spokane Deferral 3-Year 21
Amortization. This adjustment reflects the Company’s proposed three-year amortization
ICNU_DR_035 Attachment A Page 60 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 60
Docket Nos. UE-14_______ & UG-14_______
of the deferred costs related to improving dissolved oxygen levels in Lake Spokane, and
rate base treatment of the deferred balance recorded in account 182.3, net of deferred FIT,
on an AMA basis for the 2015 rate period. Mr. Kinney discusses further the costs
incurred by the Company to study the improvement of total dissolved gas downstream of
the Long Lake and the outcome of that study.
In Docket No. UE-131576 the Company sought, and received approval of (see
Order No. 0l), an Accounting Order to defer the costs related to the improvement of
dissolved oxygen levels in Lake Spokane. Order No. 01 authorized the Company to defer
and transfer Washington’s share of these costs (approximately $871,000) to FERC 9
account 182.3. The Order also approved Avista’s proposal for recovery and prudency of 10
these costs to be determined in its next general rate case or in a separate filing.
The Company therefore, is proposing a three-year amortization of this balance
starting in 2015 when new rates go into effect from this proceeding, as a reasonable
amortization period to reduce the impact on customers, while providing recovery of these
costs at a sufficient rate for the Company. The effect of this adjustment decreases
Washington net operating income by $184,000 and increases net rate base by 472,000.32
The adjustment included in column (4.06) is O&M Offsets. As explained by Mr.
DeFelice, all of the 2013 (July through December), 2014 and 2015 capital additions were
reviewed for any O&M offsets that were expected in the 2015 rate period. Specific

32 It is the Company’s understanding, per Order No. 01 in Docket No. UE-131576, that the Company would
not seek a carrying charge on the deferred balance. After completion of the Company’s revenue requirement
in this filing, the Company realized it had inadvertently included a net rate base addition of $472,000
representing the net rate base balance during the 2015 rate period. Correction of this error would reduce the
requested revenue requirement by approximately $59,000.
ICNU_DR_035 Attachment A Page 61 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 61
Docket Nos. UE-14_______ & UG-14_______
offsets identified were included as a reduction to O&M costs in both the Attrition and Pro
Forma Studies, and discussed in Mr. Kinney, Ms. Rosentrater, and Mr. DeFelice’s direct 2
testimonies with the capital asset with which the offset relates.33 The effect of this
adjustment on Washington net operating income is an increase of $398,000.
The final pro forma adjustment included in column (4.07) Revenue 5
Normalization 2014, includes revenue repricing of the 2014 authorized rates approved
on a temporary basis in Docket No. UE-120436). Ms. Knox is sponsoring this
adjustment. The effect of this adjustment increases Washington net operating income by
$8,724,000.
Q. Please summarize the purpose of the electric Pro Forma Cross Check 10
Study. 11
A. The Company’s electric rate relief for 2015 requested in this case is based
on the Company’s electric Attrition Study results. The purpose of the electric Pro Forma 13
Cross Check Study is to provide a “cross check” to the reasonableness of the electric
Attrition Study as discussed previously in Section III. Attrition Studies. Furthermore, the
Pro Forma Cross Check revenue requirement is reconciled to the Attrition Study revenue
requirement in order to establish revenue, expenses and rate base numbers that can be
used as inputs to the Company’s cost of service study prepared by Ms. Knox.
Natural Gas Pro Forma Cross Check Study 19

33 As noted within the Attrition Study discussion, upon further review of the Company’s filing, the Company
realized that the O&M Offset adjustment should have been included as a Pro Forma Cross Check Study
adjustment only, and not included as an offset to the Attrition adjusted total.
ICNU_DR_035 Attachment A Page 62 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 62
Docket Nos. UE-14_______ & UG-14_______
Q. Would you please explain what is shown on page 1 of Exhibit 1
No._____(EMA-5)? 2
A. Yes. Exhibit No._____(EMA-5), page 1, shows actual and pro forma
natural gas operating results and rate base for the test period for the State of Washington.
Column (b) of page 1 of Exhibit No._____(EMA-5) shows twelve-months ending June
30, 2013 actual operating results and components of the average-of-monthly-average rate
base as recorded; column (c) is the total of all adjustments to net operating income and
rate base; and column (d) is pro forma adjusted results of operations, all under existing
rates. Column (e) shows the revenue increase required which would allow the Company
to earn a 7.71% rate of return. Column (f) reflects total pro forma natural gas operating
results with the requested increase of $12,135,000.
Q. Would you please explain page 2 of Exhibit No._____(EMA-5)? 12
A. Yes. Page 2 shows the calculation of the $12,135,000 revenue
requirement at the requested 7.71% rate of return based on the natural gas Pro Forma
Cross Check Study.
Q. What does page 3 of Exhibit No._____(EMA-5) show? 16
A. Page 3 shows the proposed Cost of Capital and Capital Structure utilized
by the Company in this case, and the weighted average cost of capital calculation of
7.71%, as previously explained in Section III. Attrition Studies. 19
Q. Please explain page 4 of Exhibit No._____(EMA-5)? 20
A. Yes. Page 4 shows the derivation of the net-operating-income-to-gross-
revenue conversion factor. The conversion factor takes into account uncollectible
ICNU_DR_035 Attachment A Page 63 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 63
Docket Nos. UE-14_______ & UG-14_______
accounts receivable, Commission fees and Washington State excise taxes. Federal
income taxes are reflected at 35%.
Q. Now turning to pages 5 through 10 of your Exhibit No._____(EMA-5), 3
would you please explain what those pages show? 4
A. Yes. Page 5 begins with actual operating results and rate base for the
twelve-months-ending June 30, 2013 test period in column (1.00). Individual
normalizing and restating adjustments that are standard components of our annual
reporting to the Commission begin in column (1.01) on page 5 and continue through
column (2.15) on page 7. Individual pro forma adjustments are shown on page 8 in
columns (3.00) though (3.05). The first column on page 9, labeled “Pro Forma Sub-total” 10
is the subtotal of the previous columns (1.00) through (3.07).
Columns (4.00) through (4.02), on page 9 of Exhibit No._____(EMA-5), represent
additional pro forma adjustments related to capital additions for July through December
2013, 2015 and 2015. The last column on page 9, labeled “Pro Forma Cross Check 14
Total,” reflects the total natural gas revenue requirement for 2015 of $13,935,000 based 15
on the use of restating and pro forma adjustments from the historical test year to the 2015
rate year.
This revenue requirement can be compared as a “cross check” to the revenue 18
requirement determined using the Attrition Study of $13,506, which is shown at the
bottom of the second column on page 10 of Exhibit No. __(EMA-5).
Column (4.03) on page 10 represents the difference of ($429,000) between the Pro
Forma Cross Check Study and the Attrition Study.
ICNU_DR_035 Attachment A Page 64 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 64
Docket Nos. UE-14_______ & UG-14_______
An additional column, shown on page 10 of Exhibit No._____(EMA-4), (4.04) is
a final pro forma adjustment to restate the attrition-adjusted sub-total for known offsets
believed to be outside the attrition-adjusted revenue requirement proposed in this case.34
The final pro forma adjustment (4.05) reduces the revenue requirement for current 2014
revenues approved on a temporary basis, leaving the final column “Final Revenue 5
Requirement Total” representing the proposed operating results and rate base for the test 6
period, and the necessary incremental 2015 rate relief.
The Pro Forma Cross Check revenue requirement is reconciled to the Attrition
Study revenue requirement in order to establish revenue, expenses and rate base numbers
that can be used as inputs to the Company’s cost of service study prepared by Company 10
witness Mr. Miller.
Each of the Commission Basis, restating and pro forma adjustments are discussed
in the testimony that follows, and the Company has also provided workpapers, both in
hard copy and electronic formats, outlining additional details related to each of the
adjustment.
Standard Commission Basis and Restating Adjustments 16
Q. Would you please explain each of these adjustments, the reason for 17
the adjustment and its effect on test period State of Washington net operating 18
income and/or rate base? 19

34 However, after completing our review of this case the Company realized that the O&M Offset adjustment
should have been included within the Pro Forma Cross Check Study amount, and not included as an offset
to the Attrition adjusted total.
ICNU_DR_035 Attachment A Page 65 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 65
Docket Nos. UE-14_______ & UG-14_______
A. Yes, but before I begin, I will note the Results of Operations column
(1.00), reflects the Company’s actual operating results and total net rate base experienced 2
by the Company for the twelve-month period ending June, 30 2013 on an average-of-
monthly-average (AMA) basis.35 Columns following the Results of Operations column
(1.00) reflect normalizing and restating adjustments necessary to: restate the actual
results based on prior Commission orders; reflect appropriate annualized expenses;
correct for errors; or remove prior period amounts reflected in the actual June 30, 2013
results.
Q. Please continue with your explanation of each adjustment and its 9
effect on test period net operating income and/or rate base. 10
A. The first adjustment, column (1.01) on page 5, entitled Deferred FIT Rate 11
Base, adjusts the DFIT rate base balance included in the Results of Operations column
(1.00) to the corrected DFIT balance, as shown within my workpapers provided with the
Company’s filing. This adjustment to rate base is necessary to reflect various revisions
related to the final 2012 tax return filed in 2013 and tax return audit adjustments.
Accumulated DFIT reflects the deferred tax balances arising from accelerated tax
depreciation (Accelerated Cost Recovery System, or ACRS, and Modified Accelerated

35 This column, reflects an actual results of operations rate of return of 5.34% as shown on page 1 of Exhibit
No. __(EMA-5), at line 48. This 5.34% excludes the Voluntary Severance Incentive Program (VSIP) costs,
however, as non-recurring and was excluded from recovery from customers in 2013 and 2014. However,
the benefits of the VSIP initiative are reflected in the electric and natural gas operating results in this
proceeding as the labor expense of those individuals who participated in the VSIP initiative were excluded
from the 2015 pro forma level of labor expense. Although the VSIP costs were excluded from recovery
from customers and the operations column (1.00), it is appropriate to include the VSIP costs in the
calculation of actual operating results at twelve-months-period-ending June 30, 2013, resulting in an actual
ROR of 5.03%, as shown on page 1 of Exhibit No. __(EMA-5), at line 49.
ICNU_DR_035 Attachment A Page 66 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 66
Docket Nos. UE-14_______ & UG-14_______
Cost Recovery, or MACRS) and bond refinancing premiums. These amounts are
reflected on the average-of-monthly-average balance basis. The effect on Washington
rate base for this adjustment is a reduction of $883,000. A decrease to Washington net
operating income of $9,000 is due to the Federal income tax (FIT) expense on the restated
level of interest on the change in rate base.36
The adjustment in column (1.02), Deferred Debits and Credits, is a
consolidation of certain commission basis or restating other rate base adjustments and
their net operating income (NOI) impact as described in the Electric Pro Forma section
above. The rate base amount for each of the deferred debits and credits adjustments
discussed below are accurately reflected in the natural gas results of operations reports
and the Results of Operations column (1.00), and therefore no restating rate base
adjustment is necessary. The net impact on a consolidated basis of this adjustment on
Washington natural gas net operating income (NOI) is a reduction of $1,000.
For consistency with prior rate case filings, a description of each previously
separated adjustment is included below.
Customer Advances decreases rate base for money advanced by
customers for line extensions, as they will be recorded as contributions in aid of
construction at some future time. The reduction to rate base per results of
operations is accurately reflected at approximately $13,000; therefore no
adjustment is necessary to rate base.
Customer Deposits reduces natural gas rate base by the average-of-
monthly-averages of customer deposits held by the Company, as ordered by this

36 The net effect of Federal income tax (FIT) expense on the restated level of interest expense due to a
change in rate base, is shown within each individual adjustment. The restated debt interest impact per
individual adjustment can be seen on Line 28 of Exhibit No. __(EMA-3). As discussed later in my
testimony, the “Restate Debt Interest” adjustment restates debt interest using the Company’s pro forma
weighted average cost of debt, as outlined in the testimony and exhibits of Mr. Thies, on the Results of
Operations level of rate base shown in column (1.00) only, resulting in a revised level of tax deductible
interest expense on actual test period rate base.
ICNU_DR_035 Attachment A Page 67 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 67
Docket Nos. UE-14_______ & UG-14_______
Commission in Docket UE-090135. The reduction to rate base per results of
operations is accurately reflected at approximately $449,000; therefore no
adjustment is necessary to rate base. The corresponding interest paid on customer
deposits is reclassified to utility operating expense, at the current UTC interest rate
of 0.14%. The effect on Washington operating income is a decrease of $1,000.

Q. Please continue describing the remaining adjustments on page 5. 7
A. The adjustment in column (1.03), Working Capital, reflects the natural
gas working capital balance for the twelve-month period ending June 30, 2013 on an
AMA basis, based on the ISWC methodology, as explained further in the Electric Pro
Forma Section above.
In the previous natural gas GRC, Docket No. UG-120437, the Company had not
included a natural gas working capital adjustment in order to reduce the rate relief impact
on customers and minimize the issues in that case, although the Company believed it was
entirely appropriate to include as a rate base item. However, the natural gas working
capital requirement continues to impact the natural gas operations, and exclusion of
increases the rate lag experienced in the natural gas Washington jurisdiction. As can be
seen from the proposed balance, the amount of natural gas working capital of $9.1 million
is too significant to continue to exclude from the Company’s rate base requested in its 19
natural gas general rate case. The Company therefore proposes adjustment (1.03),
resulting in an increase to Washington rate base of $9,100,000 and an increase to
Washington net operating income of $88,000, due to the FIT expense on the restated level
of interest on the change in rate base. 23
The adjustment in column (2.01), Eliminate B & O Taxes, eliminates the
revenues and expenses associated with local business and occupation taxes, which the
ICNU_DR_035 Attachment A Page 68 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 68
Docket Nos. UE-14_______ & UG-14_______
Company passes through to customers. The adjustment eliminates any timing mismatch
that exists between the revenues and expenses by eliminating the revenues and expenses
in their entirety. B & O Taxes are passed through on a separate schedule, which is not
part of this proceeding. The effect of this adjustment is to decrease Washington net
operating income by $3,000.
The adjustment in column (2.02), Restate 2013 Property Tax, restates the
accrued property tax during the test period to actual property tax paid during 2013.
Property tax expense for 2013 was based on actual plant balances as of December 31,
2012. The effect of this adjustment is to decrease Washington net operating income by
$404,000. Please see pro forma discussion below, Adjustment (3.04) Pro Forma Property
Tax, for additional amounts pro formed, increasing the property tax expense included in
the Company’s filing to the 2015 rate year level of expense.
The adjustment in column (2.03), Uncollectible Expense, restates the accrued
expense to the actual level of net write-offs for the test period. The effect of this
adjustment is to increase Washington net operating income by $174,000.
Q. Please turn to page 6 and explain the first column shown there, and 16
the adjustments that follow. 17
A. The first adjustment on page 6 in column (2.04), entitled Regulatory 18
Expense Adjustment, restates recorded regulatory expense for the twelve-month period
ended June 30, 2013 to reflect the UTC assessment rates applied to revenues for the test
period. The effect of this adjustment is to increase Washington net operating income by
$16,000.
ICNU_DR_035 Attachment A Page 69 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 69
Docket Nos. UE-14_______ & UG-14_______
The adjustment in column (2.05), entitled Injuries and Damages, is a restating
adjustment that replaces the accrual with actuals to obtain the six-year rolling average of
injuries and damages payments not covered by insurance. As a result of the
Commission's Order in Docket No. U-88-2380-T, the Company changed to the reserve
method of accounting for injuries and damages not covered by insurance. The effect of
this adjustment increases Washington net operating income by $40,000.
The adjustment in column (2.06), entitled FIT/DFIT Expense, adjusts the FIT
calculated at 35% within Results of Operations by removing the effect of certain Schedule
M items. This adjustment also reflects the proper level of deferred tax expense for the
test period, all based upon a Federal tax rate of 35%. The effect of this adjustment
increases current FIT expense by $44,000, and decreases deferred tax expense by
$44,000, resulting in a net $0 change to Washington net operating income.
The adjustment in column (2.07), Office Space Charges to Subs, removes a
portion of the office space costs (including, but not limited to office building operating
and fixed costs, utilities, administrative, security, HVAC, depreciation and property taxes,
as well as other costs related to employee use of phones, laptops, etc.) using the
relationship of labor hours charged to subsidiary/non-utility activities by employee
compared to total labor hours by employee. These percentages are applied to the
employees’ office space (expressed in square feet) and multiplied by office space
costs/per square foot. This restating adjustment is made as a result of the Commission's
Third Supplemental Order in Docket No. U-88-2380-T and consistent with previous
ICNU_DR_035 Attachment A Page 70 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 70
Docket Nos. UE-14_______ & UG-14_______
Company general rate cases. The effect of this adjustment is to increase Washington net
operating income by $5,000.
The adjustment in column (2.08), Restate Excise Taxes, removes the effect of a
one-month lag between collection and payment of taxes. The effect of this adjustment is
a net $0 impact to Washington net operating income.
The adjustment in column (2.09), Net Gains/Losses, reflects a ten-year
amortization of net gains realized from the sale of real property disposed of between 2003
and 2013. This restating adjustment is made as a result of the Commission's Order in
Docket No. UG-050483 and consistent with previous Company general rate cases. The
effect of this adjustment is to increase Washington net operating income by $1,000.
The adjustment in column (2.10), entitled 2013 Revenue Normalization & Gas 11
Cost Adjustment, is an adjustment taking into account known and measurable changes
that include revenue normalization (including the 2013 authorized rates approved in
Docket No. UG-120437), which reprices customer usage for 2013 increased rates, as well
as weather normalization and an unbilled revenue calculation. Associated natural gas
costs are replaced with natural gas costs computed using normalized volumes at the
currently effective “weighted average cost of gas,” or WACOG rates. Revenues 17
associated with the temporary Gas Rate Adjustment Schedule 155 and Schedule 191
Tariff Rider are excluded from pro forma revenues, and the related amortization expense
is eliminated as well.37 Company witness Mr. Miller is sponsoring this adjustment. The

37 The impact of this adjustment is also included in the Company’s natural gas Attrition Study. See column
[D], page 4 of Exhibit No. __(EMA-3).
ICNU_DR_035 Attachment A Page 71 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 71
Docket Nos. UE-14_______ & UG-14_______
effect of this particular adjustment is to increase Washington net operating income by
$2,395,000.
Q. Please turn to page 7 and explain the adjustments shown there.
A. The first adjustment on page 7 in column (2.11), Restate Atmospheric 4
Testing, adjusts the test period expense for Atmospheric Corrosion expense. This is an
inspection program to find conditions in the Company’s system that could lead to 6
corrosion issues on customer meter sets. This program is a federally-mandated program
that requires the Company to inspect all above ground steel pipe at a frequency not to
exceed three-years. This expense is on a three-year rotation between the Company’s 9
jurisdictions (Washington, Idaho, and Oregon) and is therefore, coded directly to
Washington operations for the year in which the inspection occurs.
The atmospheric testing for 2012, which occurred in Washington at a cost of
approximately $715,000, was directly charged to Washington and included in test period
results in this case. For 2015 the atmospheric testing inspection program will occur in
Washington at an estimated cost of approximately $789,000. Therefore, this adjustment
includes 1/3 or $163,000 of the 2015 level of expense for Washington’s natural gas
operations (resulting in a reduction to test period results).
To be consistent in all three of Avista’s natural gas jurisdictions, the Company has
included a three-year amortization for each of its jurisdictional (WA, ID, OR) general rate
case filings. This method is consistent with the approach used in the Company’s past two 20
WA GRC filings, Docket Nos. UG-110877 and UG-120437. The Company has received
approval of this accounting treatment in its Oregon jurisdiction. However, due to the
ICNU_DR_035 Attachment A Page 72 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 72
Docket Nos. UE-14_______ & UG-14_______
black-box nature of the settlements approved in both Avista’s Washington and Idaho
jurisdictions in the previous 2011 and 2012 rate cases, the Company is requesting this
treatment again in this filing, and in the Company’s next Idaho general rate case as well, 3
so the Company remains whole on an annual basis. This adjustment increases
Washington net operating income by $294,000.
The adjustment in column (2.12), Miscellaneous Restating Adjustments,
removes a number of non-operating or non-utility expenses associated with dues and
donations, etc., included in error in the test period actual results, and removes or restates
other expenses incorrectly charged between service and or jurisdiction totaling
approximately $21,000. The Company also removed 50% of director meeting expenses,
as ordered in Docket No. UE-090135, and restates director fee expenses to reflect a 90%
Utility / 10% non-utility split, totaling approximately $5,000. The total effect of this
adjustment is to increase Washington net operating income by $17,000.
The adjustment in column (2.13), Restating Incentive Adjustment, restates
actual incentives included in the Company’s test period ending June 30, 2013, reducing 15
overall expense by approximately $860,000. As explained further in the Electric Pro
Forma Section above, this reduction in incentive expense is, in part, due to a change in
Company policy regarding incentive allocation between Capital and O&M, and reduced
to reflect a six-year average of payout percentages. The effect of this adjustment increases
Washington net operating income by $559,000.
The adjustment in column (2.14), Restate Debt Interest, restates debt interest
using the Company’s pro forma weighted average cost of debt, as outlined in the 22
ICNU_DR_035 Attachment A Page 73 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 73
Docket Nos. UE-14_______ & UG-14_______
testimony and exhibits of Mr. Thies, on the Results of Operations level of rate base
shown in column (1.00) only, resulting in a revised level of tax deductible interest
expense on actual test period rate base. The Federal income tax effect of the restated
level of interest for the test period decreases Washington net operating income by
$211,000.
The Federal income tax effect of the restated level of interest on all other rate base
adjustments included in the Company’s filing are included and shown in each individual 7
rate base adjustment described elsewhere in this testimony.
The last restating adjustment shown on page 7 is included in column (2.15),
Restating June 30, 2013 Capital EOP. This adjustment restates plant additions
included in the test year on a June 30, 2013 AMA basis to an end of period basis, together
with the associated accumulated depreciation and deferred federal income taxes at a June
30, 2013 end of period basis, as described further by Mr. DeFelice. This adjustment also
includes the annual level of associated depreciation expense on all plant-in-service at June
30, 2013.38 The effect of this adjustment on Washington net operating income is a
decrease of $628,000. The effect on Washington rate base is an increase of $4,955,000.
The last column on page 7, entitled Restated Total, subtotals all the preceding
columns (1.00) through column (2.15). These totals represent actual operating results and
rate base plus the standard normalizing adjustments that the Company includes in its
annual Commission Basis reports. However, the Restated Total column does not

38 The impact of this adjustment is also included in the Company’s natural gas Attrition Study. See column
[C], page 4 of Exhibit No. __(EMA-3).
ICNU_DR_035 Attachment A Page 74 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 74
Docket Nos. UE-14_______ & UG-14_______
represent June 30, 2013 test period results of operation on a normalized commission
basis. Differences between certain restating adjustments included in normalized
Commission Basis Reports (CBRs) versus those included here, include but not limited to,
inclusion of 2013 annualized revenues (described in adjustment 2.10 Revenue
Normalization & Gas Cost Adjustment above); inclusion of debt interest restated based
on the Company’s proposed weighted cost of debt (described in adjustment 2.14 Restate 6
Debt Interest above) and inclusion of net plant investment on an end-of-period basis
(described in adjustment 2.15 Restating June 30, 2013 Capital EOP above).39 Each of the
adjustments noted above have been included consistent with past general rate case filings
by the Company. For Commission Basis Report results of operations for test period
ending June 30, 2013 (resulting in a 5.79% rate of return), please see Exhibit No.
__(EMA-3), page 5, line 48.
Pro Forma Adjustments 13
Q. Please explain each of the pro forma adjustments shown on page 8. 14
A. The adjustment in column (3.00), Pro Forma Labor-Non-Exec, reflects
known and measurable changes to test period union and non-union wages and salaries,
excluding executive salaries, which are handled separately in adjustment (3.01) (as
explained in the Electric Pro Forma Section above.) The methodology behind this
adjustment is consistent with that used in the Company’s previous Docket No. UE-

39 The restated total also includes additional restatements, such as inclusion of a natural gas working capital
adjustment (including a proposed change to include pension related regulatory assets and liabilities), and
reductions to incentive expense recognizing portions capitalized starting 1/1/2013 and to reflect a 6-year
average pay-out percentage for the level of expense included.
ICNU_DR_035 Attachment A Page 75 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 75
Docket Nos. UE-14_______ & UG-14_______
120437. The effect of this adjustment on Washington net operating income is a decrease
of $304,000.
The adjustment in column (3.01), Pro Forma Labor-Executive, reflects known
and measurable changes to reflect an annualized 2013 level of allocated executive officer
salaries. However, the Company has included utility and non-utility allocation
percentages planned for 2015. No additional increases in executive labor for 2014 or 2015
planned expenses have been included in this filing. This adjustment is further explained
in the Electric Pro Forma Section above. The effect of this adjustment on Washington net
operating income is a slight increase of $5,000. It otherwise contains no increase in
executive officer base pay.
The adjustment in column (3.02), Pro Forma Employee Benefits, adjusts for a
net reduction in Company pension and medical insurance expense (as explained in the
Electric Pro Forma Section above) and increases Washington net operating income by
$156,000.
The adjustment in Column (3.03), Pro Forma Insurance, adjusts actual test
period insurance expense related to the Utility for general liability, D&O liability, and
property to reflect the expected 2015 level of insurance, resulting in an increase in
expense of $149,00040 (as explained in the Electric Pro Forma Section above). This
adjustment decreases Washington net operating income by $97,000.
The adjustment in column (3.04), Pro Forma Property Tax, restates the 2013

40 The increase in insurance expense noted above is net of the offset to reduce D&O insurance expense for
the 10% portion removed.
ICNU_DR_035 Attachment A Page 76 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 76
Docket Nos. UE-14_______ & UG-14_______
level of property tax expense (previously discussed in the natural gas restating adjustment
section above, see Adjustment (2.02) Restate 2013 Property tax), to the 2015 level of
expense. (For further explanation of the pro forma adjustment, see (3.06) Pro Forma
Property Tax adjustment in the Electric Pro Forma Section above.) As can be seen from
my workpapers provided with the Company’s filing, the property on which the tax is 5
calculated is the property value as of December 31, 2014, reflecting the 2015 level of
expense the Company will experience during the rate period. The effect of this particular
adjustment is to decrease Washington net operating income by $240,000.
The last pro forma adjustment on page 8, includes the adjustment in column
(3.05), Pro Forma Information Technology/Services Expense, which includes the
incremental costs associated with software development, application licenses,
maintenance fees, and technical support for a range of information services programs.
Mr. Kensok discusses these incremental expenditures in more detail within his testimony.
The effect of this adjustment decreases Washington net operating income by $186,000.
Q. Turning to page 9 of Exhibit No. __(EMA-5), what is shown in the 15
first column on that page? 16
A. The first column on page 9, labeled Pro Forma Sub-Total, reflects total pro
forma results of operations and rate base consisting of test period actual results (twelve-
months ending June 30, 2013) and the restating and pro forma adjustments explained thus
far.
Q. Please briefly explain each of the adjustments included on page 9 of 21
ICNU_DR_035 Attachment A Page 77 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 77
Docket Nos. UE-14_______ & UG-14_______
Exhibit No. __(EMA-5). 1
A. The first adjustment included in column (4.00), Planned Capital 2
Additions December 2013 EOP, reflects the additional July through December 2013
capital additions41 together with the associated accumulated depreciation (A/D) and
accumulated deferred federal income taxes (ADFIT) at a December 2013 EOP basis.
This adjustment also includes associated depreciation expense for these July through
December 2013 additions. In addition, the plant-in-service at June 30, 2013 end-of-
period, was adjusted to a December 31, 2013 EOP basis. Mr. DeFelice describes this
adjustment in detail within his testimony. The effect of this component decreases
Washington net operating income by $652,000 and increases rate base by $11,295,000. 10
The next adjustment included in column (4.01), Planned Capital Additions 2014 11
EOP, reflects the additional 2014 capital additions42 together with the associated A/D and
ADFIT at a December 31, 2014 EOP basis. This adjustment also includes associated
depreciation expense for these 2014 additions. In addition, the plant-in-service at
December 31, 2013 end-of-period was adjusted to a December 2014 EOP basis. Mr.
DeFelice describes this adjustment in detail within his testimony. The effect of this
component decreases Washington net operating income by $942,000 and increases rate
base by $15,436,000. 18

41 For each of the periods July-December 2013, 2014, and 2015, distribution-related capital expenditures
associated with connecting new customers to the Company’s system was excluded. The Pro Forma Cross
Check Analysis does not include the increase in revenues from growth in the number of customers from the
historical test year to the 2015 rate year and therefore, the growth in plant investment associated with
customer growth was also excluded.
42 Id.
ICNU_DR_035 Attachment A Page 78 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 78
Docket Nos. UE-14_______ & UG-14_______
Column (4.02), Planned Capital Additions 2015 AMA, reflects all 2015 capital
additions43 together with the associated A/D and ADFIT at a 2015 AMA basis. This
adjustment includes associated depreciation expense for the 2015 additions. In addition,
the plant-in-service at December 31, 2014 was adjusted to a December 31, 2015 AMA
basis. Mr. DeFelice also describes this adjustment in detail within his testimony. The
effect of this component decreases Washington net operating income by $430,000 and
increases rate base by $3,352,000.
As previously discussed, the last column on page 9, labeled “Pro Forma Cross 8
Check Total,” reflects the total natural gas revenue requirement for 2015 of $13,935,000 9
based on the use of restating and pro forma adjustments from the historical test year to the
2015 rate year. This revenue requirement can be compared or “cross checked” to the 11
revenue requirement determined using the Attrition Study of $13,506,000, shown at the
bottom of the second column on page 10 of Exhibit No. __(EMA-4).
Q. Please describe the individual adjustments shown on page 10. 14
A. The first column on page 10, labeled (4.03), Reconcile Pro Forma To 15
Attrition, represents the difference of ($429,000 revenue requirement) between the Pro
Forma Cross Check Study and the Attrition Study. This adjustment records the increase
in expense of $614,000, decreasing Washington net operating income by $494,000, and
the reduction to net rate base of $9,867,000 necessary to equate with the total level of
attrition deficiency as determined by the Company’s Attrition Study.

43 Id.
ICNU_DR_035 Attachment A Page 79 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 79
Docket Nos. UE-14_______ & UG-14_______
The next adjustment in column (4.04) is O&M Offsets. As explained by Mr.
DeFelice, all of the 2013 (July through December), 2014 and 2015 capital additions were
reviewed for any O&M offsets that were expected in the 2015 rate period. Specific
offsets identified were included as a reduction to O&M costs in both the Attrition and Pro
Forma Studies, and discussed in Mr. DeFelice’s direct testimony with the capital asset
with which the offset relates.44 The effect of this adjustment on Washington net operating
income is an increase of $8,000. 7
The final pro forma adjustment included in column (4.05) Revenue 8
Normalization 2014, includes revenue repricing of the 2014 authorized rates approved 9
on a temporary basis in Docket No. UE-120437). Mr. Miller is sponsoring this
adjustment. The effect of this adjustment increases Washington net operating income by
$843,000.
Q. Please summarize the purpose of the natural gas Pro Forma Cross 13
Check Study. 14
A. The Company’s natural gas rate relief for 2015 requested in this case is
based on the Company’s natural gas Attrition Study results. The purpose of the natural 16
gas Pro Forma Cross Check Study is to provide a “cross check” to the reasonableness of 17
the natural gas Attrition Study as discussed previously in Section III. Attrition Studies.
Furthermore, the Pro Forma Cross Check revenue requirement is reconciled to the
Attrition Study revenue requirement in order to establish revenue, expenses and rate base

44 As noted within the Attrition Study discussion, upon further review of the Company’s filing, the Company
realized that the O&M Offset adjustment should have been included as a Pro Forma Cross Check Study
adjustment only, and not included as an offset to the Attrition adjusted total.
ICNU_DR_035 Attachment A Page 80 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 80
Docket Nos. UE-14_______ & UG-14_______
numbers that can be used as inputs to the Company’s cost of service study prepared by
Mr. Miller. 2
V. 2016 INFORMATION 3
Q. Throughout this testimony you discuss and support the need for rate 4
relief in 2015, determined through the Company’s electric and natural gas Attrition 5
Studies, and “cross checked” with the Company’s electric and natural gas Pro 6
Forma Studies. Do you expect a continued increase in operating expenses and net 7
plant investment, and the need for additional rate relief beyond the 2015 level of 8
costs requested in this filing? 9
A. Yes, I do. The following discussion related to 2016 incremental revenue
requirement is based on extending the Company’s electric and natural gas Attrition
Studies an additional year to 2016. This additional discussion is included here for
informational purposes only, and has not been included in the Company’s request for rate 13
relief. Supporting workpapers for 2016 based on the Company’s electric and natural gas 14
Attrition Study analysis, as well as pro forma adjustment workpapers providing a “cross 15
check” to the Attrition Study analysis, also accompany the Company’s filed case.
Q. Please explain the results of the Company’s electric and natural gas 17
Attrition Study analysis for the period 2016. 18
A. The results of the electric and natural gas Attrition Study analysis for 2016
builds on the Attrition Study analysis completed and previously described earlier in my
testimony in Section III. Attrition Studies, for the period 2015. The Company used the
same compound growth rates (period 2007-2012) as previously described in Section III.
ICNU_DR_035 Attachment A Page 81 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 81
Docket Nos. UE-14_______ & UG-14_______
Attrition Studies for 2015, adjusted for 2016 pro forma power supply, and updated
revenues to include 2016 expected revenues. The results for the 2016 rate year show a
need for revenue increases of $20,158,000 million for electric (or 4.04%), and $3,647,000
million for natural gas (or 2.25%). (See column (h) of Exhibit No. __(EMA-6), pages 1
and 9, respectively.)45
As a “cross check” on the reasonableness of the calculated revenue need based on
the electric and natural gas 2016 Attrition Study analysis, the Company also looked at
additional expenditures planned for the Utility in 2016. For this “cross check” the 8
Company reviewed incremental increases in major cost categories, such as new plant
investment, expected increases in net power supply and labor costs, and the impact of
DSM on 2016 revenues.
For example, as mentioned in Mr. Thies’ testimony, Avista’s plans call for 12
significant capital expenditure requirements of approximately $1.7 billion on a system
basis over the next five year period ending December 31, 2018. For the 2015 rate relief
requested, Washington net plant balances include changes in net rate base through
December 2015 on an AMA basis. As described earlier in my testimony, net plant
investment represents the main driver of the 2015 rate relief requested in this case over
that currently in base rates. With the continued level of capital spend in net plant
investment planned on a go-forward basis, net plant investment is expected to continue to

45 The total 2016 electric and natural gas Attrition Study amounts were $52,698,000 electric and
$17,153,000 for natural gas, shown on page 3 and 11, respectively, of Exhibit No. __(EMA-6). After
reflecting the “After Attrition Adjustments,” the 2014 Temporary Rate Increase, and 2015 Revenue
Requirement amounts requested in this filing and previously discussed, the remaining balance is the
incremental 2016 rate relief necessary to earn the 7.71% ROR proposed in this filing.
ICNU_DR_035 Attachment A Page 82 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 82
Docket Nos. UE-14_______ & UG-14_______
be the driver in the 2016 rate period. The incremental revenue needed in 2016 related
solely to these capital additions is approximately $15.2 million electric and $3.05 million
for natural gas. (See Mr. DeFelice testimony and exhibits for information related to the
016 capital additions.)
Q. Please discuss the 2016 incremental expenses reviewed to determine 5
the 2016 pro forma revenue short-fall used as a “cross check” to the Attrition Study 6
balances noted above. 7
The Company included increases in salaries above that included in the 2015 rate
year, based on a conservative 2.5% adjustment for increases expected as of March 1,
2016. The impact of this adjustment is an incremental increase in 2016 expense of
approximately $1.0 million electric and $0.3 million natural gas.
Additionally, for electric only, the Company also examined the pro forma power
supply net expenses for 2016 and the impact of DSM on 2016 revenues. The impact of
these adjustments is an incremental increase in 2016 expense of approximately $0.7
million related to increased power supply net expense and $1.9 million related to the
impact of DSM.
Prior to consideration of any other incremental expenses the Company will
experience in 2016, the net of the cost categories discussed above, result in a 2016
incremental revenue need of approximately $18.8 million electric and $3.3 million natural
gas. A table summarizing the Attrition Study revenue requirement versus the Pro Forma
Cross Check using specific cost categories identified above is provided in Table No. 1
below.
ICNU_DR_035 Attachment A Page 83 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 83
Docket Nos. UE-14_______ & UG-14_______
Table No. 1 1
2
3
4
5
6
7
8
9
10
11
VI. COMPLIANCE WITH PAST COMMISSION ORDERS 12
Tracking of Washington General Rate Case Expenses 13
Q. Order No. 6, in Docket Nos. UE-110876 and UG-110877, required 14
Avista to begin tracking its Washington general rate case expenses beginning in 15
2012. Has the Company fulfilled these requirements? 16
A. Yes. Effective January 1, 2012, Avista agreed to begin separately
accounting for all internal and external costs related to preparation, filing, and litigation of
Washington general rate cases (GRCs), including but not limited to internal labor costs,
administrative and production costs, and costs of outside services.
Costs associated with internal and external costs related to preparation and filing
of the Washington electric and natural gas rate cases filed in 2012 totaled $1.54 million,
Electric Natural Gas
2016 Attrition Study Adjusted Balances 52,698$ 17,153$
Reduced For:
After Attrition Adjustments (287) (13)
2014 Temporary Rate Increase (14,054) (1,358)
2015 Revenue Requirement Requested Per Filing (18,201) (12,135)
2016 Incremental Revenue Requirement - Per Attrition 20,158$ 3,647$
2016 Pro Forma Cross Check Balances
Incremental Pro Forma Adjsutments:
Pro Forma 2016 Capital (AMA Basis)15,183$ 3,045$
Pro Forma 2016 Non-Union Wage Increase 999$ 276$
Pro Forma 2016 Power Supply 723$ -$
2016 DSM 1,870$ -$
18,775$ 3,321$
2016 ATTRITION VERSUS 2016 PRO FORMA COSS CHECK
REVENUE REQUIREMENT SUMMARY
2016 Incremental Revenue Requirement - Per
Pro Forma Cross Check Adjustments Examined
ICNU_DR_035 Attachment A Page 84 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 84
Docket Nos. UE-14_______ & UG-14_______
comprising of approximately $1.28 million of internal labor and benefit costs, $223,000
in outside consulting costs46, and $38,000 for all other costs, such as travel, administrative
and production costs. Washington’s electric share of these costs totaled approximately
$1.2 million, whereas Washington natural gas totaled $340,000.
Electric and natural gas GRC related costs included in the Company’s test period 5
(July 1, 2012 through June 30, 2013) and included in this filing, total approximately
$500,000 for electric and $155,000 for natural gas. No additional GRC costs were pro
formed in this case.
Internal Audit of Avista Utility Expenditures 9
Q. Order No. 7, approving the Settlement Stipulation in Docket Nos. UE-10
100467 and UG-100468, required Avista to perform an internal audit of its 11
accounting practices. Has the Company fulfilled these requirements? 12
A. Yes. The Settlement Stipulation approved by the Commission in Docket
Nos. UE-100467 and UE-100468 ordered Avista to perform an annual internal audit for
accounting practices in each of the three years following the issuance of that Final Order
dated November 19, 2010 (equivalent to the calendar years 2010 through 2013), and to
provide a report regarding the results of such audit. In addition to the results of its annual
audits, the Company is to provide all internal and external costs associated with
performing the audits and preparing the reports. 47

46 Approximately $165,000 of the total $223,000 of outside service costs related to the Washington Electric
Attrition Study included in the Company’s 2012 GRC, Docket No. UE-120436. The remaining outside
service costs (or $58,000) related to the Company’s Cost of Capital consulting witness Dr. Avera. 47Order No. 6, in Docket Nos. UE-110876 and UG-110877 reiterated these requirements at page 12,
Paragraph 15.
ICNU_DR_035 Attachment A Page 85 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 85
Docket Nos. UE-14_______ & UG-14_______
The Company has completed such audits for the periods 2010 through 2012, with
each of these reports provided to all parties.48 The Company provided a copy of its last
report, the 2012 Accounting Practices Audit, to all parties on May 20, 2013. The cost of
the 2012 audit was approximately $49,000 in internal labor and benefit costs. The 2013
Accounting Practices Audit report is scheduled to be complete in May 2014, at which
time the report and the costs will be provided to all parties.
Tracking of Aldyl-A Natural Gas Pipeline Replacement Program Projects 7
Q. Order No. 9, approving the Settlement Stipulation in Docket Nos. UE-8
120436 and UG-120437, required Avista to begin tracking separately, on January 1, 9
2013, all projects associated with its Aldyl-A natural gas pipeline replacement 10
program. Has the Company fulfilled these requirements? 11
A. Yes. Beginning January 1, 2013 the Company began tracking through
separate projects its Aldyl-A natural gas pipeline replacement program projects and will
make this information available upon request to the Commission.
Cost Assignment & Allocation Methodologies 15
Q. Order No. 9, approving the Settlement Stipulation in Docket Nos. UE-16
120436 and UG-120437, required Avista to provide additional information 17
regarding its cost49 assignment and allocation methodologies in its next general rate18

48 The Company provided its 2010 Accounting Practices Audit report and costs within its 2011 GRC filing
in Docket Nos. UE-110876 and UG-110877. (See Exhibits Nos. __(EMA-1T) and __(EMA-5).) The
Company provided its 2011 Accounting Practices Audit report and costs within its 2012 GRC filing in
Docket Nos. UE-120436 and UG-120437. (See Exhibits Nos. __(EMA-1T) and __(EMA-4).)
49 The Company records revenues, expenses and net plant investment in common accounts that must be
allocated to services and jurisdictions. The same allocation process and methodologies are used for all of
these accounts. The Company will refer to these revenues, expenses and net plant investment as “costs”
throughout this document.
ICNU_DR_035 Attachment A Page 86 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 86
Docket Nos. UE-14_______ & UG-14_______
case. Has the Company fulfilled these requirements? 1
A. Yes. In Paragraph 17 of the Multiparty Settlement Stipulation in Dockets
UE-120436 and UG-120437, the settling parties agreed that Avista, in its next general rate
case, would provide justification for the service and jurisdictional cost allocation
methodologies that it employs. The Company met with several members of the WUTC
Staff on December 2, 2013, to provide an overview of Avista’s operations and accounting 6
practices, including an overview of its allocation processes and methodologies. The
allocation presentation used by the Company at this meeting is provided as Exhibit No.
___ (EMA-7). The testimony that follows describes Avista’s cost allocation procedures 9
and why we believe the method used by Avista produces a reasonable allocation of costs.
Q. Would you please describe the utility services provided by the 11
Company and identify the jurisdictions within which the utility services are 12
provided? 13
A. Yes. The Company provides electric service in two retail jurisdictions50:
Washington (WA) and Idaho (ID), and natural gas service in three retail jurisdictions:
Washington, Idaho and Oregon (OR).
Retail natural gas service provided in eastern Washington and northern Idaho is
accounted for separately as the WA/ID natural gas service, or as the North natural gas
service. Natural gas service in central and southwest Oregon and is accounted for
separately as our Oregon jurisdiction, or the South natural gas service.
Q. How does the Company assign costs by service and jurisdiction? 21

50 Avista serves approximately 25 retail electric customers in Montana.
ICNU_DR_035 Attachment A Page 87 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 87
Docket Nos. UE-14_______ & UG-14_______
A. Whenever possible, the Company directly assigns its revenues, operating
costs and net plant investment to services and jurisdictions. For costs not directly
assigned, the Company uses an allocation process using allocation factors that are derived
from directly assigned costs which are updated annually. The costs that are not directly
assigned are referred to as “common” costs.
For example, Avista’s main headquarters in Spokane supports all services and
jurisdictions, therefore the operating costs, depreciation expense and net book value of the
building is allocated to all services and jurisdictions using allocation factors.
Q. Please explain how the Company accounts for these “common” costs 9
that must be allocated. 10
A. The Company uses service codes (electric, natural gas and common) and
jurisdiction codes (state and common) on all accounting transactions to indicate where
costs should be recorded (either directly assigned or where a common cost should be
allocated). Both service codes and jurisdiction codes consist of two-digit alpha codes,
described further below. The assignments and allocations are used for internal, financial
and regulatory reporting and for ratemaking purposes.
Q. Are costs also allocated to non-utility operations or subsidiary 17
companies of Avista Corp.? 18
A. Instead of being allocated, certain costs are directly assigned to non-utility
operations or subsidiaries. Avista Utilities is the regulated operating division of Avista
Corp. A current organization chart for Avista Corp. is provided in Illustration No. 3
below.
ICNU_DR_035 Attachment A Page 88 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 88
Docket Nos. UE-14_______ & UG-14_______
Regulated Non-Regulated
Other
Avista
Corporation
d/b/a
Avista Utilities Avista Capital
Ecova
Illustration No. 3 1

Certain officers and general office employees of Avista spend time on corporate
service support, such as accounting, federal income tax filing, planning, or incur costs for
supplies, postage, legal, graphic services, etc. for subsidiaries. Their time and costs are
directly charged to suspense accounts and then billed to the subsidiary or directly charged
to non-utility FERC accounts. Therefore, there is no need to allocate costs to subsidiaries
or non-utility accounts as part of the allocation procedures described below, because they
are all directly assigned.
An example of the Company’s process for recording subsidiary-related costs is
provided in Table No. 2 below.

ICNU_DR_035 Attachment A Page 89 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 89
Docket Nos. UE-14_______ & UG-14_______
Table No. 2 1

11
12
13
14
15

Table No. 2 shows that a total of $1.53 million of directors’ fees was paid during
the twelve months ended June 30, 2013. Of this amount, $44,000 was direct charged to
either a subsidiary receivable or to a non-utility FERC account related to Ecova’s Board 19
of Director fees. In addition, of the $1.53 million of Avista Corp. Board of Director Fees,
$148,000 was directly charged to a non-utility FERC account related to subsidiary
Total Directors' Fees 1,531$
Less: Subsidiary Directors' Fees Charged to FERC 417/186 44
Avista Corp. Directors' Fees 1,488
Less: 10% Charged to Non-utility (FERC 417)148
Utility Directors' Fees - System 1,340$
Allocation of Utility Directors' Fees by Service Using Factor 7:
Electric 72.346%969$
Natural Gas North 19.401%260
Natural Gas South (Oregon)8.253%111
Total 100.000% 1,340$
Allocation of ELECTRIC Utility Directors' Fees by Jurisdiction Using Factor 4:
Washington Electric 67.000%649$
Idaho Electric 33.000%320
Total 100.000%969$
Allocation of NATURAL GAS NORTH Utility Directors' Fees by Jurisdiction Using Factor 4:
Washington Natural Gas 70.603%184$
Idaho Natural Gas 29.397%76
Total 100.000%260$
Detail of Directors' Fees
($000's)
For Twelve Months Ended June 30, 2013
ICNU_DR_035 Attachment A Page 90 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 90
Docket Nos. UE-14_______ & UG-14_______
operations.51 The remaining $1.34 million that was charged to the utility is allocated by
service and jurisdiction.
Q. Do you believe the allocation methodology used today by the 3
Company is appropriate for allocating common costs? 4
A. Yes, I do. When the Company designed the allocation methodology that is
being used today, the specific objectives identified were as follows:
a) The method must be acceptable to all regulators to prevent any stranded
costs or investment,

b) The number of cost allocation methods should be minimized,
c) The method needs to be simple,
d) The method needs to have a sound, rational basis,
e) Allocations under the method should be automated, and
f) The method needs to produce reasonable results.
These objectives are still relevant today. The Company believes the methodology
continues to meet these over-all objectives.
The over-all goal the Company was trying to accomplish as it designed its
allocation methodology was to produce a reasonable method to allocate common costs
and common plant by service and jurisdiction. The method ultimately proposed by Avista
and approved by the state Commissions (Washington, Idaho, and Oregon) produced a
reasonable allocation of common costs. 21

51 The Company regularly surveys each member of its Avista Corp Board of Directors to determine how
much of each member’s time while serving on the Board is devoted to activities not directly related to the
operations of the Utility itself, so that costs may be appropriately assigned to utility and non-utility
operations. Current Board of Directors survey results show a 90% assignment to utility, and 10% to non-
utility.
ICNU_DR_035 Attachment A Page 91 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 91
Docket Nos. UE-14_______ & UG-14_______
Q. Please explain when the Company began using the current 1
methodology. 2
A. The current method used for electric generation and transmission expenses
and net plant investment was reviewed and supported by the Washington and Idaho
Commission staffs in 1984. This methodology uses the production/transmission ratio for
electric expense FERC Accounts 500 through 573, which is described further below.
The current method for all other expenses (expense FERC Accounts 580 through
935) and net plant investment (i.e. excluding electric generation and transmission
expenses and net plant investment), was developed and presented to the Commission
staffs of Washington, Idaho and Oregon utility commissions for approval in 1993. The
Company obtained approval letters from each jurisdiction and implemented the new
utility codes and allocation methodology in 1994. This allocation methodology and the
actual allocation of common costs using the factors computed using that methodology,
have been provided in each general rate case filed by the Company in each of its
jurisdictions since the method was implemented.
Q. When did the Company begin using the current service and 16
jurisdiction codes? 17
A. The Company converted to the Oracle Financial System on January 1,
2005. With the implementation of the Oracle Financial System, the two-digit alpha codes
for service and jurisdiction were adopted. The allocation methodology did not change
with the implementation of the Oracle Financial System, but only the account code
labeling was changed.
ICNU_DR_035 Attachment A Page 92 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 92
Docket Nos. UE-14_______ & UG-14_______
Q. Would you please identify the service codes that are used? 1
A. Yes. The Company uses the following service codes:
ED – Electric Direct
GD – Gas Direct
CD – Common Direct
ZZ – No Service (Used for balance sheet accounts (FERC Accounts 100-
399) that are not assigned to a service (i.e. cash, accounts payable, etc.)
and non-utility accounts)

Q. Would you please identify the jurisdiction codes that are used? 10
A. Yes. The Company uses the following jurisdiction codes:
AA – Allocated All
AN – Allocated North
ID – Idaho
MT – Montana
OR – Oregon
WA – Washington
ZZ – No Jurisdiction (Used for balance sheet accounts (FERC Accounts
100-399) that are not assigned to a jurisdiction (i.e. cash, accounts
payable, etc.) and non-utility accounts)

Q. Would you please summarize the assignment and utility 22
code/allocation method currently in use for costs? 23
A. Yes. To begin with, revenues, operating costs and plant are directly
assigned to services and jurisdictions whenever possible.
As explained earlier, for those costs not directly assigned, the costs are allocated
using a variety of allocation factors. The Company annually computes the allocation
factors using actual direct costs and other data points (i.e. customer counts, customer
usage, etc.). Updating the factors with current data on an annual basis is appropriate so
that growth in each jurisdiction is factored into the current year allocation. When the
ICNU_DR_035 Attachment A Page 93 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 93
Docket Nos. UE-14_______ & UG-14_______
factors are updated annually, the factors are reviewed to identify any unusual trends or
unexpected shifts in costs.
Q. Would you describe the various types of allocation factors used by the 3
Company? 4
A. Yes. The Company uses primarily three different types of allocation
factors, including:
a) Allocation factors that are used to allocate common costs and are
comprised of an equal weighting of four factors, and are therefore called
“4-factors”. The four factors are (1) direct O&M and A&G costs,
excluding labor and resource costs, (2) direct O&M and A&G labor, (3)
number of customers, and (4) net direct plant.
b) Allocation factors that use one data point (i.e. customer count or directly
assigned distribution costs, etc.)
c) Allocation factors specific to electric costs or natural gas costs. These
factors are the Production/Transmission (P/T) ratio for electric service and
the System Contract Demand ratio for natural gas service, which are
described below. 17
Allocation Factors 18
Allocation of Electric Production and Transmission Costs and Plant 19
Q. Would you please summarize the P/T ratio computation that is 20
currently used to allocate electric generation and transmission costs and plant 21
between Washington and Idaho? 22
ICNU_DR_035 Attachment A Page 94 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 94
Docket Nos. UE-14_______ & UG-14_______
A. Yes. The Company annually computes an allocation factor, called the P/T
ratio (production/transmission ratio) using the previous year’s actual usage amounts for 2
retail customer demand and energy consumption. The kilowatt demand figures are the
coincident contributions of each jurisdiction to the Company’s monthly system peak 4
loads. The kilowatt-hour energy consumption represents the actual sales figures. Both
demand and energy use ratios are weighted equally in arriving at the allocation factor.
This is Factor 1 for electric service.
Allocation of Natural Gas Underground Storage Costs and Plant 8
Q. Would you please summarize the System Contract Demand ratio 9
computation that is currently used to allocate natural gas underground storage costs 10
and plant? 11
A. Yes. The Company annually computes the System Contract Demand
allocation factor (also known as the five-day peak factor) using the actual therm
throughput during the five consecutive days in the year with the highest throughput. The
actual throughput for Washington and Idaho for this five-day period is averaged over
three years, to determine the allocation of costs between Washington and Idaho. The
Company directly assigns the O&M costs (FERC Account Nos. 824 and 837) of its share
of the Jackson Prairie storage facility to Oregon and Natural Gas North Service, using the
proportionate share of capacity assigned to each. Therefore, no further allocation of these
costs to Oregon is required. This is Factor 1 for natural gas service.

ICNU_DR_035 Attachment A Page 95 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 95
Docket Nos. UE-14_______ & UG-14_______
Allocation of Common Costs 1
Q. Would you describe the allocation process used by the Company to 2
allocate common costs? 3
A. Yes. Illustration No. 4 below depicts the allocation of common costs.
Illustration No. 4 5

The allocation of common costs is a two-step process. The first step is to allocate
the common costs to one of the three services: Electric, Natural Gas North or Natural Gas
South.
Three different 4-factors are used to allocate the common costs to the three
services. These 4-factors are used to allocate all common costs recorded in all FERC
Accounts, except FERC Accounts 901-905 (Customer Accounts Expense), FERC
Accounts 906-910 (Customer Service and Information Expense), and FERC Accounts
911-917 (Sales Expenses). These costs in FERC Accounts 901 through 917 are heavily

ICNU_DR_035 Attachment A Page 96 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 96
Docket Nos. UE-14_______ & UG-14_______
influenced by the number of customers, and therefore, it is more appropriate to allocate
these common costs using the number of customers.
The three 4-factors that are used to allocated common costs to services follows:
Factor 7 (CD.AA) – Factor used to allocate common costs to all services,
including Electric, Natural Gas North and Natural Gas South. The 4-factor
is developed using the following data:
(1) Direct O&M and A&G costs, excluding labor and resource costs,
that are assigned to electric service, natural gas North service and
natural gas South service.
(2) Direct O&M and A&G labor that are assigned to electric service,
natural gas North service and natural gas South service.
(3) Number of customers for electric service, natural gas North service
and natural gas South service.
(4) Net direct plant that is assigned to electric service, natural gas
North service and natural gas South service.

Factor 8 (GD.AA) – Factor used to allocate common natural gas costs to
natural gas services, including Natural Gas North and Natural Gas South.
The 4-factor is developed using the following data:
(1) Direct O&M and A&G costs, excluding labor and resource costs,
that are assigned to natural gas North service and natural gas South
service.
(2) Direct O&M and A&G labor that are assigned to natural gas North
service and natural gas South service.
(3) Number of customers for natural gas North service and natural gas
South service.
(4) Net direct plant that is assigned to natural gas North service and
natural gas South service.

Factor 9 (CD.AN) – Factor used to allocate costs common in Washington
and Idaho to Electric service and Natural Gas North service. The 4-factor
is developed using the following data:
ICNU_DR_035 Attachment A Page 97 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 97
Docket Nos. UE-14_______ & UG-14_______
(1) Direct O&M and A&G costs, excluding labor and resource costs,
that are assigned to electric service and natural gas North service.
(2) Direct O&M and A&G labor that are assigned to electric service
and natural gas North service.
(3) Number of customers for electric service and natural gas North
service.
(4) Net direct plant that is assigned to electric service and natural gas
North service.

These factors at June 30, 2013, used in this filing, are shown in Table No. 3
below:
Table No. 3 12

The second step is to allocate the common operating costs for Electric and Natural
Gas North to the appropriate jurisdiction (Washington or Idaho).
These costs are allocated using the jurisdictional allocation factors, including:
P/T ratio (Electric Factor 1), which was described above.
System Contract Demand ratio (Natural Gas Factor 1), which was
described above.
Factor 2 (Number of Customers) – For both electric service and natural gas
North service, Washington and Idaho’s proportional share of total electric 25
customers and total natural gas North customers are used to assign certain
costs, as described below.
Factor Service Code Jurisdiction Code Electric Natural Gas North Natural Gas South
Factor 7 CD AA 72.346% 19.401%8.253%
Factor 8 GD AA 0.000% 70.320% 29.680%
Factor 9 CD AN/WA/ID 79.221% 20.779%0.000%
Customer Ratio of Factor 7 CD AA 52.888% 33.009% 14.103%
Customer Ratio of Factor 8 GD AA 0.000% 70.065% 29.935%
Customer Ratio of Factor 9 CD AN/WA/ID 61.572% 38.428%0.000%
Allocation Percentages
ICNU_DR_035 Attachment A Page 98 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 98
Docket Nos. UE-14_______ & UG-14_______
Factor 3 (Directly-Assigned Distribution Costs) - For both electric and
natural gas North service, Washington and Idaho’s proportional share of 2
total actual directly assigned distribution O&M expenses are used to assign
certain costs, as described below.
Factor 4 (Electric Common Costs) - Factor used to allocate common
electric service costs to Washington and Idaho. The 4-factor is developed
using the following data:
(1) Direct O&M and A&G costs, excluding labor and resource costs,
that are assigned to Washington and Idaho electric service.
(2) Direct O&M and A&G labor that are assigned to Washington and
Idaho electric.
(3) Number of customers for Washington and Idaho electric.
(4) Net direct plant that is assigned to Washington and Idaho electric
service.

Factor 4 (Natural Gas Common Costs) - Factor used to allocate common
natural gas North service costs to Washington and Idaho. The 4-factor is
developed using the following data:
(1) Direct O&M and A&G costs, excluding labor and resource costs,
that are assigned to Washington and Idaho natural gas North service.
(2) Direct O&M and A&G labor that are assigned to Washington and
Idaho natural gas North service.
(3) Number of customers for Washington and Idaho natural gas North
service.
(4) Net direct plant that is assigned to Washington and Idaho natural
gas North service.

Factor 10 (Natural Gas Actual Annual Throughput) – For natural gas
North service, Washington and Idaho’s proportional share of total actual
annual therm throughput are used to assign certain costs, as described
below.
ICNU_DR_035 Attachment A Page 99 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 99
Docket Nos. UE-14_______ & UG-14_______
1
These factors at June 30, 2013, used in this filing for both electric and natural gas
operations, are shown in Table No. 4 below:
Table No. 4 4

These allocation factors are applied in a jurisdictional allocation model outside of
the general ledger system. This model produces the monthly Results of Operations
reports. Washington’s Results of Operations reports as of June 30, 2013 have been
provided with my workpapers at Section 1.00 for both electric and natural gas.
Additional workpapers supporting the allocations described above are provided as
Andrews Workpapers (Part 3), both in hard copy and electronic formats.
Allocation Methodology 18
Q. Would you describe for electric service for each income statement and 19
rate base FERC account the allocation method that is used by the Company and a 20
brief explanation of how the use of that factor produces a reasonable allocation of 21
costs? 22
Factors
Electric:
PT Ratio (Electric Factor 1)ED AN 65.010% 34.990%
Customer Ratio (Factor 2)ED AN 65.618% 34.382%
Direct Distribution Costs (Factor 3)ED AN 66.932% 33.068%
Common Factor (Electric Factor 4)ED AN 67.000% 33.000%
Natural Gas:
System Contract Demand Ratio (Nat. Gas Factor 1)GD AN 69.990% 30.010%
Customer Ratio (Factor 2)GD AN 66.411% 33.589%
Direct Distribution Costs (Factor 3)GD AN 70.462% 29.538%
Common Factor (Nat. Gas Factor 4)GD AN 70.603% 29.397%
Actual Annual Throughput Ratio (Factor 10)GD AN 69.163% 30.837%
Allocation Percentages
Service
Code
Jurisdiction
Code Washington Idaho
ICNU_DR_035 Attachment A Page 100 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 100
Docket Nos. UE-14_______ & UG-14_______
A. Yes. For electric operations, Table No. 5 below summarizes the various
factors that are used for each FERC account.
Table No. 5: 3

Lines 1 through 7 – Customer revenues, generation O&M costs, power supply
costs and transmission O&M costs are directly assigned to electric service in the general
ledger. Revenues are primarily directly assigned to the states. The costs are either
directly assigned to Washington and Idaho or are allocated to Washington and Idaho
Line Description FERC Accounts
Allocation Method to
Electric/Natural Gas Allocation Method to State
Income Statement
1)Sales to Customers 440-446, 448, 499 Direct Assignment Direct Assignment
2)Other Sales, including Sales for Resale, Rent,
etc.
447, 451-456 Direct Assignment PT Ratio (Electric Factor 1)
3)Generation O&M - Steam Power 500-514 Direct Assignment PT Ratio (Electric Factor 1)
4)Generation O&M - Hydro 535-545 Direct Assignment PT Ratio (Electric Factor 1)
5)Generation O&M - Other Generation 546-554 Direct Assignment PT Ratio (Electric Factor 1)
6)Other Power Supply (i.e. Purchased Power) 555-557 Direct Assignment Direct Assignment or PT Ratio (Electric
Factor 1)
7)Transmission O&M 560-573 Direct Assignment PT Ratio (Electric Factor 1)
8)Distribution O&M 580-598 Direct Assignment Direct Assignment or Factor 3 (Directly-
Assigned Distribution Costs)
9)A&G - Customer Accounts Expenses 901-905 Customer Ratio of Factors 7, 8 &
9 (Common Factor)
Customer Ratio (Factor 2)
10)A&G - Customer Service and Info Expenses 908-910 Customer Ratio of Factors 7, 8 &
9 (Common Factor)
Customer Ratio (Factor 2)
11)A&G - Sales Expenses 912-916 Customer Ratio of Factors 7, 8 &
9 (Common Factor)
Customer Ratio (Factor 2)
12)A&G - Other Expenses 920-927, 930-935 Factors 7, 8 & 9 (Common
Factor)
Factor 4 (Common Factor)
13)A&G - Regulatory Expenses 928 Factors 7, 8 & 9 (Common
Factor)
PT Ratio (Electric Factor 1)
14)Depreciation and Amortization - Generation 403-404 Direct Assignment PT Ratio (Electric Factor 1)
15)Depreciation and Amortization - Transmission 403-404 Direct Assignment PT Ratio (Electric Factor 1)
16)Depreciation and Amortization - Distribution 403-404 Direct Assignment Direct Assignment
17)Depreciation and Amortization - General 403-404 Factors 7, 8 & 9 (Common
Factor)
Factor 4 (Common Factor)
18)Regulatory Amortizations 407 Direct Assignment Direct Assignment or PT Ratio (Electric
Factor 1)
Rate Base
19)Intangible Plant and A/D 101, 108-111 Direct Assignment and Factors
7, 8 & 9 (Common Factor)
PT Ratio (Electric Factor 1) or Factor 4
(Common Factor)
20)Generation Plant and A/D 101, 108-111 Direct Assignment PT Ratio (Electric Factor 1)
21)Transmission Plant and A/D 101, 108-111 Direct Assignment PT Ratio (Electric Factor 1)
22)Distribution Plant and A/D 101, 108-111 Direct Assignment Direct Assignment
23)General Plant and A/D 101, 108-111 Factors 7, 8 & 9 (Common
Factor)
Factor 4 (Common Factor)
24)Regulatory Deferred Assets and Liabilities 182, 186 Direct Assignment Direct Assignment
25)Working Capital ISWC Investor Supplied Allocation Investor Supplied Allocation
ICNU_DR_035 Attachment A Page 101 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 101
Docket Nos. UE-14_______ & UG-14_______
electric service using the P/T ratio. As discussed above, the P/T ratio is an equal
weighting of actual usage amounts for retail customer demand and energy consumption.
Since the P/T ratio is derived from actual sales data in each state, the use of the P/T ratio
to allocate these costs produces a matching of costs with the revenues.
Line 8 – Distribution costs are directly assigned in the general ledger to electric
service. The majority of costs are also directly assigned to Washington and Idaho. For
those costs not directly assigned, the Company allocates the common distribution costs
using the ratio of directly assigned distribution costs incurred in each state in comparison
to the total.
Lines 9 through 11 – Customer count is one component of the 4-factors. Rather
than using the over-all 4-factors (Factors 7, 8 and 9) to allocate the common costs to
electric service for common portions of FERC Accounts 901-905 (Customer Accounts
Expense), FERC Accounts 906-910 (Customer Service and Information Expense), and
FERC Accounts 911-917 (Sales Expenses), the Company uses the customer component
ratio of the 4-factors. These costs in these FERC accounts are heavily influenced by the
number of customers, and therefore, the ratio based on customers is more appropriate to
allocate the costs to electric and natural gas service than the over-all 4-factor. Using the
same reasoning, the Company uses Factor 2 (Customer Ratio) to allocate the common
electric costs to Washington and Idaho.
Line 12 - FERC Accounts 920-927 and 930-935 (Administrative and General)
include various A&G costs, including salaries, office supplies and expenses, outside
services, maintenance of common general plant, etc. The over-all 4-factor allocator s
ICNU_DR_035 Attachment A Page 102 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 102
Docket Nos. UE-14_______ & UG-14_______
(Factors 7, 8 and 9) are used to allocate the common costs to electric service and the over-
all 4-factor allocator (Factor 4) is used to allocate the common electric costs to
Washington and Idaho. These costs are not influenced by any one factor, so the use of the
over-all 4-factor that is equally weighted with customers, direct labor, other non-labor
O&M and A&G direct costs and net direct plant, produces a reasonable allocation of
common costs.
Line 13 – FERC Accounts 928 (Regulatory Commission expenses) include state
and FERC fees that are based on revenues, in addition to other A&G expenses of the
State and Federal Regulation department. The Company directly assigns the fees to
electric service. For the state commission fees, the Company directly assigns the fees
paid to each state to the appropriate state. For the FERC fees, the Company uses the P/T
ratio to allocate the fees to Washington and Idaho. Since these fees are based on
revenues, the use of the P/T ratio to allocate the fees produces the best matching of costs
with revenues in each state. For the other common A&G expenses of the State and
Federal Regulation department, the over-all 4-factors are used to allocate to electric
service (Factors 7, 8 and 9).
Lines 14 through 15 – Depreciation and amortization expense of generation and
transmission property are allocated using the same methodology as the generation and
transmission O&M costs, described above for lines 1 through 7.
Line 16 – Depreciation and amortization expense of electric distribution property
are all directly assigned.
ICNU_DR_035 Attachment A Page 103 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 103
Docket Nos. UE-14_______ & UG-14_______
Line 17 – Depreciation and amortization expense of general plant are allocated
using the same methodology as the Administrative and General costs, described above for
line 12.
Line 18 – FERC Accounts 407 (Regulatory Amortizations) are primarily directly
assigned to the state where the deferral of costs originated. However, for electric service,
there are deferrals that were approved in both Washington and Idaho related to the Coeur
d’ Alene Tribe Settlement (CDA Settlement) in 2008 that were recorded as a common 7
electric deferral that is allocated to Washington and Idaho using the P/T ratio. The CDA
Settlement relates to the use of the land for Avista’s hydro generating facilities. 9
Therefore, the P/T ratio is appropriate to allocate these costs.
Line 19 – Intangible plant accounts and associated accumulated depreciation
(A/D) accounts include two groups of plant: 1) general intangible plant, like software, and
2) the CDA Settlement costs that were recorded as plant in 2008. The CDA Settlement
costs are all directly assigned to electric service. General intangible plant and A/D is
allocated to electric using the 4-factors (Factors 7, 8 and 9). The CDA Settlement costs
are allocated to Washington and Idaho using the P/T ratio, using the same reasoning as
describe in Line 18 above. General intangible plant and A/D is allocated to Washington
and Idaho using the 4-factors (Factor 4). The amount of intangible plant, like software, is
not directly influenced by just one factor, like customers; therefore the over-all 4-factors
are used as a reasonable basis to allocate the rate base.
Lines 20-21 – Generation and transmission plant and associated A/D are directly
assigned to electric service. Consistent with generation and transmission O&M costs and
ICNU_DR_035 Attachment A Page 104 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 104
Docket Nos. UE-14_______ & UG-14_______
depreciation expenses, the rate base is allocated to Washington and Idaho using the P/T
ratio.
Line 22 - Distribution plant and associated A/D are directly assigned to electric
service and to each state.
Line 23 – General plant includes structures and improvements, office furniture,
power operated equipment and transportation vehicles, etc. General plant and A/D is
allocated to electric using the 4-factors (Factors 7, 8 and 9). General plant and A/D is
allocated to Washington and Idaho using the 4-factors (Factors 4). The amount of general
plant is not directly influenced by just one factor, like customers; therefore the over-all 4-
factors are used as a reasonable basis to allocate the rate base.
Line 24 – Regulatory deferred assets and liabilities are all directly assigned to
electric service and to each state that approved the deferral.
Line 25 – Working capital is computed using the investor supplied working
capital (ISWC) method. Each balance sheet account is categorized. The remaining
accounts (primarily non-earning short-term assets and liabilities) are allocated to service
and states by the types of activity in each account. A variety of the allocation factors are
used depending on the types of activity.
Q. Would you describe for natural gas service for each income statement 18
and rate base FERC account the allocation method that is used by the Company and 19
a brief explanation of how the use of that factor produces a reasonable allocation of 20
costs? 21
ICNU_DR_035 Attachment A Page 105 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 105
Docket Nos. UE-14_______ & UG-14_______
A. For natural gas North operations, Table No. 6 below summarizes the
various factors that are used for each FERC account.
Table No. 6 3

Lines 1 through 2 – Customer revenues and other revenues are directly assigned to
natural gas service in the general ledger. Revenues are primarily directly assigned to the
states. There are other revenues that are allocated to Washington and Idaho natural gas
service using the over-all 4-factor allocator (Factor 4). These other revenues are not
Line Description FERC Accounts
Allocation Method to
Electric/Natural Gas Allocation Method to State
Income Statement
1)Sales to Customers 480-484, 499 Direct Assignment Direct Assignment
2)Other Sales, including Sales for Resale, Rent,
etc.
483, 488-495 Direct Assignment Direct Assignment or Factor 4 (Common
Factor)
3)Production Expenses 804-813 Direct Assignment Direct Assignment or Actual Annual
Throughput Ratio (Nat. Gas Factor 10)
4)Underground Storage 814-837 Direct Assignment System Contract Demand Ratio (Nat. Gas
Factor 1)
5)Distribution O&M 870-894 Direct Assignment Direct Assignment or Factor 3 (Directly-
Assigned Distribution Costs)
6)A&G - Customer Accounts Expenses 901-905 Customer Ratio of Factors 7, 8 &
9 (Common Factor)
Customer Ratio (Factor 2)
7)A&G - Customer Service and Info Expenses 908-910 Customer Ratio of Factors 7, 8 &
9 (Common Factor)
Customer Ratio (Factor 2)
8)A&G - Sales Expenses 912-916 Customer Ratio of Factors 7, 8 &
9 (Common Factor)
Customer Ratio (Factor 2)
9)A&G - Other Expenses 920-927, 930-935 Factors 7, 8 & 9 (Common
Factor)
Factor 4 (Common Factor)
10)A&G - Regulatory Expenses 928 Factors 7, 8 & 9 (Common
Factor)
Factor 4 (Common Factor)
11)Depreciation and Amortization - U/G Storage 403-404 Direct Assignment System Contract Demand Ratio (Nat. Gas
Factor 1)
12)Depreciation and Amortization - Distribution 403-404 Direct Assignment Direct Assignment
13)Depreciation and Amortization - General 403-404 Factors 7, 8 & 9 (Common
Factor)
Factor 4 (Common Factor)
14)Regulatory Amortizations 407 Direct Assignment Direct Assignment
Rate Base
15)Intangible Plant and A/D 101, 108-111 Direct Assignment and Factors
7, 8 & 9 (Common Factor)
Factor 4 (Common Factor)
16)U/G Storage Plant and A/D 101, 108-111 Direct Assignment System Contract Demand Ratio (Nat. Gas
Factor 1)
17)Distribution Plant and A/D 101, 108-111 Direct Assignment Direct Assignment
18)General Plant and A/D 101, 108-111 Factors 7, 8 & 9 (Common
Factor)
Factor 4 (Common Factor)
19)Regulatory Deferred Assets and Liabilities 182, 186 Direct Assignment Direct Assignment
20)Working Capital ISWC Investor Supplied Allocation Investor Supplied Allocation
21)Gas Inventory 117, 164 Direct Assignment System Contract Demand Ratio (Nat. Gas
Factor 1)
ICNU_DR_035 Attachment A Page 106 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 106
Docket Nos. UE-14_______ & UG-14_______
influenced by any one factor, so the use of the over-all 4-factor that is equally weighted
with customers, direct labor, other non-labor O&M and A&G direct costs and net direct
plant, produces a reasonable allocation of common revenues.
Line 3 – Production expenses, including natural gas purchases are directly
assigned to natural gas service in the general ledger. The majority of these costs are
directly assigned to Washington and Idaho using the actual sales data for each month. A
small amount of the costs are allocated using the prior year’s actual annual throughput 7
(Factor 10). Since all of these costs are allocated using actual sales data in each state, the
use of these ratios to allocate these costs produces a matching of costs with the revenues.
Line 4 – Underground storage costs are directly assigned in the general ledger to
natural gas service. The costs are allocated to Washington and Idaho using the System
Contract Demand ratio. As described above, this ratio is the average of the highest 5
consecutive days of throughput for a 3-year period.
Line 5 - Distribution costs are directly assigned in the general ledger to natural gas
service. The majority of costs are also directly assigned to Washington and Idaho. For
those costs not directly assigned, the Company allocates the common distribution costs
using the ratio of directly assigned distribution costs incurred in each state in comparison
to the total.
Lines 6 through 8 - Customer count is one component of the 4-factors. Rather
than using the over-all 4-factors (Factors 7, 8 and 9) to allocate the common costs to
natural gas service for common portions of FERC Accounts 901-905 (Customer Accounts
Expense), FERC Accounts 906-910 (Customer Service and Information Expense), and
ICNU_DR_035 Attachment A Page 107 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 107
Docket Nos. UE-14_______ & UG-14_______
FERC Accounts 911-917 (Sales Expenses), the Company uses the customer component
ratio of the 4-factors. These costs in these FERC accounts are heavily influenced by the
number of customers, and therefore, the ratio based on customers is more appropriate to
allocate the costs to electric and natural gas service than the over-all 4-factor. Using the
same reasoning, the Company uses Factor 2 (Customer Ratio) to allocate the common
natural gas costs to Washington and Idaho.
Line 9 - FERC Accounts 920-927 and 930-935 (Administrative and General)
include various A&G costs, including salaries, office supplies and expenses, outside
services, maintenance of common general plant, etc. The over-all 4-factor allocator s
(Factors 7, 8 and 9) are used to allocate the common costs to natural gas service and the
over-all 4-factor allocator (Factor 4) is used to allocate the common natural gas costs to
Washington and Idaho. These costs are not influenced by any one factor, so the use of the
over-all 4-factor that is equally weighted with customers, direct labor, other non-labor
O&M and A&G direct costs and net direct plant, produces a reasonable allocation of
common costs.
Line 10 – FERC Accounts 928 (Regulatory Commission expenses) include state
fees that are based on revenues, in addition to other A&G expenses of the State and
Federal Regulation department. The Company directly assigns the fees to natural gas
service. For the state commission fees, the Company directly assigns the fees paid to each
state to the appropriate state. For the other common A&G expenses of the State and
Federal Regulation department, the over-all 4-factors are used to allocate to natural gas
service (Factors 7, 8 and 9).
ICNU_DR_035 Attachment A Page 108 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 108
Docket Nos. UE-14_______ & UG-14_______
Line 11 – Depreciation and amortization expense of underground storage property
are allocated using the same methodology as the underground storage costs, described
above for line 4.
Line 12 – Depreciation and amortization expense of natural gas distribution
property are all directly assigned.
Line 13 – Depreciation and amortization expense of general plant are allocated
using the same methodology as the Administrative and General costs, described above for
line 9.
Line 14 – FERC Accounts 407 (Regulatory Amortizations) are primarily directly
assigned to the state where the deferral of costs originated.
Line 15 – Intangible plant accounts and associated accumulated depreciation
(A/D) accounts includes general intangible plant, like software. General intangible plant
and A/D is allocated to natural gas service using the 4-factors (Factors 7, 8 and 9).
General intangible plant and A/D is allocated to Washington and Idaho using the 4-factors
(Factors 4). The amount of intangible plant, like software, is not directly influenced by
just one factor, like customers; therefore the over-all 4-factors are used as a reasonable
basis to allocate the rate base.
Line 16 – Underground storage plant and associated A/D are directly assigned to
natural gas service. Consistent with underground storage costs and depreciation
expenses, the rate base is allocated to Washington and Idaho using the System Contract
Demand ratio.
ICNU_DR_035 Attachment A Page 109 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 109
Docket Nos. UE-14_______ & UG-14_______
Line 17 - Distribution plant and associated A/D are directly assigned to natural gas
service and to each state.
Line 18 - General plant includes structures and improvements, office furniture,
power operated equipment and transportation vehicles, etc. General plant and A/D is
allocated to natural gas using the 4-factors (Factors 7, 8 and 9). General plant and A/D is
allocated to Washington and Idaho using the 4-factors (Factors 4). The amount of general
plant is not directly influenced by just one factor, like customers; therefore the over-all 4-
factors are used as a reasonable basis to allocate the rate base.
Line 19 – Regulatory deferred assets and liabilities are all directly assigned to
natural gas and each state that approved the deferral.
Line 20 – Working capital is computed using the investor supplied working
capital (ISWC) method. Each balance sheet account is categorized. The remaining
accounts (primarily non-earning short-term assets and liabilities) are allocated to service
and states by the types of activity in each account. A variety of the allocation factors are
used depending on the types of activity.
Line 21 – Natural gas inventory is directly assigned to natural gas service in the
general ledger. The costs are allocated to Washington and Idaho using the System
Contract Demand ratio. This method is consistent with the method used to allocate
underground storage costs, as described in Line 4 above.
Summary 20
Q. What portion of Washington’s costs are allocated in the test period? 21
ICNU_DR_035 Attachment A Page 110 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 110
Docket Nos. UE-14_______ & UG-14_______
A. A summary of the costs for the test period (twelve months ended June 30,
2013) is provided in Table No. 7 below.
Table No. 7 3

Excluding the allocated power supply, generation and transmission costs that are
allocated using the P/T ratio, the Company has allocated $68,088,000 of costs to
Washington electric service. This represents approximately 14% of total electric costs
($68,088/$572,926) that have been allocated to Washington electric service. Excluding
the costs that are allocated using the P/T ratio, this represents approximately 41% of non-
generation, transmission and power supply costs are allocated for electric service in
Washington ($68,088/$166,534).
Excluding the allocated production and underground storage costs, the Company
has allocated $22,251,000 of costs to Washington natural gas service. This represents
approximately 11% of total natural gas costs ($22,251/$197,058) that have been allocated
Direct Allocated Total Direct Allocated Total
Power Supply/Generation &
Transmission/Production/Underground
Storage 11,347$ 395,045$ 406,392$ 136,095$ 2,045$ 138,140$
O&M Distribution 15,401 5,734 21,135 7,898 2,758 10,656
Depreciation and Amortization 23,092 12,007 35,099 7,649 3,228 10,877
Administative and General 20,336 50,347 70,683 8,588 16,265 24,853
Taxes other than Income Taxes 39,617 - 39,617 12,532 - 12,532
Total Other Costs 98,446 68,088 166,534 36,667 22,251 58,918
Total 109,793$ 463,133$ 572,926$ 172,762$ 24,296$ 197,058$
Operating Costs
For the Twelve Months Ended June 30, 2013
WA Electric WA Natual Gas
($000's)
ICNU_DR_035 Attachment A Page 111 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 111
Docket Nos. UE-14_______ & UG-14_______
to Washington natural gas service. Excluding production and underground storage costs,
this represents approximately 38% of non-production costs and underground storage costs
are allocated for natural gas service in Washington ($22,251/$58,918).
Q. What portion of Washington’s plant costs are allocated in the test 4
period? 5
A. A summary of plant costs for the test period (June 30, 2013 AMA basis) is
provided in Table No. 8 below.
Table No. 8 8
9
10
11
12
13
14
15

Excluding the allocated generation and transmission plant investment that are
allocated using the P/T ratio, the Company has allocated $171,300,000 of plant costs to
Washington electric service. This represents approximately 8% of total electric plant
costs ($171,300/$2,097,701) that have been allocated to Washington electric service.
Excluding the costs that are allocated using the P/T ratio, this represents approximately
17% of non-generation, transmission and power supply costs are allocated for electric
Direct Allocated Total Direct Allocated Total
Generation &
Transmission/Underground Storage -$ 1,108,341$ 1,108,341$ -$ 24,503$ 24,503$
Distribution 768,726 - 768,726 300,048 1,792 301,840
Intangible 2,762 52,535 55,296 965 7,282 8,247
General Plant 46,573 118,765 165,338 13,945 24,818 38,764
Total Other 818,061 171,300 989,360 314,958 33,892 348,851
Total 818,061$ 1,279,641$ 2,097,701$ 314,958$ 58,395$ 373,354$
Plant Costs
Average of Monthly Averages at June 30, 2013
($000's)
WA Electric WA Natual Gas
ICNU_DR_035 Attachment A Page 112 of 113
Exhibit No. ___(EMA-1T)
Direct Testimony of Elizabeth M. Andrews
Avista Corporation Page 112
Docket Nos. UE-14_______ & UG-14_______
service in Washington ($171,300/$989,360). Therefore, approximately 83% of non-
generation and transmission plant costs are directly assigned for electric service in
Washington.
Excluding the allocated underground storage plant, the Company has allocated
$33,892,000 of plant costs to Washington natural gas service. This represents
approximately 9% of total natural gas plant costs ($33,892/$373,354) that have been
allocated to Washington natural gas service. Excluding the underground storage plant
this represents approximately 10% of non-underground storage plant costs are allocated
for natural gas service in Washington ($33,892/$348,851). Therefore, approximately
90% of non-underground storage plant costs are directly assigned for natural gas service
in Washington.
Q. In summary, do you believe the allocation methodology used today by 12
the Company is appropriate for allocating common costs? 13
A. Yes, I do. We believe the method used by Avista produces a reasonable
allocation of costs. The allocation factors are derived using actual, directly assigned costs
and other actual data points that are updated annually with current data, so growth in each
service or jurisdiction is factored into the current year allocation. It has been reviewed
and accepted by all jurisdictions in which Avista serves and remains a sound, rational
basis for allocating costs.
Q. Does that conclude your pre-filed direct testimony? 20
A. Yes, it does.

ICNU_DR_035 Attachment A Page 113 of 113
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Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 036 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to ICNU Data Request 009. From 2005 to the present, please provide the annual amount of Schedule 91 Demand Side Management (“DSM”) funding collected from each other schedule (i.e.,
besides Schedule 25), including supporting documents.

RESPONSE:
See ICNU_DR_036 Attachment A for the requested information. The electronic file of
ICNU_DR_036 Attachment A includes the supporting documents.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 037 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to ICNU Data Request 010. From 2005 to the present, please provide a quantification of benefits received by customers of each other schedule (i.e., besides Schedule 25 customers) from
the Company’s DSM programs, including supporting documents.

RESPONSE:
The following table outlines the direct incentive amounts by segment (schedule 25 customers are
included in the non-residential segment), as well as the overall system benefits for all customers
from that year’s specific electric conservation measures. Please see ICNU_DR_037 Attachments A
and B.

Washington
Residential Low Income Nonresidential System Electric Avoided Cost
2015
2014
2013
2012
2011
2010
2009
2008*
2007*
2006*
2005*
* Washington and Idaho
Idaho
Residential Low
Income
Nonresidential System Electric Avoided
Cost
2015
2014
2013
2012
2011
2010
2009

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 038 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to ICNU Data Requests 010 and 037. In addition to direct energy efficiency incentives paid to customers for qualifying electric efficiency measures, has the Company performed an analysis
showing the benefits customers have received from the deployment of the Company’s DSM
resources, e.g., in terms of reduced power supply costs, or any other form of additional benefit? If
yes, please provide all supporting studies and documentation.
RESPONSE:
Please see the Company’s response to ICNU_DR_037.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 039 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Has the Company quantified the benefits provided to each customer class from their use of the Company’s DSM staff for efficiency consultations, energy audits, or analysis and reporting on
potential efficiency measures? If yes, please provide all supporting studies and documentation.

RESPONSE:
The Company has not performed an analysis quantifying the benefits provided to each schedule of
customers from their use of Avista’s DSM staff for efficiency consultations, energy audits, or
analysis and reporting on potential efficiency measures.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 040 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to the Company’s responses to ICNU Data Requests 009 and 010. Would the Company agree that it is inequitable for one rate schedule to consistently provide more DSM funding through
Schedule 91 in comparison to direct energy efficiency incentives paid back to that rate schedule?

RESPONSE:
The Company does not agree that it is inequitable for one rate schedule to consistently provide
more DSM funding through Schedule 91 since all customers receive benefits through the DSM
programs whether they are directly participating at their specific level of contribution or not.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 041 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

If the Company answered no to ICNU Data Request 040, does the Company disagree on the basis that DSM benefits go to the entire system, such that everyone benefits in the same way? If no,
please explain why the Company disagrees with ICNU Data Request 040.

RESPONSE:
Although systematic benefits would be difficult to quantify whether customers benefit in the exact
same way at all times, the Company believes that the actual benefits that accrue to all customers is
much greater than just the direct incentives provided to customers for efficiency projects, so
judging the equity of DSM by purely comparing direct incentives to the portion of funds collected through schedule 91 for specific customer classes is an incomplete analysis.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 042 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

If the Company answered yes to ICNU Data Request 041, please confirm that customers of each rate schedule will continue to benefit in the exact same manner from DSM funding collected
through Schedule 91, regardless of the annual amount of funding collected from each respective
rate schedule. If the Company cannot confirm, please explain how benefits by rate schedule vary
depending upon DSM funding levels by the same rate schedule.
RESPONSE:
Please see the Company’s response to ICNU_DR_041.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 043 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that for present Low Income Rate Assistance Program (“LIRAP”) funding purposes, under Schedule 92, LIRAP funds are not collected from Block 3 of Schedule 25.
RESPONSE:
Per the Settlement Agreement approved by the Commission in Docket No. 140188, the parties agreed
that for Schedule 25 the LIRAP rate will apply to only the first and second energy blocks.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 044 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that the Company analyzes the cost effectiveness of its DSM program by separately reviewing residential, non-residential, and site-specific programs. If the Company cannot confirm,
please explain the analytical review process of DSM measures and programs contained in the
Company’s Revised 2016 DSM Business Plan (see pp. 16-24).

RESPONSE:
The Company, as well as our third party evaluator, separately analyzes the cost-effectiveness of
residential, non-residential, and site-specific programs. It should be noted that those specific
analyses are measuring the system benefits of those programs and not the direct benefits to customers who participate in those programs.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 045 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Regarding “site-specific” DSM projects, please quantify, from 2005 to the present, the percentage of projects that the Company would classify as: a) “residential”; b) “non-residential”; and c)
“industrial.”

RESPONSE:
a) All of the Company’s residential program offerings are prescriptive and there are no site specific
analyses performed for this segment, so the percentage would be 0%.
b) The Company only performs site specific analyses for non-residential customers, so 100% of the
site-specific analyses would be classified as non-residential. c) The Company classifies industrial customers under the non-residential umbrella but does not
specifically track industrial projects separately.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 046 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that site-specific DSM programs have historically been one of the most cost-effective. If the Company cannot confirm, please identify which DSM programs have been more
cost-effective over the last 10 years.

RESPONSE:
Historically, the site-specific DSM projects have been the most cost-effective projects.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 047 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

From 2005 to the present, please quantify the annual share of energy savings achieved by site-specific DSM programs relative to all other DSM programs.

RESPONSE:
The table below shows the gross unverified Washington & Idaho savings, site-specific savings and
site-specific percentage of the portfolio.

Annual
Savings (kWh)
Site Specific
Savings (kWh) %
2005

46,182,976

22,169,139 48.0%
2006

49,154,518

16,409,415 33.4%
2007

58,759,769

28,852,950 49.1%
2008

74,861,160

17,571,353 23.5%
2009

80,340,472

31,952,425 39.8%
2010

72,900,711

13,483,000 18.5%
2011

119,281,122

53,629,000 45.0%
2012

80,179,716

43,458,824 54.2%
2013

65,123,082

17,788,975 27.3%
2014

67,873,456

13,720,712 20.2%
2015

52,025,516

11,665,362 22.4%

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 048 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that the proportion of DSM funds returned to Schedule 25 customers through direct incentives is less than the overall proportion returned for the Company’s Washington Electric Portfolio.
If the Company cannot confirm, please explain with specific consideration and reference to the
Company’s responses to ICNU Data Requests 009 and 010 and Table 4 of the Company’s Revised 2016
DSM Business Plan (p. 29).
RESPONSE:
For all except 2 years (2007 and 2009) the ratio of revenue returned to Schedule 25 customers through
direct incentives was less than the ratio (.64) presented in the 2016 Revised DSM Business Plan.
Schedule 25 Schedule 25
Year DSM Revenue DSM Direct Incentives Ratio
2005 570,784$ 304,663$ 0.53
2006 582,847$ 139,523$ 0.24
2007 583,346$ 915,154$ 1.57
2008 1,155,315$ 301,082$ 0.26
2009 1,855,706$ 1,304,745$ 0.70
2010 2,242,314$ 736,950$ 0.33
2011 2,306,451$ 418,132$ 0.18
2012 1,773,427$ 832,731$ 0.47
2013 1,495,037$ 336,161$ 0.22
2014 1,956,751$ 40,244$ 0.02
2015 1,752,710$ 798,300$ 0.46

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/13/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 049 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that Avista is required by Commission rule to receive advice regarding conservation program budgets and actual expenditures compared to budgets. If the Company
cannot confirm, please explain the Company’s understanding of its responsibilities under WAC §
480-109-110(1)(l).

RESPONSE:
Avista is required by Commission rule to maintain and use an external conservation advisory group
of stakeholders to advise the utility on conservation issues, including program budgets and actual
expenditures compared to budgets.

Page 1 of 1
AVISTA CORP. RESPONSE TO REQUEST FOR INFORMATION

JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016 CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 050 TELEPHONE: [phone]
EMAIL: [e-mail]
REQUEST:
For each month of the test year, please provide monthly peak demand and energy consumption
on a total-system basis and for each rate class on the Company’s system.
RESPONSE:
The requested information was included in previously provided Ms. Knox work papers on page
TLK-E-129. For your convenience a copy of the table from that work paper is provided as ICNU_DR_050 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 051 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide workpapers detailing the manner in which the demand and energy allocation factors in the Company’s class cost of service study were adjusted for line losses.

RESPONSE:
The development of the loss factors is shown in the previously provided Ms. Knox work papers on
page TLK-E-141. The loss factor adjustment to estimated monthly coincident peak values is shown
on work paper page TLK-E-128. The loss factor adjustment to estimated monthly non-coincident
peak values is shown on work paper page TLK-E-131. The same loss factors are applied to energy
allocations embedded in the formulas for the E02 allocator within the cost of service model as shown on work paper page TLK-E-116 line 13. These work papers were also provided
electronically with the Company’s initial filing.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 052 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a complete electronic copy of the Company’s class cost of service study.
RESPONSE:
The complete electronic copy of the Company’s electric class cost of service study was provided
with the Company’s initial filing. For your convenience, a duplicate electronic copy of the Ms. Knox Electric Cost of Service work papers is provided as ICNU_DR_052 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 053 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a complete electronic copy of the workpapers supporting the Company’s proposed revenue distribution.
RESPONSE:
See the previously provided Excel workpaper files provided by the Company in its initial filing for
Company witness Ehrbar labeled “WA Elec Revenue - 2017” and “WA Elec Revenue – 2018”.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox/Pat Ehrbar
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 054 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide workpapers that demonstrate how the Company developed its distribution plant allocators in its class cost of service study to recognize differences in the voltage level of service
(transmission, sub-transmission, primary distribution and secondary distribution). If voltage level
distinctions are not fully recognized in the development of the allocators, please explain why not,
in detail.
RESPONSE:
The work papers supporting the voltage level distribution plant assignment and allocation were included
in the Company’s initial filing. A duplicate copy of the electric cost of service model and work papers
were also supplied in response to ICNU_DR_052.
Voltage level distinction of distribution plant work papers may be found on the pages marked TLK-E-
91, TLK-E-92, and TLK-E-94. The non-coincident peak allocation factor development by voltage level
is shown on the pages marked TLK-E-130 and TLK-E-131. The model input area for the distribution
plant voltage level distinctions is shown as work paper page TLK-E-78. The demand allocators within the model are shown as work paper page TLK-E-116.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/02/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 055 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a table that shows a breakdown of the Company transmission and distribution plant in service by voltage level of service (transmission, sub-transmission, primary distribution and
secondary distribution).

RESPONSE:
The Company’s accounting system does not maintain plant in service values by voltage level.
However, for cost of service purposes distribution poles, towers, and fixtures (FERC Account 364),
overhead conductors and devices (FERC Account 365), underground conduit (FERC Account 366),
and underground conductors and devices (FERC Account 366) are segregated by the percentage of
line miles in service at primary versus secondary voltage level. The table provided as ICNU_DR_055 Attachment A represents the plant in service values from the pro forma cross check
study segregated by voltage level according to the line mile percentages utilized in the electric cost
of service study. Other transmission and distribution plant accounts are shown at the voltage levels
assumed for the electric cost of service study.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 056 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the monthly system peak demands on the Company’s system for each of the most recent five calendar years.
RESPONSE:

The Company’s historical monthly coincident peak demands for the last five years was provided in response to ICNU_DR_031.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox/Pat Ehrbar
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 057 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Referring to the Extra Large General Service (Schedule 25) rate class, please provide the following:
a. A list of all customers receiving service under this rate schedule;
b. The delivery voltage or voltages at which each customer is supplied;
c. The test year energy and demand data for each customer, used in the development of
the demand and energy allocation factors for the Schedule 25 class in the cost of
service study; and
d. The test year billing determinants (both kWh and kW) used in the Company’s proof
of revenue at proposed rates.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 057C. Please note that
Avista’s response to ICNU – 057C is Confidential per Protective Order in UTC Dockets 160228 &
UG-160229.

The non-confidential version of this data (omitting customer names) was provided with Ms. Knox and Mr. Ehrbar work papers with the Company’s initial filing.

Please see ICNU_DR_057C CONFIDENTIAL Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/02/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 058 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Exh. No. TLK-1T at 12, n.6. Please provide detailed workpapers showing the determination of the peak credit ratio and the resulting classification of generation and transmission
fixed costs using the prior method of comparing the ratio of the replacement cost per kW of the
Company’s peaking units to the replacement cost per kW of the Company’s thermal and hydro
plants (separately).
RESPONSE:
Please see ICNU_DR_058 Attachment A which contains summary results of the Company’s electric
cost of service study scenario reflecting the replacement cost peak credit methodology including a
comparison of key results. Electronic only work papers (including the cost of service model run) are provided as ICNU_DR_058 Attachment B.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 059 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Exh. No. TLK-2 at 3:11-15. Please provide detailed workpapers showing the determination of the peak credit ratio and the resulting classification of generation and transmission
fixed costs using the electric system load factor.

RESPONSE:
The peak credit ratio determination is shown on Ms. Knox work paper pages TLK-E-79 through
TLK-E-81 that were included in the Company’s initial filing. A summary of the resulting
classification of generation and transmission costs may be found on the “Functional Cost Summary
by Classification at Uniform Requested Return" provided as work paper page TLK-E-157.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 060 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Exh. No. TLK-2 at 4:19-5:4. Please provide workpapers supporting the following calculations:
a. The direct assignment of distribution demand-related costs to customer classes and
the justification for such direct assignment, including the direct assignment of specific
substations and related primary voltage distribution facilities to Extra Large General
Service customers based on their load ratio share of substation capacity; and
b. The development of the allocator for distribution facilities that serve only secondary
voltage customers.

RESPONSE:
The work papers supporting these calculations were included with the Company’s initial filing. A
duplicate copy of the electric cost of service model and work papers were also supplied in response to
ICNU_DR_052.

Part a. work papers may be found on the pages marked TLK-82 through TLK-98. Part b. work papers may be found on the pages marked TLK-E-130 and TLK-E-131. The demand
allocators within the model are shown as work paper page TLK-E-116.

The purpose of the direct assignment of specific substations and related primary voltage distribution
facilities to Schedule 25 customers is to limit the proportion of the distribution system assigned to them to the facilities that they directly benefit from. Absent the direct assignment process, these 21 (of
242,443) customers would receive 14.96% of the total demand-related distribution costs through the
unadjusted non-coincident peak allocation factor D02. (NCP allocation would result in a cost
responsibility of approximately $15.2 million versus the direct assignment that results in $4.0 million to
this group of customers in this study.)

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 061 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 6:1-18. Please confirm that the Company’s Washington Electric Rate of Return (“ROR”), on a Normalized Commission Basis (“CB”) results basis for the 12-month period ended September
30, 2015, is higher than the Normalized CB results for the Company’s Washington Electric ROR for
the 12-month period ended September 30, 2014.

RESPONSE:
See Avista’s response to ICNU_DR_004 for an explanation of the Normalized CB results for the
period 2013-2015.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 062 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to 12:22-27. Please confirm that on January 11, 2016, the Commission stated concern that, absent
an electric attrition adjustment, the Company may not have an opportunity to achieve earnings on electric operations at or near the authorized levels of a 7.29% ROR and a 9.50% return on equity (“ROE”).
RESPONSE:
Yes. In Order 5 in Avista Dockets UE-150204 and UG-150205, in reference to setting rates for the 2016
rate period, the Commission stated concern that, absent an electric attrition adjustment, the Company may not have an opportunity to achieve earnings on [2016] electric operations at or near the authorized levels
of a 7.29% ROR and a 9.50% return on equity (“ROE”).

Also see Avista’s responses to ICNU_DR_067 & _069.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/18/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 063 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to 16:15-18:1. Please identify benefits from recent cost management measures that were not
already discussed by Ms. Andrews in testimony supporting the Company’s 2015 general rate case (“GRC”) (UE-150204 and UG-150205).

RESPONSE: See Avista’s response to ICNU_DR_017

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 064 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 18:8-20. Please provide earned ROE results for 2015, in the same format as the 2013 and 2014 results provided in Table 4.

RESPONSE:
See Avista’s response to ICNU_DR_004.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/18/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 065 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to 25:12-32:2. Please provide a narrative response explaining why the Company believes that “after
attrition adjustments” are appropriate, with specific consideration and reference to Order 05 in the Company’s 2015 GRC (“Order 05”), ¶¶ 111-15, in which the Commission discusses “the appropriate
methodology for an attrition study.”

RESPONSE:
The Company explained at-length its reasoning for including an After-Attrition adjustment in this proceeding starting at page 26, line 1 through page 32, line 2, of Ms. Andrews’ testimony, Exhibit No.
__(EMA-1T).

Specifically as After-Attrition adjustments relate to the Company’s 2015 GRC (Docket Nos. UE-150204
and UG-150205) and Order 05, both Commission Staff in its direct filed testimony (see Docket Nos. UE-150204 and UG-150205, McGuire Exhibit No. _(CRM-1T), page 54 line 19 – page 55 line 10), and the
Commission in its Order 05, by way of support of the Commission Staff’s attrition methodology,
supported After-Attrition adjustments with regards to certain capital and expenses. The Commission
supported the proposed After-Attrition adjustments within their ultimate revenue requirement
determination for both electric and natural gas by supporting Commission Staff’s Attrition model methodology. Specifically, the Commission noted in its Order 05, paragraph 111:

We find Staff’s approach, as adjusted and corrected by the Company, to provide the
most appropriate methodology in this docket for supporting an attrition adjustment.
The Commission in its Order 05 noted their acceptance of Staff’s methodology (and Avista’s adoption,
with corrections of that methodology on rebuttal at paragraph 114, Order 05), which included certain
capital and expense After-Attrition adjustments. Both the Staff and the Company (on rebuttal) included
within their electric and natural gas Attrition Study models and testimonies explanation and accounting
for certain After-Attrition adjustments within the electric and natural gas revenue requirements ultimately approved by the Commission in Order 05, as follows:
• Electric Attrition Study included separate columns for 1) “After Attrition Adjustment
CS2/Colstrip Incremental O&M Expense” and 2) “After-Attrition Adjustment–Project Compass.”
• Natural Gas Attrition Study included separate columns for 1) “After-Attrition Adjustment–Project Compass” an 2) “After-Attrition Adjustment-Atmospheric Testing.”

As noted within Ms. Andrews’ testimony at Exhibit No. _(EMA-1T), page 31, line 4-31,
Staff supported the use of an After-Attrition adjustment for Project Compass within its electric and natural gas Attrition models, which ultimately was approved by the Commission at a level that reflected 100% recovery level of Project Compass:

Page 2 of 2
Q. Was an “After-Attrition Adjustment” included and approved in Avista’s last
general rate case in Docket Nos. UE-150204 and UG-150205 to recognize that the use
of historical growth factors alone would not properly reflect what was expected to occur in the rate year?
A. Yes. Commission Staff witness Mr. McGuire recognized that his historical growth
trends (related to Net Plant After DFIT and Depreciation Expense) alone would not be
sufficient to allow Avista an opportunity to earn a fair return, and proposed an “After
Attrition Adjustment” related to the Company’s Project Compass capital project, which moved into service on February 2, 2015, following the base year utilized in that proceeding
of December 2014. He explains this and notes his adjustment is appropriate as follows:
I provide Avista with an after-attrition adjustment for Project Compass. That is,
I allow for recovery in rates the capital costs associated with Project Compass
beyond what would be implied by use of growth factors. … I determined that this was appropriate because Project Compass appears to be an abnormality
with respect to the Company’s ongoing capital growth pattern. Consider that the
calculated rate of growth for electric net plant between 2009 and 2014 was
approximately $50 million per year. Next, consider that the Company’s actual
electric transfers to plant was $45 million in February 2015 alone (the month Project Compass was placed in service). February transfers will not be the only
plant placed in service in 2015 and, so, implying that it will be by only using my
$50 million annual growth rate will likely lead to stranded capital costs and a
higher probability of earnings attrition. Treating Project compass as an
abnormality by including it as an after-attrition adjustment addresses this issue. (emphasis added) See Docket Nos. UE-150204 and UG-150205, McGuire
Exhibit No. _(CRM-1T), page 54 line 19 – page 55 line 10.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/18/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 066 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to 32:3-36:1. Please provide a narrative response explaining how the Company’s electric O&M
escalation proposal differs from the methodology approved by the Commission in Order 05, ¶¶ 137-39. RESPONSE: The electric O&M escalation and methodology approved by the Commission in Order 05 in Docket No.
UE-150204 was approved based on facts presented in that proceeding.
When discussing the use of attrition and escalation factors, the Commission noted at paragraph 113
“…an attrition study should use multiple years of historical data to arrive at a stable, non-volatile
projection of revenue, expenses and rate base.”

At paragraph 115 of Order 05 the Commission noted it may vary its determination “depending on the specific factual circumstances”:

The use of escalation factors from attrition studies to set rates is also a matter of informed
judgment. Here, we accept Staff’s use of a weighted average escalation factor for O&M
expense. It is supported with sound reasoning, as it recognizes and reflects recent reductions in O&M expense. However, as described below, we decline to use the recommended 3 percent escalation rate. We do not reject this escalation rate out of hand,
but find the Company and Staff do not present sufficient evidence to support their
recommendation to modify the result of their studies.1[170] The Commission has accepted
the modification of escalation rates derived from attrition studies in the past, and may do so again in the future depending on the specific factual circumstances and recognizing
that the Company carries the burden to make its case. (emphasis added)

Based on the facts of this case and the guidance in Order 05 from the Commission on “what is
the appropriate methodology for an attrition study,” the Company has used actual historical data for the period 2007 through September 2015 consistently for all cost categories (Net Plant After
Deferred Income Tax; Total Depreciation/Amortization; Taxes Other Than Income; and
O&M/A&G) to determine the appropriate growth trends.

As explained within Ms. Andrews’ testimony starting at page 31, line 3 of Exhibit No. _(EMA-1T), in determining the data used for a trend analysis for the purpose of an attrition study, it is important the data should reflect, as closely as possible, the Company’s recent and planned
expenditures. In reviewing the appropriate O&M growth trend, Avista looked at both its
historical trend and changes in O&M expenses, as well as that expected during the specified rate

1 Id. at 484:14 – 485:11.

Page 2 of 2
periods. For the impact of changes in expenses over time both historically and into the 2017 and
January to June 2018 rate periods, see Avista’s response to ICNU_DR_017.
As shown within Exhibit Nos. _(EMA-2) (electric) and _(EMA-3) (natural gas), page 12, the
O&M annual growth escalation trend proposed by the Company in its electric and natural gas
Attrition Studies (using 2007-2015 CBR data) is 4% and 2.28%, respectively. For comparison
purposes, the following table shows the weighted average results between the electric and natural
gas operations, given that electric operations represent approximately 81% and natural gas operations represent approximately 19%, of the Company’s total operations2. Avista’s proposed
O&M annual increase of 4.0% for electric and 2.28% for natural gas results in an overall
weighted average of 3.67% as shown below.

This 3.67% growth rate is less than the financial forecast of 4.36% annually between 2015 and
2017, and shows that the proposed 4.00% electric and 2.28% natural gas growth rates included in
the Company’s Attrition Models are reasonable, and if anything, understated. Further, given the one-way Earnings Tests in place related to the Decoupling Mechanism, it is
very important to establish the correct O&M escalation growth factors for each service as Avista
is subject to separate one-way earnings tests for each of its Washington electric and natural gas
operations. If Avista over-earns, for example, in its natural gas operations because a higher O&M escalation growth factor is used, it would be required to return half of its overearnings, protecting customers. However, if Avista under-earns in its electric operations, as a result of a
low O&M escalation growth factor being used, there is no protection for the Company under
these circumstances; Avista simply would not have the opportunity to earn its authorized rate of
return.

2 81% electric / 19% natural gas split based on current Results of Operations Utility Four Factor Allocation analysis for electric
and natural gas factor “direct non-labor O&M and A&G”.
Electric 4.00%81%3.22%
Natural Gas 2.28%19%0.44%
Weighted Average 3.67%
Weighted Average Annual O&M Increase

Page 1 of 2
Proposed Cap Structure
Capital Weighted
Component Structure Cost Cost
Total Debt 51.50%5.51%2.84%
Common 48.50%9.90%4.80%
Total 100.00%7.64%
Electric Revenue Rquirement: (000s)
ROR based on:2017 2018
(6-months )
1) Proposed (7.64%)38,568$ 10,301$
2) Current authorized (7.29%)31,558 10,209
3) Current authorized, updated with
Cost of Debt of 5.51% (7.45%)34,046 10,241
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 067-Supplemental TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to 38:7-8. Please state the Company’s proposed 2017 revenue requirement at the currently
authorized ROR of 7.29%.
RESPONSE: The current authorized rate of return (ROR) of 7.29% approved in Docket No. UE-150204 was approved
based on a Multiparty Settlement Stipulation (Partial Settlement) between the Parties to the proceeding.
This Partial Settlement, among other things, included agreement on cost of capital for the 2016 rate period, including a capital structure of 51.5% debt / 48.5% equity ratio, Return on Equity (ROE) of 9.5%
and cost of debt of 5.2%, resulting in an ROR of 7.29%. This partial settlement was part of a “give-and-
take” process, representing a compromise among differing points of view, with concessions made by the
Parties to reach a reasonable balancing of interests.
The Company’s request in this case includes the following cost of capital:

Below, a comparison of the Company’s requested revenue requirement for the 2017 and 6-month January
to June 2018 rate periods follows, using an ROR of: 1) Proposed (7.64%); 2) Current authorized (7.29%);
and 3) updated for the expected cost of debt as proposed by Avista of 5.51% (7.45%)1:

1 Cost of debt is expected to increase to 5.51% from the current authorized level of 5.2%. See support for the proposed cost of debt at witness Mr. Thies’ testimony Exhibit No. __(MTT-1T), starting at page 21, line 12. Updating the current authorized
capital structure alone for the expected cost of debt of 5.51% would result in an ROR of 7.45%.

Page 2 of 2
Using 12.31.2015 CBR Updated Attriton Studies
Electric Revenue Rquirement: (000s)
ROR based on:2017 2018
(6-months )
1) Proposed Revenue Request as FILED 38,568$ 10,301$
2) Revised Attrition Model using Current
authorized (7.29%)33,944 10,342
3) Revised Attrition Model using Current
authorized, updated with Cost of Debt of
5.51% (7.45%)36,443 10,374
Supplemental 05/20/2016

Recently the Company supplemented its 2017 and 2018 (6 months) electric Attrition Studies using December 31, 2015 normalized Commission Basis Results actual information, see Staff_DR_030. Using
these revised Attrition Studies per Staff_DR_030, the table below provides the same comparison included
in the table above for the 2017 and 6-month January to June 2018 rate periods, using an ROR of: 1)
Proposed (7.64%); 2) Current authorized (7.29%); and 3) updated for the expected cost of debt as
proposed by Avista of 5.51% (7.45%):

Page 1 of 1
Proposed Cap Structure
Capital Weighted
Component Structure Cost Cost
Total Debt 51.50%5.51%2.84%
Common 48.50%9.90%4.80%
Total 100.00%7.64%
Electric Revenue Rquirement: (000s)
ROR based on:2017 2018
(6-months )
1) Proposed (7.64%)38,568$ 10,301$
2) Current authorized (7.29%)31,558 10,209
3) Current authorized, updated with
Cost of Debt of 5.51% (7.45%)34,046 10,241
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/18/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 067 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to 38:7-8. Please state the Company’s proposed 2017 revenue requirement at the currently
authorized ROR of 7.29%.
RESPONSE: The current authorized rate of return (ROR) of 7.29% approved in Docket No. UE-150204 was approved
based on a Multiparty Settlement Stipulation (Partial Settlement) between the Parties to the proceeding.
This Partial Settlement, among other things, included agreement on cost of capital for the 2016 rate period, including a capital structure of 51.5% debt / 48.5% equity ratio, Return on Equity (ROE) of 9.5%
and cost of debt of 5.2%, resulting in an ROR of 7.29%. This partial settlement was part of a “give-and-
take” process, representing a compromise among differing points of view, with concessions made by the
Parties to reach a reasonable balancing of interests.
The Company’s request in this case includes the following cost of capital:

Below, a comparison of the Company’s requested revenue requirement for the 2017 and 6-month January
to June 2018 rate periods follows, using an ROR of: 1) Proposed (7.64%); 2) Current authorized (7.29%);
and 3) updated for the expected cost of debt as proposed by Avista of 5.51% (7.45%)1:

1 Cost of debt is expected to increase to 5.51% from the current authorized level of 5.2%. See support for the proposed cost of debt at witness Mr. Thies’ testimony Exhibit No. __(MTT-1T), starting at page 21, line 12. Updating the current authorized
capital structure alone for the expected cost of debt of 5.51% would result in an ROR of 7.45%.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/18/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 068 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to 49:21-50:5. Please state the Company’s proposed January to June 2018 revenue requirement at
the currently authorized ROR of 7.29%.
RESPONSE:
See Avista’s response to ICNU_DR_067.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/18/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 069 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to 61:11-14. Please explain why an $11.8 million electric rate increase would be “[c]learly …
insufficient to allow the Company to earn its authorized rate of return,” in light of the Company’s 2016 statement that “an $8.1 million reduction … leads to fair, just, reasonable, and sufficient end results. This
is a reduction that still allows Avista a reasonable opportunity to earn its authorized return” of a 7.29%
ROR (see the Company’s 2015 GRC, Order 06 at ¶ 28).

RESPONSE: The Company’s 2015 GRC (Docket No. UE-150204), the $8.1 million reduction approved in Order 05
and the statements made by Avista and noted in Order 06, relate specifically to the 2016 rate period
requested in that case. The Commission noted in Order 05, at paragraph 140: Accordingly, we find the [2016] overall revenue requirement for Avista’s electric
service should be reduced by approximately $8.1 million, based upon the results of a
modified historical test year with known and measurable pro forma adjustments,
including an attrition adjustment of approximately $28.3 million. While the end result
is still a reduction in revenue requirement for Avista’s electric service, it is significantly less than what would result from adopting Staff’s pro forma analysis or the intervenor’s
revenue requirement recommendations. Further, the Company has stated on the record
it expects to file a rate case every year for the next five years.

As noted by the Commission, the resulting revenue requirement approved in the Company’s 2015 GRC (Docket No. UE-150204) was approved based on the information on record for the
2016 rate period, and that the Company “expects to file a rate case every year for the next five
years.” As noted in the Company’s filing in this case, Docket No. UE-160228, the Company is
requesting rate relief for the calendar 2017 and 6-month January through June 2018 rate periods of $38.6 million and $10.3 million, respectively.
As explained in Ms. Andrews’ testimony at Exhibit No. _(EMA-1T), starting at page 61, line 7:
Q. How do these revenue requirement numbers compare with the
results from the electric and natural gas Pro Forma and Cross Check Studies?
A. As discussed earlier and explained by Ms. Smith, the Company has
prepared electric and natural gas Pro Forma Studies, based on a modified
historical test period, adjusted to reflect only limited adjustments. The results of
the electric and natural gas Pro Forma Studies provided a revenue requirement increase of only $11.843 million for electric operations and a reduction of $1.151

Page 2 of 2
million for the natural gas operations.1 Clearly, this would be insufficient to
allow the Company to earn its authorized rate of return.
By way of comparison, the Company’s electric and natural gas Attrition Studies produced revenue requirement results of $38.568 million and $4.397 million,
respectively for the 2017 rate period (emphasis added). For electric, this
difference results in an electric Attrition Adjustment of $26.7 million above the
electric Pro Forma Study results in order for the Company to achieve the
proposed ROR of 7.64%. For natural gas, the difference results in a natural gas Attrition Adjustment of $5.6 million above the natural gas Pro Forma Study
results in order for the Company to achieve this same proposed ROR of 7.64%.
The incremental January to June 2018 electric and natural gas revenue
requirements of $10.301 million and $941,000, respectively, results in
incremental Attrition Adjustments above 2017 amounts (emphasis added).
This is a significant difference, demonstrating that without the use of an
“Attrition Adjustment,” Avista would not have the opportunity to earn its
requested Rate of Return, and would significantly under-earn during the 18-
month rate plan period.
See Ms. Andrews testimony starting at page 11 for on-going attrition and impact on Avista’s
earnings for further discussion of increased capital and expenses expected beyond 2016. See
Ms. Smith’s testimony at Exhibit No. (JSS-1T) for discussion of the Company’s increased
capital and expenses over the 18-month rate plan (beyond the historical test period 12 months-
ending 09.2015, on an AMA basis, and compared to that currently authorized (in Docket No. UE-150204).

See also Avista’s response to ICNU_DR_017.

1 These studies were provided as Exhibit Nos. __(JSS-2) and __(JSS-3). Specifically, pages 6 – 10 of both studies show the revenue requirement produced from a modified historical test period approach, adjusted for limited, known and measureable
pro forma adjustments.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Kinney
REQUESTER: ICNU RESPONDER: Karen Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 070 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please refer to 14:12-38. Please confirm that all 2018 and 2019 upgrades described are not included within the $73.2 million for Nine Mile Redevelopment. If the Company cannot confirm,
please explain why 2018 and 2019 upgrades are included in a 2016 capital spending category.

RESPONSE:
The Company confirms that the $73.2 million investment in the Nine Mile Redevelopment is the
balance that will be placed in service during 2016 for this project. That is, this balance does not
include the 2018 and 2019 upgrades that are discussed within the overall description of the project.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Karen Schuh
REQUESTER: ICNU RESPONDER: Rich Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 071 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide all studies demonstrating that the cost differential—i.e., that each dollar of investment made in a prior year would have required x times that value (or $x) for an equivalent
amount of investment today—of replacing plant and equipment facilities, or of maintaining
reliable customer service and meeting reliability standards, is different today than throughout the
Company’s history.
RESPONSE:
The Company is not aware of any studies demonstrating cost differential. The replacement values
are estimated based on original cost escalated for inflation (the Handy-Whitman index). The computation is done by type of property (by plant account) and vintage (year placed in service). In
some cases, the replacement values derived from this method have been further adjusted based on
a current engineering estimate for the type of plant, because the assets are so old that compound
error / imprecision from simple application of the index method may not provide satisfactory
results.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Karen Schuh
REQUESTER: ICNU RESPONDER: Dave DeFelice
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 072 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that the overall 50-year cost differential of replacing plant and equipment facilities has been trending downward (e.g., the cost differential from 1965 to 2015 is lower than from 1943
to 1993). If the Company cannot confirm, please explain and provide documentation that would
support a static or upward trend.

RESPONSE:
Please see the Company’s response to ICNU_DR_011.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Heather Rosentrater
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 073 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify how many and which Schedule 25 customers are currently metered under the Company’s existing MV-90 program.

RESPONSE:
The Company has 32 Schedule 25 customers who are currently metered under our existing MV-90
system.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Heather Rosentrater
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 074 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a narrative response describing the Company’s MV-90 program. RESPONSE:

MV-90 is a head end system that consists of a database server and 2 application clients. The MV90 system interrogates electric meters over a phone land line (POTS) or over cellular digital connections.
Interval and register data is retrieved from the meters, validation is performed on reading data, system
support validation, estimation, and editing. MV-90 calculates billing determinates from interval data, it
also has a wide variety of reporting options and supports multiple export formats which allows for
extracting and analyzing data.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/20/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Joe Miller/Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Joe Miller
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 075 Supplemental TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a narrative response describing the basis for the allocation of metering costs among rate schedules in relation to the Washington Advanced Metering Project (“Project”).
SUPPLEMENTAL RESPONSE:

Upon further review, the Company discovered that it had inadvertently allocated the natural gas distribution plant related AMI meter costs (pro forma adjustment 4.03 G-CAMI) similar to the
allocation of all other distribution plant. The Company should have allocated the natural gas
distribution plant related AMI meter costs based on the meter cost allocator (C03), consistent with
the allocation described in the Company’s response to ICNU-075 for electric.
Communication and software pro forma investments related to the Advanced Metering Project did
not receive any special treatment in the natural gas cost of service study provided in this case. Both
communication equipment and software were allocated by the Company’s blended 4-part factor
consistent with all general plant. Please note, the communication and software pro forma
investments were appropriately allocated in the Company's original filing and therefore no adjustments have been made in this response.
The Company has provided a summary of the rate of return and relative rate of return at present rates
as an attachment labeled “ICNU_DR_075 Supplemental Attachment A”. In addition, a complete
electronic version of the cost of service study, reflecting the change described above has been provided as part of the attachment.
The result of this adjustment has a minor effect on the present return ratio’s provided to Company
witness Ehrbar for his consideration into the proposed rate spread. The Company believes the results
of this adjustment are minor and would not change the proposed rate spread in this case. ORIGINAL RESPONSE:
The electric cost of service study provided in this case allocated plant related meter costs by the
weighted current cost of meters in service. The weighting is determined by multiplying the current retirement unit cost of each equipment type by the number of units in service for each rate schedule. The total for each rate schedule is divided by the average number of customers to determine the
average cost for the schedule. The weighted cost is the comparison of each schedule’s average cost
to the lowest average cost. The weighted cost ratio is then multiplied by the number of customers
in each schedule to determine the allocation factor for metering equipment. Please see Knox Electric Cost of Service work paper pages TLK-E-143 and TLK-E-144 (work papers were provided with the

Page 2 of 2
Company’s initial filing and a duplicate copy for your convenience was included as an attachment
to ICNU_DR_052).
As Advanced Meters are placed in service the relative costs of the equipment providing service to
each rate group are expected to be captured through this process.

Communication and software pro forma investments related to the Advanced Metering Project did
not receive any special treatment in the electric cost of service study provided in this case. Communication equipment is allocated by an allocator generated within the model capturing the
assignment of operating and maintenance labor expense excluding administrative and general FERC
accounts. Computer software intangible plant is allocated by an allocator generated within the model
capturing the assignment of tangible plant in service. As stated in my testimony the allocation
methodology applied to these common plant items was derived from the methodology approved for Puget Sound Power and Light (now Puget Sound Energy) in Docket No. UE-920499.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/02/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 075 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a narrative response describing the basis for the allocation of metering costs among rate schedules in relation to the Washington Advanced Metering Project (“Project”).
RESPONSE:

The electric cost of service study provided in this case allocated plant related meter costs by the weighted current cost of meters in service. The weighting is determined by multiplying the current
retirement unit cost of each equipment type by the number of units in service for each rate schedule.
The total for each rate schedule is divided by the average number of customers to determine the
average cost for the schedule. The weighted cost is the comparison of each schedule’s average cost
to the lowest average cost. The weighted cost ratio is then multiplied by the number of customers in each schedule to determine the allocation factor for metering equipment. Please see Knox Electric
Cost of Service work paper pages TLK-E-143 and TLK-E-144 (work papers were provided with the
Company’s initial filing and a duplicate copy for your convenience was included as an attachment
to the Company’s response to ICNU_DR_052).
As Advanced Meters are placed in service the relative costs of the equipment providing service to each rate group are expected to be captured through this process.

Communication and software pro forma investments related to the Advanced Metering Project did
not receive any special treatment in the electric cost of service study provided in this case. Communication equipment is allocated by an allocator generated within the model capturing the assignment of operating and maintenance labor expense excluding administrative and general FERC
accounts. Computer software intangible plant is allocated by an allocator generated within the model
capturing the assignment of tangible plant in service. As stated in my testimony the allocation
methodology applied to these common plant items was derived from the methodology approved for Puget Sound Power and Light (now Puget Sound Energy) in Docket No. UE-920499.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/27/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 076 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that, in Avista’s 2015 general rate case (“GRC”) (UE-150204 and UG-150205), the Company anticipated that the costs for the Project would principally be applied to rate schedules
other than Schedule 25 and that many industrial customers would continue to be metered under the
Company’s existing MV-90 program.

RESPONSE:
Avista’s advanced metering program, as proposed in this case, anticipates that the allocation of the
project costs will be based on the degree of sharing of the benefits by each customer group. Please
see the Company’s response to ICNU_DR_091. At this point in time, Avista is planning to continue
the electric metering of its industrial customers (as currently applied) using its existing MV-90 system. Therefore, we expect the metering portion of the project costs, for example, to be principally
applied to the Company’s other rate schedules (other than schedule 25).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 077 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that Avista tested more than 30,000 meters from 2002-2015, but none of them were for rate Schedule 25. If the Company cannot confirm, please explain.

RESPONSE:
Avista tests every Schedule 25 meter annually.

Avista AMI Survey Follow-up with
Additional Surveys in Targeted ZIP Codes
June, 2015
Contact:
Bill Svendsen ([e-mail])
DRAFT
ICNU_DR_078 Attachment A Page 1 of 47
Test how customer opinions may have shifted since 2010 about Smart Grid
(“Grid Modernization”) and Smart Meters (“Advanced Meters”) in
Washington.
Note: 2010 results have been weighted to match the 2015 sample.
Inform Avista’s outreach and communication strategies and messaging for
2016 deployment of advanced meters across Washington state.
Segment by the collected demographics and identify geographic areas of
support versus opposition to help identify targets for initial deployment.
2015 survey goals DRAFT
ICNU_DR_078 Attachment A Page 2 of 47
Survey data was collected by telephone interviews conducted between May 26 and June 15, 2015.
A total of 1,200 interviews were completed, stratified across 6 geographic regions:
Additional interviews were conducted so as to have n=100 surveys in each of six targeted ZIP that initial results
suggested were less receptive to Smart Grid and Smart Meters (99022, 99111, 99114, 99344, 99204, 99207).
Male and female customers were equally represented.
Respondents were screened to be age 18 or older, responsible for or sharing in responsibility for
the household’s finances or budget, and not employed by a telephone, cable, utility, or petroleum
company, or a market research firm.
Methodology
Region % of Population % of Collected Sample # of Interviews
Spokane Urban 70.3%50%600
Rural North 10.3%12.5%150
Rural South 2.8%12.5%150
Rural West 7.1%12.5%150
Pullman Urban 5.4%8.3%100
Clarkston Urban 4.1%4.2%50
DRAFT
ICNU_DR_078 Attachment A Page 3 of 47
Service Territory Divided into 6 Geographic Regions
Washington service
territory divided into
6 geographic regions
Survey revealed areas of
“Strong Support”
Areas of “Mixed Support”
were identified, which
may require more
focused outreach
ICNU_DR_078 Attachment A Page 4 of 47
Areas of Strong Support
These zip codes said they
“Strongly Support” Smart
Grid and Advanced Meters
These neighborhoods could
be considered for pilots
ICNU_DR_078 Attachment A Page 5 of 47
Areas That May Require More Attention
Zip codes show higher number of
people who “Somewhat Oppose”
or “Strongly Oppose” Smart Grid
and Advanced Meters
These areas / communities may
require more focused outreach
ICNU_DR_078 Attachment A Page 6 of 47
Satisfaction with Avista Service
4 -Very
satisfied, 60%
3 -
Somewhat satisfied, 35%
2 -Not too
satisfied, 3%
1 -Not at all
satisfied, 2%
Q2. As an Avista customer, are you very satisfied, somewhat satisfied, not too satisfied, or not
at all satisfied with your overall service?
Top Box
95%
2010:
90%
With top-box satisfaction of
95% there is relatively little
room for variation; however,
these groups express
somewhat higher satisfaction:
Spokane and Clarkston
customers
Natural-gas-only
customers
Apartment dwellers
Those age 55+
Satisfaction was also higher in
Pullman in 2010.
DRAFT
ICNU_DR_078 Attachment A Page 7 of 47
Satisfaction with Avista Service –Targeted ZIP Codes
Q2. As an Avista customer, are you very satisfied, somewhat satisfied, not too satisfied, or not
at all satisfied with your overall service?
Top-box satisfaction in the targeted ZIP codes is not significantly different from overall
satisfaction, although several of the ZIPs have higher levels of “somewhat satisfied”
customers.
DRAFT
Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
Top Box 95%96%93%91%86%93%
4 -Very satisfied 65%64%55%50%43%53%
3 -Somewhat satisfied 30%32%38%41%43%40%
2 -Not too satisfied 3%4%3%7%7%3%
1 -Not at all satisfied 1%-4%2%7%3%
ICNU_DR_078 Attachment A Page 8 of 47
Importance of Utility Attributes (% rating “Very Important”)
Functional attributes are more
important than the promotion of
energy efficiency, which is in turn
more important than offering
choices or participation in the
community.
This is true across geographic
regions, housing characteristics,
and demographics (following three
pages).
Importance ratings for the top three
items were significantly lower in
2010; however, this may have
impacted by the preceding question
(concern about community issues).
28%
36%
62%
84%
89%
95%
E. Offering choices, such as solar,
or other programs like electricvehicle charges
F. Being an active, visible
member of the community
D. Promoting energy efficiency
C. Providing responsive customerservice
B. Offering reasonable rates
A. Providing reliable service
Q1. When it comes to service from your electric & natural gas utility company, is each of the
following very important, somewhat important, not too important or not at all important to you?
2010
79%
76%
65%
60%
30%
n/a
DRAFT
ICNU_DR_078 Attachment A Page 9 of 47
Importance of Utility Attributes –Targeted ZIP Codes
The targeted ZIP codes are more concerned with rates than customers overall, but
otherwise the patterns of response are similar.
DRAFT
% rating “Very Important”Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
A. Providing reliable service 98%98%94%92%95%97%
B. Offering reasonable rates 94%89%90%93%90%95%
C. Providing responsive
customer service 83%84%85%82%87%85%
D. Promoting energy
efficiency 61%62%72%81%59%69%
E. Offering choices 29%26%27%38%32%29%
F. Being an active, visible
member of the community 43%39%38%40%37%37%
Q1. When it comes to service from your electric & natural gas utility company, is each of the
following very important, somewhat important, not too important or not at all important to you?
ICNU_DR_078 Attachment A Page 10 of 47
Importance of Utility Attributes by Region
Spokane Clarkston Pullman Rural Rural Rural
Total Urban Urban Urban North South West
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
A. Providing reliable service
B. Offering reasonable rates
C. Providing responsive customer service
D. Promoting energy efficiency
E. Offering choices, such as solar, or otherprograms like electric vehicle charges
F. Being an active, visible member of thecommunity
%
r
a
t
i
n
g

“
V
e
r
y

I
m
p
o
r
t
a
n
t
”
DRAFT
ICNU_DR_078 Attachment A Page 11 of 47
Importance of Utility Attributes by Housing Characteristics
Total Urban Suburb Rural Elec Gas Both SF Du/Tri 4+ Own Rent
Only Only Home Plex Units
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
A. Providing reliable service
B. Offering reasonable rates
C. Providing responsive customer service
D. Promoting energy efficiency
E. Offering choices, such as solar, or otherprograms like electric vehicle charges
F. Being an active, visible member of the
community
%
r
a
t
i
n
g

“
V
e
r
y

I
m
p
o
r
t
a
n
t
”
DRAFT
ICNU_DR_078 Attachment A Page 12 of 47
Importance of Utility Attributes by Demographics
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
A. Providing reliable service
B. Offering reasonable rates
C. Providing responsive customer service
D. Promoting energy efficiency
E. Offering choices, such as solar, or otherprograms like electric vehicle charges
F. Being an active, visible member of thecommunity
Total <35 35 to 45 to 55 to 65+ HS or Some Coll. Post $35K $35K-$75K->$150K
44 54 64 less Coll. Grad Grad or less $75K $150K
%
r
a
t
i
n
g

“
V
e
r
y

I
m
p
o
r
t
a
n
t
”
DRAFT
ICNU_DR_078 Attachment A Page 13 of 47
Support for Initiatives (% “Strongly support”)
Support is essentially equal for the
three initiatives tested; however,
there are variations.
The chart below highlights the areas
of highest support, which tend to
mirror Pullman (or Spokane to a
lesser degree) demographics.
Support was higher in Pullman for
all three in 2010.

Total
Spokane
Urban
Pullman
Urban
Natural
gas only
Multi-
family Rent <35 35 to 44 45 to 54 Over $150K
A. Producing renewable energy 64% 66% 68% 68% 69% 67% 73% 64% 66% 64%
B. Investing in new technology to
improve energy efficiency 64% 66% 72% 69% 70% 69% 70% 70% 64% 69%
C. Investing in new technology to
improve the reliability of electricity
and natural gas service
65% 67% 58% 70% 67% 66% 65% 68% 67% 69%
Q3. Would you say that you strongly support, somewhat support,
somewhat oppose, or strongly oppose your utility doing the following?
65%
64%
64%
C. Investing in new technology
to improve the reliability ofelectricity and natural gasservice
B. Investing in new technology
to improve energy efficiency
A. Producing renewable energy
2010
63%
55%
52%
DRAFT
ICNU_DR_078 Attachment A Page 14 of 47
Support for Initiatives –Targeted ZIP Codes
The same demographic variations seen in the response to this question overall also apply to the
targeted ZIP codes.
Q3. Would you say that you strongly support, somewhat support,
somewhat oppose, or strongly oppose your utility doing the following?
DRAFT
% rating “Strongly Support”Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
A. Producing renewable
energy 54%45%52%76%65%62%
B. Investing in new
technology to improve
energy efficiency
54%59%57%71%59%56%
C. Investing in new
technology to improve
reliability
62%60%62%66%60%68%
ICNU_DR_078 Attachment A Page 15 of 47
Awareness of Smart Grid or Grid Modernization
Just under half have heard the term Smart Grid or Grid
Modernization.
Notably higher awareness is seen in:
Pullman (61%)
The Rural South Region (59%)
Among college graduates (50%)
Those with incomes over $75K (54%)
Awareness in particularly low in:
Clarkston (26%)
Among those with a HS or less education (29%)
This is higher than in 2010 (26% overall). Pullman was
higher than the rest of the state at that time also (47%).
The targeted ZIPs show the expected demographic
variations.
Q4. Have you heard the term Smart Grid or Grid Modernization?
Yes
44%No
56%
DRAFT
Colville
99114
Colfax
99111
Othello
99344
SE Spokane
99204
NW Spokane
99207
Medical Lake/Frchld AFB
99022
54%45%52%76%65%62%
ICNU_DR_078 Attachment A Page 16 of 47
Awareness of Smart Meter or Advanced Meter
About half who have heard the term Smart
Grid or Grid Modernization have also heard
of Smart Meter or Advanced Meter (23% of
the total).
Patterns of awareness are very similar to
those see for the awareness of Smart Grid
or Grid Modernization.
Although the question was asked of the
entire sample in 2010, results suggest that
awareness has increased significantly.
Again, the targeted ZIPs show the expected
demographic variations.
Q6. Have you heard the term Smart Meter or Advanced Meter?
Yes44%No
56%
Yes
53%
No
47%
Aware of Smart Grid/Grid Modernization
Aware of Smart
Meter/Advanced Meter
DRAFT
Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
49%49%43%37%47%57%
ICNU_DR_078 Attachment A Page 17 of 47
Knowledge of Smart Technologies
Q5. What is your understanding of a Smart Grid or Grid Modernization?Q7. What is your understanding of a Smart Meter or Advanced Meter?
Aware of Smart Grid/Grid Modernization Aware of Smart Meter/Advanced Meter
15%
4%
5%
5%
6%
7%
9%
13%
14%
18%
23%
27%
Other
Helps save money/lowers costs
Make people energy…
Renewable energy
Smart meter/problem solving
High tech
Prevent outages
Gives control of electricity…
Helps keep track of electricity usage
Energy efficiency
Evenly distributes electricity
Don’t know/Only heard term
12%
4%
4%
5%
8%
8%
11%
20%
32%
43%
Other
Prevent outages
Make people energy conscious/aware
Evenly distributes electricity
Charges different rates at differenttimes of day
High tech
Energy efficiency
Controls usage inhousehold/appliances/lights
Helps keep track of electricity
Check electric usage remotely/offsite
“Don’t know” was 14%
in 2015
2010
13%
46%
29%
18%
3%
<1%
5%
7%
<1%
13%
The question was asked of all respondents in 2010, so
results have re-percentaged to those giving an answer.
DRAFT
-Higher in Colville (17%)
-Higher in 99207 (28%)Higher in
Colfax &
Othello (43%)
ICNU_DR_078 Attachment A Page 18 of 47
Agreement with Arguments for Smart Grid Technology
Q8. Please tell me if you strongly agree, somewhat agree, somewhat
disagree, or strongly disagree with each of these statements.
(% “Strongly agree”)2010
A. Smart Grid technology provides information to customers about how much energy they are using and
how much it costs so the customer can make choices to save energy and money 56%33%
B. Smart Grid technology will improve reliability 44%21%
C. Smart Grid technology could reduce the frequency and duration of outages 38%23%
D. Smart Grid technology will enable more and better use of renewable energy 36%25%
E. Smart Grid technology would help reduce green house gas emissions 31%21%
F. Smart Grid technology may increase electric rates 33%19%
G. Smart Grid technology would allow your electric utility to shut off major appliances in your home 20%9%
H. Smart Grids and Smart Meters would give electric utilities control over how and when customers use
electricity 30%16%
The relative levels of agreement show a fairly nuanced understanding of the technology among customers.
As was seen with the support for the initiatives, the areas of highest agreement which tend to mirror Pullman
demographics (as was the case in 2010 as well), though Clarkston scores high on “save energy and money.”
DRAFT
ICNU_DR_078 Attachment A Page 19 of 47
Agreement with Arguments for Smart Grid Technology –
Targeted ZIP Codes (Main differences from overall highlighted)
Q8. Please tell me if you strongly agree, somewhat agree, somewhat
disagree, or strongly disagree with each of these statements.
DRAFT
% rating “Strongly Agree”Colville
99114
Colfax
99111
Othello
99344
SE Spokane
99204
NW Spokane
99207
Medical Lake/Frchld AFB
99022
A. Smart Grid technology provides information about energy use and cost 41%46%58%44%53%41%
B. Smart Grid technology will improve reliability 41%50%58%44%41%28%
C. Smart Grid technology could reduce the frequency and
duration of outages 47%46%58%31%35%34%
D. Smart Grid technology will enable more and better use of renewable energy 24%54%42%44%41%34%
E. Smart Grid technology would help reduce green house gas emissions 29%46%42%19%29%24%
F. Smart Grid technology may increase electric rates 24%29%50%25%41%34%
G. Smart Grid technology would allow your electric utility to shut
off major appliances in your home 6%21%17%6%12%28%
H. Smart Grids and Smart Meters would give electric utilities control 29%39%25%6%29%21%
Higher Lower
ICNU_DR_078 Attachment A Page 20 of 47
Support for Smart Grid Technology Investments
Q9. Given this description, do you generally support or oppose your
utility investing in smart grid technology?
All respondents were read this description,
and asked if they support or oppose
investment in this technology:
“Smart Grid or Grid Modernization is a set of
technologies that provides greater visibility
into the electric grid. For example, it can
sense system overloads and reroute power
to prevent potential outages, make the
distribution of electricity more efficient, make
it easier for renewable energy sources to
connect to the electricity grid, and give
customers near real-time energy usage
information and more control over how and
when their appliances use electricity.”
Total support (Strongly + Somewhat) shows
most of the expected variations, but support
in Clarkston is surprisingly high.
Support by Region 2010
Total 85%64%
Spokane Urban 86%
Clarkston Urban 94%
Pullman Urban 91%82%
Rural North 77%
Rural South 79%
Rural West 80%
DRAFT
ICNU_DR_078 Attachment A Page 21 of 47
Support for Smart Grid Technology Investments –
Targeted ZIP Codes
Q9. Given this description, do you generally support or oppose your
utility investing in smart grid technology?
Total support (Strongly + Somewhat) is lower than the overall result except for ZIP Code 99204,
SE Spokane.
Othello has a particularly high rate of opposition (16% Strongly + Somewhat).
DRAFT
Total support
(Strongly + Somewhat) Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
Total Support 79%86%81%87%80%80%
4 -Strongly support 38%52%51%55%49%49%
3 -Somewhat support 41%34%30%32%31%31%
2 -Somewhat oppose 6%5%8%3%7%5%
1 -Strongly oppose 7%7%8%7%2%8%
ICNU_DR_078 Attachment A Page 22 of 47
Variations in Support for Smart Grid Technology Investments
Q9. Given this description, do you generally support or oppose your
utility investing in smart grid technology?
Support by Housing Characteristics
Total 85%
Urban 87%
Suburban 88%
Rural 81%
Electric only 86%
Natural gas only 89%
Both 85%
Single 83%
Multifamily 92%
Own 84%
Rent 89%
Support by Demographics
Total 85%
<35 90%
35 to 44 85%
45 to 54 81%
55 to 64 84%
65+86%
HS or Less 84%
Some College 87%
College graduate 88%
Graduate school 82%
$35K or Less 88%
$35K to $75K 86%
$75K to $150K 89%
Over $150K 75%
DRAFT
ICNU_DR_078 Attachment A Page 23 of 47
Reasons to Support or Oppose Smart Grid Technology Investments
Q10. Why do you support your utility starting investing in Smart Grid?
Q11. Why do you oppose your utility investing in Smart Grid?
Top Reasons for Support (>5%)2010
Save power/energy efficiency 38%30%
Good idea—General 22%8%
Save money/cheaper/lower
rates 21%23%
Reliability 9%4%
Prevent outages 9%6%
Good for the environment 8%9%
Invaluable technology/we
need it 7%19%
Looking ahead to future 7%14%
Able to monitor/track usage 6%4%
Top Reasons for Opposition (>5%)*2010
Don’t want consumption
limited/controlled 25%38%
Rates would increase 16%21%
Need more information 15%15%
Unnecessary 12%13%
Too much government control 11%3%
Gives more power to
company/monopoly 10%13%
Don’t trust utility company 9%1%
Cost too much 8%10%
New technology 6%1%
* Only 124 (10%) respondents oppose these investments.
DRAFT
ICNU_DR_078 Attachment A Page 24 of 47
Support for Smart Meter Installations
Q12. Given this description, do you generally support or oppose your
utility investing in smart meters or advanced meters?
Respondents were read this description, and
asked if they support or the installation of
Smart Meters:
“Avista plans to install Smart Meters or
Advanced Meters across areas they serve in
Washington state –beginning in 2016.
Smart Meters are advanced metering
technology that are installed in homes and
businesses and that work together with
Smart Grids. Smart Meters provide
customers with real time information on
electricity use, the ability for utilities to offer
different rate plans to customers and digital
meter reading can be done remotely.”
Total support (Strongly + Somewhat) shows
most of the expected variations.
Support by Region 2010
Total 78%64%
Spokane Urban 79%
Clarkston Urban 78%
Pullman Urban 87%77%
Rural North 69%
Rural South 71%
Rural West 75%
DRAFT
ICNU_DR_078 Attachment A Page 25 of 47
Support for Smart Meter Installations –
Targeted ZIP Codes
Q9. Given this description, do you generally support or oppose your
utility investing in smart grid technology?
Total support (Strongly + Somewhat) is lower than the overall result in Colville, Colfax, and Othello.
The Spokane ZIPs (99204 and 99207) are at the overall average, and 99022 is somewhat above.
DRAFT
Total support
(Strongly + Somewhat) Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
Total Support 74%74%71%76%76%81%
4 -Strongly support 38%41%45%44%38%38%
3 -Somewhat support 36%33%26%32%38%43%
2 -Somewhat oppose 8%6%5%6%12%6%
1 -Strongly oppose 9%10%12%13%3%3%
ICNU_DR_078 Attachment A Page 26 of 47
Variations in Support for Smart Meter Installations
Q12. Given this description, do you generally support or oppose your
utility investing in smart meters or advanced meters?
Support by Housing Characteristics
Total 78%
Urban 79%
Suburban 82%
Rural 73%
Electric only 80%
Natural gas only 85%
Both 75%
Single 80%
Multifamily 86%
Own 76%
Rent 81%
Support by Demographics
Total 78%
<35 86%
35 to 44 81%
45 to 54 74%
55 to 64 75%
65+75%
HS or Less 72%
Some College 78%
College graduate 80%
Graduate school 82%
$35K or Less 76%
$35K to $75K 82%
$75K to $150K 85%
Over $150K 73%
DRAFT
ICNU_DR_078 Attachment A Page 27 of 47
Reasons to Support or Oppose Smart Meter Installations
Q13. Why do you support your utility investing in smart meters or advanced meters?
Q14. Why do you oppose your utility investing in smart meters or advanced meters?
Top Reasons for Support (>5%)2010
Save power/energy efficiency 29%25%
Save money/cheaper/lower rates 24%24%
Good idea—general 21%13%
Able to monitor usage 13%5%
Makes people energy
conscious/awareness 10%13%
Can monitor usage
remotely/offsite 8%2%
Invaluable technology/we need it 8%14%
Benefits customers/the consumer 7%4%
Top Reasons for Opposition (>5%)*2010
Rates would increase 29%22%
Don’t want consumption limited/controlled 20%25%
Expensive 13%15%
Need more information 12%12%
Unnecessary 10%13%
Gives the government too much control 9%4%
Invasion of privacy 8%9%
Bad idea—General 6%4%
Gives more power to company/monopoly 6%11%
* Only 180 (15%) respondents oppose these investments.
DRAFT
ICNU_DR_078 Attachment A Page 28 of 47
Willingness to Pay for Opting Out
Opting out was described to the 15% of respondents
opposed to Smart Meter technology as:
“If you oppose smart meters or advanced meters,
you may have the opportunity to “opt out.” Avista is
still working out the details of what this would
involve. However, most opt-out programs across the
nation typically require these customers to pay an
additional fee to cover the cost of having your meter
read manually. For example, Avista currently has an
“opt out” policy in Oregon that costs customers $51
per month. If you chose to “opt out,” would you be
willing to pay extra to cover this cost?”
Nearly two-thirds (64%) would not choose to opt out.
The low opt-out rates in 99114, 99204, and 99207
are likely income-driven. 99022 is higher income
and an above-average supporter of Smart Meters.
Q15. Would you be willing to pay extra to cover this cost?
Yes
15%
Yes, but
not that
much
9%
No
64%
DK
12%
The 15% who would opt out represent
2.2% (27 out 1,200) of all customers
DRAFT
Colville
99114
Colfax
99111
Othello
99344
SE Spokane
99204
NW Spokane
99207
Medical Lake/Frchld AFB
99022
-6%12%5%13%-
ICNU_DR_078 Attachment A Page 29 of 47
Concerns About Smart Meters (among all customers)
Concern is low on all three of the issues tested.
Concern is lowest in Pullman and among those under the age of 35 –on
average, about half of these numbers.
Q16. On a scale of 1 to 5, with 1 being “not at all concerned” and 5 being “very concerned” -
-Do you have any concerns about Smart Meters related to the following:
16%
22%
12%
9%
10%
5%
C. Accuracy perceptions between digital meters
compared to conventional meters.
B. Privacy concerns about the type of information
being collected by the utility and communicated…
A. Health concerns related to perceptions about
radio frequency emissions.
5 - Very concerned 4
DRAFT
ICNU_DR_078 Attachment A Page 30 of 47
Concerns About Smart Meters -Targeted ZIP Codes
Colville and Othello customers -who have the lowest levels of
educational attainment -express the highest levels of concern.
Q16. On a scale of 1 to 5, with 1 being “not at all concerned” and 5 being “very concerned” -
-Do you have any concerns about Smart Meters related to the following:
DRAFT
Total support
(Strongly + Somewhat) Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
A. Health concerns 15%18%30%15%20%18%
B. Privacy concerns 42%28%50%23%33%38%
C. Accuracy perceptions 34%21%32%18%30%21%
ICNU_DR_078 Attachment A Page 31 of 47
Value of Expected Benefits (% saying “Highly Valuable”)
The more functional
benefits –reduced outage
length, conservation ideas,
energy use info -are more
valuable than the others.
This is true across
geographic regions,
housing characteristics, and
demographics (following
three pages).
Q17. A number of customer benefits are expected to come with smart meters. In general, would
you find each of the following features highly valuable, somewhat valuable, or not valuable?
32%
32%
35%
44%
49%
74%
C. Energy alerts that you can receive via text or email to let you know how much
energy you’ve used at any given time
F. The possibility for future benefits such astime-of-use rates or pre-pay options.
E. Increased privacy because no one hasto visit your property each month to readyour meter
A. Access to view and analyze your near
real-time energy use information through a
website
B. Energy conservation tips that you canchoose to implement to help manage your
energy usage
D. Reduced power outage times becausesmart meters can notify Avista when poweris out
DRAFT
ICNU_DR_078 Attachment A Page 32 of 47
Value of Expected Benefits –Targeted ZIP Codes DRAFT
% rating “Highly Valuable”Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
A. Access to view and analyze energy use 22%41%48%57%46%40%
B. Energy conservation tips 35%39%59%62%53%40%
C. Energy alerts 15%29%40%44%30%27%
D. Reduced power outage times 62%66%78%80%72%71%
E. Increased privacy 27%32%36%34%38%27%
F. The possibility for future benefits 19%33%38%43%33%26%
Higher Lower
Q17. A number of customer benefits are expected to come with smart meters. In general, would
you find each of the following features highly valuable, somewhat valuable, or not valuable?
ICNU_DR_078 Attachment A Page 33 of 47
Value of Expected Benefits by Region
Spokane Clarkston Pullman Rural Rural Rural
Total Urban Urban Urban North South West
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
D. Reduced outage times
B. Conservation tips
A. Real-time energy use
E. Increased privacy
F. Future benefits
C. Energy alerts%
r
a
t
i
n
g

“
V
e
r
y

V
a
l
u
a
b
l
e
”
DRAFT
ICNU_DR_078 Attachment A Page 34 of 47
Value of Expected Benefits by Housing Characteristics
Total Urban Suburb Rural Elec Gas Both SF Multi-Own Rent
Only Only Home Family
%
r
a
t
i
n
g

“
V
e
r
y

V
a
l
u
a
b
l
e
”
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
D. Reduced outage times
B. Conservation tips
A. Real-time energy use
E. Increased privacy
F. Future benefits
C. Energy alerts
DRAFT
ICNU_DR_078 Attachment A Page 35 of 47
Value of Expected Benefits by Demographics
Total <35 35 to 45 to 55 to 65+ HS or Some Coll. Post $35K $35K-$75K->$150K
44 54 64 less Coll. Grad Grad or less $75K $150K
%
r
a
t
i
n
g

“
V
e
r
y

V
a
l
u
a
b
l
e
”
0%
10%
20%
30%
40%
50%
60%
70%
80%
90%
100%
D. Reduced outage times
B. Conservation tips
A. Real-time energy use
E. Increased privacy
F. Future benefits
C. Energy alerts
DRAFT
ICNU_DR_078 Attachment A Page 36 of 47
Preferred Sources of Information
Total of
1st/2nd/3rd 1st Choice
Information mailed directly to you 74%41%
Email updates 65%27%
Website with info, FAQ, other resources 50%16%
Avista text message 30%5%
Small group neighborhood meetings 22%4%
Avista spokesperson 21%4%
Community business leader 7%<1%
DK 3%
Q18. As Avista gets closer to installing Smart Meters in your area, which of these would be the way you would MOST prefer
to receive information and learn more? What would be your second choice? What would be your third choice?
Note: There is little variation in these choices.
DRAFT
ICNU_DR_078 Attachment A Page 37 of 47
Preferred Sources of Information –Targeted ZIP Codes
Q18. As Avista gets closer to installing Smart Meters in your area, which of these would be the way you would MOST prefer
to receive information and learn more? What would be your second choice? What would be your third choice?
Note: There is little variation in these choices.
DRAFT
Total support
(Strongly + Somewhat) Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
Information mailed directly to you 83%80%90%66%83%84%
Email updates 49%53%49%72%61%62%
Website with info, FAQ, other resources 35%44%41%52%44%40%
Avista text message 21%19%37%42%32%24%
Small group neighborhood meetings 22%29%22%25%17%23%
Avista spokesperson 27%25%19%7%24%23%
Community business leader 6%7%9%9%6%9%
DK 6%4%2%3%3%3%
Except for 99204, the targeted ZIP codes strongly prefer to have information mailed
directly to them.
ICNU_DR_078 Attachment A Page 38 of 47
Demographics by Region DRAFT
Total
Spokane
Urban
Clarkston
Urban
Pullman
Urban
Rural
North
Rural
South
Rural
West
Type of Area
Suburban 38%46%38%30%11%8%13%
Urban 31%37%22%32%11%9%15%
Rural 28%14%36%37%75%80%68%
Avista Services
Electric and natural gas 52%57%78%48%27%37%30%
Electric only 40%34%20%46%67%56%53%
Natural gas only 7%7%2%1%4%5%15%
Type of Dwelling
Single family dwelling;75%72%88%47%93%93%93%
A duplex or triplex; or 7%7%8%15%2%1%3%
In a building with 4+ units 17%21%4%37%3%5%3%
ICNU_DR_078 Attachment A Page 39 of 47
Demographics by Region –Targeted ZIP Codes DRAFT
Total
Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
Type of Area
Suburban 38%10%8%14%21%30%21%
Urban 31%17%18%17%68%58%12%
Rural 28%69%68%61%6%5%63%
Avista Services
Electric and natural gas 52%34%56%11%31%60%46%
Electric only 40%61%42%86%64%34%47%
Natural gas only 7%2%1%-3%4%6%
Type of Dwelling
Single family dwelling;75%86%86%93%34%72%90%
A duplex or triplex; or 7%5%6%-9%8%3%
In a building with 4+ units 17%7%8%5%56%19%6%
ICNU_DR_078 Attachment A Page 40 of 47
Demographics by Region (continued)
Total
Spokane
Urban
Clarkston
Urban
Pullman
Urban
Rural
North
Rural
South
Rural
West
Ownership
Own 68%63%76%46%90%87%83%
Rent 32%36%24%54%9%12%15%
Have High Speed Internet
Yes 79%82%70%90%64%69%70%
DRAFT
ICNU_DR_078 Attachment A Page 41 of 47
Demographics by Region –Targeted ZIP Codes
Total Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
Ownership
Own 68%82%77%78%34%59%83%
Rent 32%17%23%21%63%40%16%
Have High Speed Internet
Yes 79%64%78%68%78%74%74%
DRAFT
ICNU_DR_078 Attachment A Page 42 of 47
Demographics by Region (continued)
Total
Spokane
Urban
Clarkston
Urban
Pullman
Urban
Rural
North
Rural
South
Rural
West
Family Size
Median family size 2.57 2.59 2.40 2.63 2.53 2.46 2.63
Respondent Age
Age <35 25%29%10%49%7%9%7%
35-44 12%14%2%6%7%8%11%
45-54 13%12%22%7%15%15%14%
55-64 19%17%20%12%25%23%27%
65+26%23%42%20%39%41%32%
Household Income
Median HH Income $51.7K $54.6K $33K $50.9K $44.5K $46.5K $49.5K
DRAFT
ICNU_DR_078 Attachment A Page 43 of 47
Demographics by Region –Targeted ZIP Codes
Total
Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
Family Size
Median family size 2.57 2.35 2.51 2.81 2.16 2.69 2.70
Respondent Age
Age <35 25%6%15%13%38%36%8%
35-44 12%6%10%16%14%15%16%
45-54 13%10%11%13%9%13%23%
55-64 19%22%21%21%19%11%17%
65+26%49%42%28%14%18%28%
Household Income
Median HH Income $51.7K $25.0K $51.8K $45.5K $40.6K $38.2K $54.8K
DRAFT
ICNU_DR_078 Attachment A Page 44 of 47
Demographics by Region (continued)
Total
Spokane
Urban
Clarkston
Urban
Pullman
Urban
Rural
North
Rural
South
Rural
West
Education
Some high school 2%1%6%5%1%5%
Graduated high school 13%11%26%2%25%24%21%
Trade or Technical school 4%4%2%3%5%5%6%
Some college 23%22%20%23%29%23%27%
College graduate 37%40%30%39%23%32%25%
Graduate school 17%18%16%33%8%11%10%
DRAFT
ICNU_DR_078 Attachment A Page 45 of 47
Demographics by Region –Targeted ZIP Codes DRAFT
Total
Colville
99114
Colfax
99111
Othello
99344
SE
Spokane
99204
NW
Spokane
99207
Medical Lake/
Frchld AFB
99022
Education
Some high school 2%6%2%12%1%2%3%
Graduated high school 13%30%19%18%12%20%13%
Trade or Technical school 4%6%4%7%5%6%6%
Some college 23%27%30%31%25%21%30%
College graduate 37%21%28%17%33%35%33%
Graduate school 17%6%17%11%22%13%10%
ICNU_DR_078 Attachment A Page 46 of 47
Functional attributes (reliable service, reasonable rates, good customer service) are more important than
the promotion of energy efficiency, which is in turn more important than offering choices or participation
in the community.
This is true across geographic regions, housing characteristics, and demographics
Support is essentially equal –nearly two-thirds “Strongly support” -for renewable energy, investments to
improve reliability, and investments to improve energy efficiency.
44% of customers are aware of Smart Grid, and 23% of Smart Meter technologies.
Support for Smart Grid investments and Smart Meter installations is high (85% and 78%, respectively).
15% of respondents opposed to Smart Meter technology would pay to opt out of the program,
representing 2.2% of all customers surveyed (27 out of 1,200).
In terms of perceived value, the more functional benefits –reduced outage length, conservation ideas,
energy use info -are more valuable than the other, more abstract benefits.
Throughout the survey data, support is highest among younger customers (<35, in particular) and those
with higher educations (college graduate+) and incomes ($75K or more)..
The additional surveys targeted by ZIP code confirm that demographics are the primary driver of
attitudes towards Smart Grid and Smart Meters.
Key Findings DRAFT
ICNU_DR_078 Attachment A Page 47 of 47

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Heather Rosentrater
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 078 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Regarding Avista’s 2015 customer survey of 1,200 Washington customers concerning the Project, please: a) provide the survey results; and b) identify how many Schedule 25 customers were
surveyed.

RESPONSE:
a) Please see ICNU_DR_078 Attachment A.
b) No Schedule 25 customers participated in the survey.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 079 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please confirm that large industrial customers already have sophisticated time-of-use-ready meters. If the Company cannot confirm, please explain why Avista publicly made this statement
in comments filed in Docket UE-060649, on August 11, 2006 (see p. 2).

RESPONSE: Schedule 25 customers all have meters on the Company’s MV90 system and are billed from
interval data. Since we bill from interval data, we have the ability to create Time of Use (TOU)
billing windows from the interval data and bill accordingly.

Page 1 of 1
AVISTA UTILITIES
WASHINGTON ELECTRIC
PRESENT & PROPOSED RATES OF RETURN BY RATE SCHEDULE
12 MONTHS ENDED SEPTEMBER 30, 2015
Present Rates Base Proposed Rates
Present Present Tariff Proposed Proposed
Line Type of Sch.Rate of Relative Proposed Rate of Relative
No.Service Number Return ROR Increase Return ROR
(a)(b)(c)(d)(e)(f)(g)
1 Residential 1 3.30%0.55 8.4%4.79%0.63
2 General Service 11/12 11.92%1.98 7.0%13.82%1.81
3 Large General Service 21/22 8.96%1.49 7.5%10.72%1.40
4 Extra Large General Svc.25 6.23%1.0342 6.8%7.86%1.0282
5 Pumping Service 30/31/32 5.01%0.83 8.6%6.58%0.86
6 Street & Area Lights 41-48 5.32%0.88 10.2%6.90%0.90
7 Total 6.02%1.00 7.8%7.64%1.00
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/13/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 080 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 7:13-19. Please confirm that the only rate schedule which Avista does not propose to move closer to the overall rate of return (unity) is Schedule 25. If the Company cannot confirm,
please explain.

RESPONSE:
The Company did propose to move Schedule 25 approximately 17.5% closer to unity, but due to
rounding to two decimal points Table No. 3 in my testimony made it look as if the present and
proposed rates of return were both 1.03. The table below is a revised Table No. 3 which shows the
relative rates of return for Schedule 25 taken out to four decimal points. The percentage move going from 1.0342 to 1.0282 is 17.5%.1

1 Calculation = (0.0282 – 0.0342)/0.0342 = 17.54% movement.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/13/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 081 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 15:13-15, 22-23. Please confirm that Avista is proposing uniform percentage increases to Schedule 25 energy blocks that are higher than the Company’s overall proposed increases to
Schedule 25. If the Company cannot confirm, please explain.

RESPONSE:
The Company’s proposed increases to the energy blocks as well as the variable demand rate for
Schedule 25 are higher than the overall proposed increase to Schedule 25. This is the result of the
Company proposing to keep the monthly minimum demand charge at $21,000 per month.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/12/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Jeanne Pluth
TYPE: Data Request DEPT: State and Fed. Regulation
REQUEST NO.: ICNU – 082 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 20:6-9. Please provide (or identify workpapers containing) the specific dates on which Avista expects the six parcels of land to be placed into service, including all supporting
documentation.

RESPONSE:
Please see ICNU_DR_082-Attachments A-C. These are the workpapers that were provided with
Company witness Ms. Smith’s workpapers in the original filed case. Currently, there are no
specific dates scheduled since the timing is primarily dependent on the needs of the system to
reliably serve our customers. The attached information provides a range of dates using the
information at the current time.

Avista – Plant Held for Future Use
ICNU_DR_082-Attachment B Page | 1
Garden Springs:
Property was purchased adjacent to Avista’s Garden Springs 115 kV switching station in order to prepare
for a new 230/115 kV Substation to be constructed. This new substation is needed as a second 230 kV
source for the west Spokane system. Presently, Avista has only one 230/115 kV station providing load
support into Spokane from the west. This new Garden Springs Substation will allow for much better
transmission system reliability as well as operational flexibility and future capacity as electric load
continues to grow west of Spokane in both Avista’s and Inland Power & Light’s service areas.
Additional property was required to upgrade the existing switching station from a 3-terminal overhead
strain bus and air switch configuration to a standard substation bus and breaker configuration. Plans for
the 230 kV addition required enough property to be purchased such that we could confirm the location
for new 230 kV line terminations from the north. Planning is in progress for a 230 kV transmission
interconnection with BPA and preliminary line routing to the site. Expected timeframe for the new
substation is within the next 10-15 years.

Hillyard:
We purchased the Hillyard 115/13 kV Substation property in advance of the new North Spokane
Corridor Freeway construction in order to be prepared for future load growth and to be better prepared
for service on the east side of the new freeway. Even without the freeway and potential load growth
expected for the area, the adjacent substations are nearing capacity from a system reliability and
operational flexibility perspective. This Hillyard site is almost directly between the adjacent substations
and will provide the needed capacity for load growth in northeast Spokane and will allow for better
reliability to transfer load between substations when required for outages, planned maintenance, and
better system operations. Load growth over the next 5 years will determine the timing for the new
station within 5-10 years.

Downtown West:
As load grows to the west of Spokane, and particularly in the new Kendall Yards area on the north bank
of the Spokane River northwest of downtown Spokane, additional 115/13 kV substation capacity will be
required. The Downtown West site is along the existing 115 kV transmission line corridor and is in a
perfect location between three adjacent subs to provide the needed capacity, improved reliability, and
operational flexibility for the foreseeable future. In 2016, the substation yard will be encompassed with
a security wall in preparation for the future station, which is planned to be in service within the next 5-
10 years.

Avista – Plant Held for Future Use
ICNU_DR_082-Attachment B Page | 2
Downtown East:
Property on the east side of downtown Spokane was purchased for a new 115/13 kV substation in
preparation for the new University District. This planning has proven to be accurate as the University
District is well under construction and projections are for considerable load growth. This substation site
is perfectly located adjacent to an existing 115 kV transmission line and will be able to provide any
needed capacity and reliability requirements for the U-District. The new substation is expected to be
energized in the next 5-10 years as load increases and projects plans are finalized with load projections
determined.

Avista Corp
ICNU_DR_082-Attachment C Page 1 of 2

Greensferry Road Site for
Potential Natural Gas-Fired Combustion Turbine
December 3, 2015

Avista’s 2015 Electric Integrated Resource Plan (IRP) shows a need for electric generation by the end of
2020 to meet additional projected customer demand. To meet this demand, the 2015 IRP recommends
investing in a natural gas-fired combustion turbine, similar to others in our system. The 2015 IRP was
filed with the public utility commissions in Washington and Idaho in August 2015.

To meet the projected resource need, Avista purchased land on Greensferry Road in Rathdrum, Idaho,
continue our analysis and expect to issue a Request for Proposal
(RFP) in 2018 to evaluate all prudent, cost-effective options for
meeting the generation and energy needs of our customers.

Avista is now in the early stages of developing the 2017 Electric IRP
which will provide updated guidance on the amount of additional
generation and conservation needed to meet growing customer
demand through 2037, along with the preferred resources for
meeting that need.

Key Messages
• Purchasing and optioning land for future use is part of our normal
course of business which preserves cost-effective options and
flexibility in meeting the future needs of customers.

• Avista has purchased land on Greensferry Road in Rathdrum,

What is an IRP?
An Integrated Resource Plan (IRP
details projected growth in demand
for energy, new resources and
conservation needed to serve our
customers over the next 20 years. IRP is updated on a two-year cycle.

The 2015 IRP is on our website at
www.avistautilities.com/IRP.

gas generating facility based on the projected customer demand shown in the 2015 Electric IRP,
which was filed with the utility commissions in Washington and Idaho in August 2015.
• Avista is currently in the early stages of developing the 2017 Electric IRP which will provide updated
guidance on the amount of additional generation and conservation needed to meet customer demand
through 2037 and the preferred resources for meeting that need.

• Avista expects to issue a RFP in 2018 and will evaluate all prudent, cost-effective options for meeting
the energy and capacity needs of our customers, including potentially constructing a natural gas
generating facility on the Greensferry Road site.

-over-

Avista Corp
ICNU_DR_082-Attachment C
Page 2 of 2

Questions and Answers

Why is a Rathdrum area location being considered?
A major natural gas pipeline and Avista’s electric transmission lines are both located in the Rathdrum
vicinity, making it a preferred and cost-effective area for a natural gas generating facility. There are
also other natural gas generating facilities in the area.

Why is Avista purchasing land now for a generating facility it may not build?
There is a long lead time in developing, designing, permitting and constructing any new generating
facility. Property and related resources are challenging, but important prerequisites for this effort.
Acquiring property now gives Avista the flexibility to meet future customer demand in a timely way that
balances cost, reliability, rate volatility and renewable resource requirements.

Does the site need to be rezoned to construct a generating facility?
Yes. To shorten the construction timeline in the event a generating facility is built, Avista will likely
submit a request in 2016 to rezone the site back to its former industrial designation.
Is Avista starting the permitting process now?
Preliminary research on permitting requirements may occur over the next few years, as part of the site
analysis and feasibility studies.

Will Avista need to acquire new water rights for a possible future facility?
Avista is exploring water supply options as part of the feasibility studies for a potential natural gas
generating facility.
Will customer rates increase because of the need to build or acquire additional generation?
A key factor in determining the preferred resource strategy, but not the only one, is cost. However, all
new generation resources are likely to be more expensive than the average cost of our current
generation resources.

Why is Avista considering building a fossil fuel generating facility rather than wind or solar?
The 2015 IRP identifies a need for additional capacity which is the type of generation that can be
turned on or off when needed to meet customer demand. Because the wind does not always blow or
the sun does not always shine, wind or solar are not dependable. This is especially true during
extreme winter or summer temperatures. Wind or solar can’t be counted on to meet demand during
peak periods. That means backup generation would be needed to supplement these resource
resulting in a greater cost to customers than construction of a traditional plant such as a natural gas-
fired combustion turbine.

ICNU_DR_083 Attachment A Page 1 of 10
ICNU_DR_083 Attachment A Page 2 of 10
ICNU_DR_083 Attachment A Page 3 of 10
ICNU_DR_083 Attachment A Page 4 of 10
ICNU_DR_083 Attachment A Page 5 of 10
ICNU_DR_083 Attachment A Page 6 of 10
ICNU_DR_083 Attachment A Page 7 of 10
ICNU_DR_083 Attachment A Page 8 of 10
ICNU_DR_083 Attachment A Page 9 of 10
ICNU_DR_083 Attachment A Page 10 of 10

19
OTHER COMPANY EXPENSE
POLICIES:
The following information provides specific guidance on the accounting for certain expenses.
Board of Director Expenses
Board of Director Fees

Beginning in 2011, 90% of Avista Corp. / Avista Utility director fees will be charged to the Utility or “Above
the Line” FERC Account 930200. The remaining 10% will be charged to Non-Utility, or “Below the Line”
FERC Account 426. This sharing represents the appropriate allocation of director fees paid to the Board
of Directors during the year based on the historical level of Utility versus Non-Utility activities involving
directors.

Annually thereafter, a survey of all Avista Corp. Directors will be completed to determine the appropriate
percentage split between Utility/Non-Utility, based on the average of the individual Board Member’s time
spent on Utility versus Non-Utility activities while serving on the Avista Corp. Board.

Director Fee expenses paid for Advantage IQ Board meetings to Corporate Board of Director members
shall be charged to Non-Utility FERC Account 426.

Board of Director Meeting Costs

Board members are required to travel or incur other expenses from time to time to conduct Company
business. The purpose of this Policy is to ensure that adequate cost controls are in place that, travel and
other expenditures are appropriate, and to provide a uniform and consistent approach for the coding of
expenses incurred for board of director expenses.

Based on specific guidelines discussed below, beginning in 2011, 90% of Avista Corp. / Avista Utility
director meeting costs will be charged to the Utility or “Above the Line” FERC Account 930200. The
remaining 10% will be charged to Non-Utility, or “Below the Line” FERC Account 426. This sharing
represents the appropriate allocation of director meeting costs for the Board of Directors during the year
based on the historical level of Utility versus Non-Utility activities involving directors.

Facility Costs
90% of costs associated with the rental or use of room, equipment, etc. for board meeting activities will be
charged to the Utility or “Above the Line” to FERC account 930200. The remaining 10% will be charged to
Non-Utility, or “Below the Line” FERC Account 426.

ICNU_DR_083 AAttachment B Regulatory Accounting Guidelines and Policies Manual Page 1 of 1

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 083 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 24:16-18. Please explain why a 90%/10% split for director fee expenses are currently recorded on the Company’s books, given the Commission’s decision in Order 05 of the
Company’s 2015 GRC (“Order 05”), ¶ 220, in which the Commission decided to “continue to
authorize only 50 percent of director fees and meeting costs in both electric and natural gas rates.”

RESPONSE:
Please refer to Ms. Smith’s direct testimony (JSS-1T) page 25 for the Company’s justification of
using a 90%/10% sharing of director fees during the test period and the proposed 97%/3% sharing for
the 2017 and 2018(6-month) rate period.
The Commission stated in Order 05 of the Company’s 2015 GRC at ¶ 220 “Avista has not presented
substantial evidence as to why this practice should be modified. Absent such a showing, we continue
to authorize only 50 percent of director fees and meeting costs in both electric and natural gas rates.”
In Ms. Smith’s testimony (JSS-1T) she provided support for the Company’s 90/10 allocation of director fees. Each year the directors complete an estimate of time spent on utility and non-utility
operations based on their actual experience. In the aggregate, the most recent survey completed in
November 2015, showed a result of 97%/03% split between utility and non-utility operations. Please
see ICNU_DR_083 Attachment A for a copy of these estimates for 2015. The Company remained
conservative in their accounting of these costs by continuing to split director fees 90% utility and 10% non-utility.

The 90% utility 10% non-utility split is consistent with the Company’s current internal Regulatory
Accounting Guidelines. This sharing represented the allocation of director fees paid to the board of
directors during the year based on prior historical level of utility versus non-utility activities involving directors. Please see ICNU_DR_083 Attachment B for a copy of those guidelines pertaining to
director fees.

Note that director fees are system common costs which are shared amongst Avista’s jurisdictions
in which the Company operates. No other jurisdiction has imposed a 50%/50% split on the Company’s director fees expense. The Company has appropriately recorded these expenses using
90%/10% sharing based on past survey results, and adjusted this sharing within individual
jurisdictional rate cases.

As noted in Ms. Smith’s testimony, fees paid to directors are part of the compensation package offered to attract and retain qualified officers and directors. Similarly, D&O insurance is a

Page 2 of 2
necessary cost which, in Docket Nos. UE-090134 and UG-090135 Order No. 10, the Commission
approved the Company’s 90%/10% split for D&O Insurance.
Recovery of only 50% of director fees and costs does not appropriately recognize the ordinary cost
of doing business as a large, publicly-traded company, requiring substantial oversight
responsibilities of an independent board of directors. While it is reasonable to apportion some of
the directors fees and costs to unregulated operations, that should reflect a true assessment of the
extent of any director involvement in unregulated operations of the Company. As described above, each director is surveyed in order to assess the amount of time dedicated to unregulated
activities; the most recent survey is a 97/3 overall split. To assign a greater 50% disallowance is
unreasonable.

Nor is it reasonable to arbitrarily disallow a large portion of these costs on the basis that shareholders should bear a share of these expenses. These are costs incurred in the ordinary
course of business that cannot be avoided. The Company, as a publicly-traded company must be
able to attract and retain a qualified board of directors to provide required oversight and
independent guidance. The Company does not have the option to refuse to incur these costs, any
more than it does to refuse to pay its taxes or provide salaries to its employees; all are costs of doing business.

The question of whether the Company is paying a fair and reasonable amount for such service has
been answered by the independent compensation studies performed by Milliman that benchmarks
director fees against other similarly-situated companies that compete for the talents of board-members.

In the final analysis, a reasonable level of Director fees must be paid in order to attract and retain
directors, who are required for the independent oversight of compliance and governance.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 084 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 24:16-17. Please confirm that the Company’s restatement of “director fee expenses to reflect a 97% Utility / 3% non-utility split” is contrary to the Commission’s decision in Order 05 at
¶ 220. If the Company cannot confirm, please explain.

RESPONSE:
The Commission stated in Order 05 of the Company’s 2015 GRC at ¶ 220 “Avista has not presented
substantial evidence as to why this practice should be modified. Absent such a showing, we continue
to authorize only 50 percent of director fees and meeting costs in both electric and natural gas rates.”
The Company has provided evidence to justify its 97%/03% sharing of director fees at Direct Testimony of Ms. Smith (JSS-1T, page 25). See ICNU_DR_083 for further explanation and
justification of its sharing.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/15/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 085 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 24:16-18. Relative to the 90%/10% split currently recorded on the Company’s books, how much would director fee expenses be decreased if Avista reflected a 50% Utility / 50% non-utility split?
RESPONSE:
The reduction from expenses included in the test year would be $293,329 WA Electric and $84,992 WA Gas
if the Company included a 50%/50% split for director fees. (Approximately $308,000 WA Electric and
$89,000 WA Natural gas revenue requirement.)

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/13/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Annette Brandon
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 086 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to 28:10-29:6. Please identify and describe all changes to the Executive Short Term Incentive Plan relative to the Company’s 2015 GRC.

RESPONSE:
There have been no changes to the Executive Short Term Incentive Plan relative to the
Company’s 2015 GRC.

The Executive Short Term Incentive Plan includes metrics related to Earnings-Per-Share
(excluded from the Company’s filing with costs borne by shareholders), O & M cost per customer, Customer Satisfaction, Reliability, and Response Time. These metrics, and the
weighting of each metric, is consistent with the Company’s 2015 GRC.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/19/2016
CASE NO.: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 087 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to Exh. No. HLR-1T at 9:9-11. Please confirm that the Company’s recent experience
implementing advanced metering in Pullman, Washington, did not include industrial customers. If the
Company cannot confirm, please explain.

RESPONSE:
The company did not install new advanced metering equipment for any Schedule 25 customers (extra-
large or industrial customers) in Pullman, Washington, as part of its smart grid project.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/19/2016
CASE NO.: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 088 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to Exh. No. HLR-1T at 12:28-13:3. Please confirm that the Company will be replacing
existing electric meters for all 23 Schedule 25 customers as part of the Project. If the Company
cannot confirm, please identify any Schedule 25 customers which will not have existing electric
meters replaced as part of the Project.
RESPONSE:
The company will not be replacing any schedule 25 customers’ meters as part of the Washington
AMI project.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/19/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: Federal & State Regulation
REQUEST NO.: ICNU – 089 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to Exh. No. HLR-1T at 15:24-25. What is the rate of penetration of advanced electric meters for
industrial applications, according to the report referenced?
RESPONSE:
The reported rate of expected penetration of advanced metering referenced in the above testimony is for
residential metering only. The subject report did not discuss or provide rates of penetration for industrial
applications (customers).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/25/2016
CASE NO.: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 090 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to Exh. No. HLR-1T at 17:18-20 and 20:4-6. In Order 05, ¶ 193, the Commission noted that Avista had testified in October 2015 (i.e., at hearing) that the Project “business case analysis was accurate with ‘plus-or-minus-50-percent’ uncertainty in costs.” Please provide a narrative response:
a. Identifying the plus-or-minus-percentage of cost accuracy for the recently updated Project business
case; and
b. Explaining how, in the five months between the referenced testimony and the filing of the 2016 GRC, the Company was able to reduce the Project’s “‘plus-or-minus-50-percent’ uncertainty in costs.”
RESPONSE:
a. The Company’s current business case has a contingency amount of 15.4% included in its estimate
of the project capital costs. This contingency represents Avista’s best estimate of the upward cost
uncertainty at this stage in the development of the project.
b. In the elapsed time between the subject hearing and the filing of the Company’s current business case, Avista further refined project technical specifications, received pricing for many systems and
components from vendors responding to the Company’s formal Request for Proposals (“RFP”). As
we developed a better understanding of the system specifications we were also able to make much more detailed estimates of Avista’s labor requirements. All of these measures have contributed to our greater confidence in the filed cost estimates.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/27/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 091 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Exh. No. HLR-1T at 18:3-10 and n. 17, citing the Commission’s Interpretive and Policy Statement in Docket UE-060649 (“Policy Statement”). Please indicate, accompanied by all
supporting documentation related to the Project, whether the Company specifically addressed the
following factors previously considered by Avista and/or to be considered by the Commission in
evaluating advanced metering projects:
a. Likelihood that metering will be cost-effective for all customer classes (Policy Statement at ¶ 24);
b. Propriety of meters for each of Avista’s customers (Policy Statement at ¶ 31);
c. Varying circumstances of each Avista customer class (Policy Statement at ¶ 32); and
d. “Equity in the distribution of any bill savings or costs among the customer classes” (Policy
Statement at ¶ 33).
RESPONSE:
Avista’s advanced metering project will provide our customers with cost effective benefits,
consistent with the applicable portions of the subject policy statement, particularly having to do with the implementation of AMI, the provision of net metering capabilities for customers, energy
conservation, and the consideration of implementing time of use rates. Since the policy statement
addresses factors outside the scope of advanced metering, such as development of diverse fossil fuel
and renewable fuel supplies, not all portions of the federal rules the policy statement addresses are
applicable to the project.
a. Avista’s business case demonstrates that the Washington AMI project will produce positive
net benefits for our customers. As examples, the benefits of AMI that reduce the duration of
electric system outages, or save energy through implementation of conservation voltage
reduction, benefit all customers, regardless of class. Other benefits, such as the elimination
of manual meter reading, benefit Avista’s residential and commercial customers. b. Avista’s advanced metering business case is consistent with the subject policy statement.
The Company’s plan at this point in time is to maintain the MV-90 metering system used to
measure usage and billing determinants for our industrial customers.
c. The Company’s AMI business case is consistent with the subject policy statement. Any
proposal to implement time-of-use rates in the future will be supported by an analysis of the costs and benefits of the proposal overall, and for each of its customer classes, as designed.
d. Please see Avista’s response to part “a” above.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/19/2016
CASE NO.: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 092 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to Exh. No. HLR-3 at 22. Please provide further detail, including specific time periods according
to customer rate schedules, of the Company’s planned installation of commercial metering.

RESPONSE: The company plans to launch the installation of advanced meters for its commercial customers at the same time it begins the installation of residential meters, in June 2017. Avista expects to have completed
the installation of residential meters in 2019, and commercial meters by Q4 2020, though a small portion
of the commercial installations could be completed as late as Q1 2021.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/19/2016
CASE NO.: UE-160228 & UG-160229 WITNESS: Heather Rosentrater
REQUESTER: ICNU RESPONDER: Larry La Bolle
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 093 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to Exh. No. HLR-3 at 25. Please provide a narrative response describing and detailing all
communications, to date, tailored to industrial customers and any subsets within the industrial customer
class in relation to the Project.

RESPONSE:
The company has initiated no advanced metering communications to date that have been tailored to our
industrial customers. Avista’s communications with these customers are performed by our Account
Executive staff. The Company will provide its Account Executives with materials describing the Washington Advanced Metering Project so they can provide an overview of the Project as well as be responsive to any questions from their industrial customer clients. These communication materials will
be provided to the Account Executives once details around the deployment schedule are more complete.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/06/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies/Karen Schuh
REQUESTER: ICNU RESPONDER: Margie Stevens
TYPE: Data Request DEPT: Finance
REQUEST NO.: ICNU – 094 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s response to ICNU Data Request (“DR”) 013. ICNU requested “all … documentation and any associated studies” pertaining to “the establishment of proposed capital
budgets by senior management.” In response, the Company provided no documentation supporting
its narrative response other than a confidential five-year financial forecast. Is ICNU correct in
understanding that there are no minutes or any other documentation recording “the establishment of
proposed capital budgets by senior management”? If no, please explain and provide all such documentation.
RESPONSE:

Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 094C. Please note that Avista’s response to ICNU – 094C is Confidential per Protective Order in UTC Dockets 160228
& UG-160229.
The Finance Committee of the Board of Directors approves the next year’s capital budget as shown in
the excerpt below of the most recent meeting minutes. The Board of Directors approved a capital budget of $407.1 million in November 2015 and approved an updated capital budget of $415.3 million
in February 2016.

Below are excerpts from the November 5, 2015 and February 4, 2016 Finance Committee of the
Board minutes of each meeting:
November 5, 2015 – See Avista’s response to ICNU_DR_094C.

February 4, 20161 - See Avista’s response to ICNU_DR_094C.

Please also see the Company’s response to ICNU_DR_013, where the Company discussed factors that
influenced senior management’s consideration of the proposed capital budget, in witnesses’ testimony
throughout this case. The Company has prepared a Virtual Data Room, as in previous cases, which houses the complete
Finance Committee meeting minutes. Please contact Paul Kimball via email –
[e-mail] – to get the required login and password information.

1 February 2016 minutes represents draft minutes that will be finalized at the May 13, 2016 Board meeting.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/28/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 095 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s responses to ICNU DRs 010, 036 and 037. Please provide a response to ICNU DR 037 that provides a quantification of benefits for each customer class schedule, similar to the
isolation of Schedule 25 quantified benefits in the response to ICNU DR 010, using the same
class schedule differentiation provided in response to ICNU DR 036 (i.e., 001; 011/012; 021/022;
025; 031/032; 41-48). If the Company cannot, please explain why the Company was able to
isolate direct incentives paid to Schedule 25, yet cannot isolate direct incentives paid to other schedules.

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 095C. Please note that
Avista’s response to ICNU – 095C is Confidential per Protective Order in UTC Dockets 160228
& UG-160229.

The Company was able to provide the information for Schedule 25 customers in the format provided in response to ICNU_DR_010 because the information for projects for those customers
are tracked in the Company’s SalesLogix customer relationship management system. However,
while SalesLogix is also used to track a majority of the energy efficiency projects for non-
residential customers (Schedules 11/12, 21/22, 31/32, 41-48), it is not the only system of record.
For example, the Company has contracted with SBW Consulting to deliver a small business program. The data and savings from that 3rd party program is provided to Avista by SBW and
tracked outside of SalesLogix.

Further, residential energy efficiency projects (including low-income program savings) are
tracked in the Company’s customer information system (CSS prior to 2015, and Customer Care and Billing from 2015 to present). Given the additional systems that store the requested data,
we are not able to provide all of the data requested in the format requested.

Attached as ICNU_DR_095C Confidential Attachment A is the data requested (in electronic
format), by rate schedule for Schedules 11/12, 21/22, 31/32, 41-48, for those projects that were tracked in SalesLogix similar to the Schedule 25 projects. The data provided in the Company’s response to ICNU_DR_037 does provide, albeit in a different format than requested, the direct
incentives paid to residential, low-income, and nonresidential (which includes Schedule 25). It
is in the three segments listed above that Avista tracks and reports savings to its utility
commissions and external Advisory Group. Please also see the Company’s response to ICNU_DR_037 and 124.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 096 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s response to ICNU DR 041. Please provide a narrative response:
a. Containing specific detail as to why “systematic benefits would be difficult to quantify whether
customers benefit in the exact same way at all times”; and
Explaining what would complete, in the Company’s view, the referenced “incomplete analysis”
pertaining to “judging the equity of DSM.”
RESPONSE:
The Company’s energy efficiency programs provide benefits to all customers as these programs
help to alleviate the need for more expensive generation resources. That being said, it is not feasible to determine how the system benefits accrue to each and every individual customer as each
customer would need to be analyzed individually. Please see the Company’s response to
ICNU_DR_037 for the system electric avoided cost.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/04/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 097 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s responses to ICNU DRs 037 and 044. Please:
a. Explain why, in response to ICNU DR 037, the Company provides system benefits amounts
without express reference to site-specific programs, while in response to ICNU DR 044, Avista
states that the Company separately analyzes the cost-effectiveness of site-specific programs in
“measuring the system benefits”; and
Indicate and explain whether direct incentives paid to the “Nonresidential” segment referenced in the Company’s response to ICNU DR 037 includes incentives for both “non-residential” and “site-
specific” programs, as referenced in the Company’s response to ICNU DR 044.

RESPONSE:
In the Company’s response to ICNU_DR_044, the Company stated “The Company, as well as our
third party evaluator, separately analyzes the cost-effectiveness of residential, non-residential, and
site-specific programs.”
The response should have stated ‘The Company, as well as our third party evaluator, separately
analyzes the cost-effectiveness of residential, non-residential, and limited income programs.

The site-specific programs are reviewed by the Company and our third party evaluator, but are done
so under the “Nonresidential” segment. The Nonresidential segment incentives included in the Company’s response to ICNU_DR_037 do contain incentives related to site-specific program
offerings, as well as prescriptive incentive payments.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Karen Schuh
REQUESTER: ICNU RESPONDER: Karen Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 098 Supplemental TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s responses to ICNU DRs 071 and 002. Please provide an updated version of the Handy-Whitman index, as a file containing the index values, listed by major plant categories by
year, as provided in response to ICNU DR 039 in Docket UE-150204, the Company’s 2015 general
rate case (“GRC”) (see Avista’s response in this proceeding to ICNU DR 002, ICNU_DR_002
Attachment A).
RESPONSE:
The Company has not prepared this information in this format. The company will supplement this
data response when this information becomes available. Supplemental:
Please see ICNU_DR_098 Supplemental Attachment A for the requested updated version of the
Handy-Whitman index as provided in the Company’s response to ICNU_DR_039 in Docket UE-150204.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/06/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Scott Morris/Karen Schuh
REQUESTER: ICNU RESPONDER: Karen Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 098 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s responses to ICNU DRs 071 and 002. Please provide an updated version of the Handy-Whitman index, as a file containing the index values, listed by major plant categories by
year, as provided in response to ICNU DR 039 in Docket UE-150204, the Company’s 2015 general
rate case (“GRC”) (see Avista’s response in this proceeding to ICNU DR 002, ICNU_DR_002
Attachment A).
RESPONSE:
The Company has not prepared this information in this format. The company will supplement this
data response when this information becomes available.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/06/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Karen Schuh
REQUESTER: ICNU RESPONDER: Karen Schuh
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 099 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s responses to ICNU DRs 072 and 011. Based on real/relative cost, as opposed to nominal cost, please confirm that the overall 50-year cost differential of replacing plant and
equipment facilities has been trending downward (e.g., the cost differential from 1965 to 2015
is lower than from 1943 to 1993). If the Company cannot confirm, please explain and provide
documentation that would support a static or upward trend.
RESPONSE:
The cost of installing equipment is higher today than it was fifty years ago. Therefore, the level of
depreciation built into rates today is not sufficient to cover the additional cost of new plant units.
For example, as shown below in the Distribution Equipment – Account 364 Poles from the Handy
Whitman Index, for the parameters given above between 1965 and 2014 (2015 not yet available)
index value of a pole is still 10 times higher in 2014 than in 1965. For the second parameter from
1943 to 1993 is almost 18 times higher than in 1943.
Distribution Account 365 - Poles
Parameter 1 :
Year Index Value of Pole
1965 $9.65
2014 $100.00
Prameter 2 :
Year Index Value of Pole
1943 $3.16
1993 $55.41

Please also see the Company’s response to ICNU_DR_11 and ICNU DR_072 where the
Company explained that the cost of installing equipment is higher today than it was fifty years ago. The primary point is the level of depreciation built into rates today is not sufficient to
cover the additional cost of new plant units.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/27/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Pat Ehrbar
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 100 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s response to ICNU DR 073 and Avista’s confidential response to ICNU DR 057. Please explain why the Company states that Avista has 32 Schedule 25 customers in response to
ICNU DR 073, but provides a different number of customers when responding to ICNU DR 057,
subpart a, which requests “[a] list of all customers receiving service under” Schedule 25.

RESPONSE:
The response to ICNU DR 073 included both Washington and Idaho Schedule 25 customer count.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/27/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Pat Ehrbar
REQUESTER: ICNU RESPONDER: Linda Gervais
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 101 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s response to ICNU DR 077. Please explain the Company’s response, given Avista’s response to Public Counsel/Energy Project DR 026 in the Company’s 2015 GRC (Docket
UE-150204), in which Avista did not indicate that testing had been performed for any Schedule 25
meters.

RESPONSE:
Public Counsel/Energy Project DR 026 in the Company’s 2015 GRC (Docket UE-150204) request
asked:
“Identify the actual number of slow run or failed meters for each customer class identified by
Avista for each year 2000-2015 to date.”

Avista responded to the actual number of slow run or failed meters identified through its meter
testing program. Schedule 25 meters are tested annually and have not been identified as slow run, nor have they been identified as a failed meter.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 102 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:
Refer to Avista’s response to ICNU DR 083. The Company quotes Order 05 of the Company’s
2015 GRC at ¶ 220, where the Commission stated: “Avista has not presented substantial evidence
as to why this practice should be modified. Absent such a showing, we continue to authorize only
50 percent of director fees and meeting costs in both electric and natural gas rates.” (Emphasis
added). ICNU understands the Company’s response to ICNU DR 083 as purporting to explain how Avista has provided the “showing” necessary to justify authorization, in this proceeding, for the
inclusion of more than 50% of director fees and meeting costs in proposed rates. Notwithstanding,
ICNU does not understand Avista’s response to explain how the Company obtained authority to
“currently” record a 90%/10% split for director fees in present rates, which were authorized by the
Commission in Order 05 to include “only 50 percent of director fees.” If ICNU is misunderstanding the Company’s response to ICNU DR 083 in any respect, please explain through
a narrative response.

RESPONSE:
As the Company had explained in its response to ICNU_DR_083, “The 90% utility 10% non-utility
split is consistent with the Company’s current internal Regulatory Accounting Guidelines. This
sharing represented the allocation of director fees paid to the board of directors during the year based
on prior historical level of utility versus non-utility activities involving directors. … Note that director fees are system common costs which are shared amongst Avista’s jurisdictions in which the Company
operates. No other jurisdiction has imposed a 50%/50% split on the Company’s director fees expense.
The Company has appropriately recorded these expenses using 90%/10% sharing based on past survey
results, and adjusted this sharing within individual jurisdictional rate cases.” (emphasis added)
Also noted, was that the 90% utility / 10% non-utility split was more representative of the actual time
spent by the board of directors and therefore a 90% utility and 10% non-utility split provides the most
accurate cost sharing for accounting purposes. In reference to ¶ 220, the Commission stated that they
“continue to authorize only 50 percent of director fees and meeting costs in both electric and natural gas rates” (emphasis added.) The Commission did not rule on the Company’s accounting policies but
rather ordered the appropriate percentages to be reflected in electric and natural gas present rates.
Dollars recorded in the Company’s accounting records can be different than what is included in retail
rates per the Commission’s oderes.
The Company has proposed in this proceeding, and included further support, for a revised allocation of
97% Utility /3% non-utility based on current information, to be included in the rates established for the
18 month rate plan proposed by Avista.

Page 1 of 2
2017 2017 Difference:
Pro Forma Studies Attrition Studies
Service
(see Exh. Nos.
JSS-2 & 3, page 10)
(see Exh. Nos.
EMA-2 & 3, page 12)
WA Electric 11,843$ 38,568$ 26,725$
WA Natural Gas (1,151)$ 4,397$ 5,548$
*The amounts shown here are the resulting "Attrition Adjustments" necessary above the Pro
Forma Study results required for Avista to earn its requested Rate of Return of 7.64%.
Resulting Attrition
Adjustment*
Pro Forma versus Attrition Study Results
Revenue Requirement Above Current Rates (000s)
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 103 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

In Avista’s 2015 general rate case, Docket UE-150204, the Commission approved an attrition allowance as an adjustment to the Company’s revenue requirement, calculated using the
Commission’s traditional modified historical test period methodology. Please identify, in the
Company’s present filing, the Avista’s proposed revenue requirements, calculated using the
Commission’s traditional modified historical test year methodology and excluding an attrition
allowance adjustment. Please identify each and every restating and pro-forma revenue requirement adjustment supported by the Company to arrive at the modified historical test year results. Please
perform this analysis separately for gas and electric service.

RESPONSE: Ms. Andrews’ testimony Exhibit No. (EAM-1T), starting at page 13, line 15, discusses that in
conjunction with preparing the Company’s electric and natural gas Attrition Studies, the Company
performed a revenue requirement analysis or “Pro Forma Study” based on a modified historical test
period, adjusted to reflect limited adjustments. The results of the “Pro Forma” Studies in comparison to the Company’s “Attrition” Studies, and “Difference: Resulting Attrition Adjustment” was shown in Ms. Andrews’ Table No. 3 (reproduced below).

Table No. 3 (see page 14, Exhibit No. _(EMA-1T))

Ms. Smith, within her testimony, exhibits and detailed supporting workpapers, provides the Company’s electric and natural gas Pro Forma Studies, as well as, explanations and analysis of each restating and pro forma adjustment included by the Company. See Smith testimony at Exhibit
No. _(JSS-1t), page 4, lines 8-23; page 6 lines 1-23; “Electric Standard Commission Basis and

Page 2 of 2
Restating Adjustments” starting at page 13 line 16 through page 31, line 8; “Electric Pro Forma
Adjustments” starting at page 31, line 9 through page 40, line 8; “Natural Gas Standard
Commission Basis and Restating Adjustments: starting at page 55, line 8 through page 64, line 5; and “Natural Gas Pro Forma Adjustments” starting at page 64, line 6 through page 69, line 4. See
also Exhibit Nos. __(JSS-2) and __(JSS-3), specifically, pages 6 through 10 of both studies show
the revenue requirement produced from a modified historical test period approach, adjusted only for
limited pro forma adjustments.1

1 As explained by Ms. Smith, the Company has also provided electric and natural gas “Cross Check Studies” that adjust the “Pro Forma Study” results, identified in Table No. 3, recognizing additional expected increases in expenses and
capital investment identified by the Company beyond the Pro Forma Study. These Cross Check Studies provide the level of net income and net rate base expected for the 2017 and January to June 2018 rate periods. These balances are
then compared to the results produced by the Attrition Studies for comparison purposes only, to determine the reasonableness of the results produced by the Attrition Studies, and for the limited purpose of preparing the cost-of-
service studies as presented by Company witnesses Ms. Knox and Mr. Miller. The Cross Check Study values readily lend themselves to the cost-of-service analysis. See Exhibit Nos. _(JSS-2) and _(JSS-3), pages 11-12 (2017) and pages
13-14 (January to June 2018).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 104 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide the Company’s Washington Commission Basis Report (“CBR”) for gas and electric service in Excel format for the following calendar years: 2011, 2012, 2013, 2014, and 2015.

RESPONSE:
Please see the following Attachments:

ICNU_DR_104 – Attachment A – 2011 Electric CBR
ICNU_DR_104 – Attachment B – 2011 Natural Gas CBR
ICNU_DR_104 – Attachment C – 2012 Electric CBR
ICNU_DR_104 – Attachment D – 2012 Natural Gas CBR

ICNU_DR_104 – Attachment E – 2013 Electric CBR
ICNU_DR_104 – Attachment F – 2013 Natural Gas CBR
ICNU_DR_104 – Attachment G – 2014 Electric CBR
ICNU_DR_104 – Attachment H – 2014 Natural Gas CBR

ICNU_DR_104 – Attachment I – 2015 Electric CBR ICNU_DR_104 – Attachment J – 2015 Natural Gas CBR

These attachments are being provided in electronic format only.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: Liz Andrews
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 105 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s September 2015 Electric CBR. Please provide an explanation of why restating adjustment 1.02 (relating to deferred debits and credits) in the Company’s CBR is
different than adjustment 1.02 in Ms. Smith’s pro forma revenue requirement study (see the
workpaper titled “Pro Forma 09.2015 WA Electric Model.xlsx”)

RESPONSE:
Adjustment 1.02 “Deferred Debits and Credits” included within annual Commission Basis Reports
(CBR) includes necessary adjustments compared to the jurisdictional results of operations
necessary to adjust the regulatory deferred debit and credit rate base balances and regulatory amortizations as approved by the Commission for that reporting year. Within the annual CBR this adjustment typically is minor in nature as the proper level of amortization expense and offsets to
rate base for each item is properly recorded within the Company’s annual jurisdictional results of
operations (ROO).
As noted within Ms. Smith’s testimony, in her restating Adjustment 1.02, see Exhibit _(JSS-1T), starting at page 15, line 7 – page 18, line 28, certain of the “Deferred Debit/Credit” asset balances
(net of Accumulated Deferred Federal Income Tax (ADFIT)) are adjusted (from 2015 test period
AM balances) to reflect the balances expected during the 2017 rate period on an AMA basis.
Deferred Debit/Credit Adjustment 1.02 reduces the following deferred debit asset balances to their appropriate 2017 level: Settlement Exchange Power; Restating CDA Settlement Deferral; Restating CDA/SRR (Spokane River Relicensing) CDR Deferral; Restating Spokane River Deferral;
Restating Spokane River PM&E Deferral; Restating Montana Riverbed Lease; and Restating
Lancaster Amortization. Also included in this adjustment is a reduction for regulatory
amortizations expiring prior to the 2017 rate year. Expiring amortizations include: Montana Riverbed Lease Deferral, Lancaster Deferral, 2011 Colstrip and Coyote Springs 2 Thermal Maintenance Expense Deferral, BPA Settlement Deferral, Canada to Northern California (CNC)
Transmission Project Deferral, LiDAR O&M Expense Deferral and the Wartsila Generator (Small
Gen) Expense Deferral.
Each of these adjustments are described in Ms. Smith’s testimony and workpapers associated with each deferred item in Adjustment 1.02 is provided at workpaper section 1.02. The overall rate base
reduction from adjusting deferred balances from AMA 2015 to AMA 2017 totaled -$6.3 million.
The overall reduction for expiring regulatory amortizations is -$1.7 million. 1

1 The reduction in rate base and amortization expense to reflect 2017 AMA Deferred Debit/Credit balances and 2017 expired amortizations was also included in the Company’s electric Attrition model as discussed by Ms. Andrews at
Exhibit No. _(EMA-1T), page 40, lines 6-16, and page 42 lines 4-9.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 106 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference “I. UE_AVA Dir Evidence-(Feb16)\3. UE_AVA WP's (Feb16)\L. UE__Smith WP(AVA-Feb16)\Elec. WP's\PF_CC-PROPERTY TAX\3) 2017 - Property Tax ADJ.xlsx.” Does
the Company agree that the value in Tab “E-CPT-1,” cell “I13,” represents the restated property tax
expense of $20.6 million, not the 2016 pro forma property tax expense of $21.7 million? If yes,
please indicate whether this is an error in the Company’s calculations.
RESPONSE:
The Company agrees that the value in cell C113 contains an error and should reflect the 2016 level
of expense not the restated expense value from cell C113 in the Pro Forma Property Tax adjustment
3.06 (E-PPT). This correction would reduce the 2017 Electric Cross Check Property Tax expense by $620,000. This correction has no impact on the Company’s Electric Pro Forma Study1. Also
note that the 2017 Cross Check Study was provided as a “cross check” only to the Electric 2017
Attrition Study and therefore has no impact on the requested revenue requirement.

1 This error was isolated to the Electric Cross Check Study and did not impact the Natural Gas Studies.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 107 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify each and every asset that the Company sold or retired between January 2014 and March 2016, where the transaction resulted in proceeds (or a write-off) in excess of $100,000.
Please include detail of the date on which the asset was retired or sold and the proceeds or loss from
the transaction.

RESPONSE:
Please see ICNU_DR_107 Attachment A for the requested information. See also Restating
Adjustment 2.09 “Net Gains/Losses” which reflects a ten-year amortization of net gains realized
from the sale of real property disposed of between 2006 and September 20, 2015. See Company witness Smith, Exhibit No._(JSS-1T) page 23 for discussion and accompanying Smith workpapers
filed with the direct case.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 108 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please re-provide the Company’s response to ICNU Data Request (“DR”) 23, including a field for the transaction date, and including a description for each of the revenue entries booked to Federal
Energy Regulatory Commission (“FERC”) account 456.

RESPONSE: Please see ICNU_DR_0108 Attachment A. The Company’s internal accounting system does not
provide a transaction description for revenue entries in FERC 456. However, we have provided the
following journal descriptions pertaining to FERC 456:

• REVCOL – Records Avista’s share of revenue from sale of surplus vehicles, misc. scrap by
Talen Energy, operator of Colstrip Power Plant.

• REVPGE – Records monthly service revenue from Spokane Energy per PGE Capacity Contract.

• REVREC – Records revenue from Renewable Energy Credit (REC) sales. Avista sells and purchases RECs for both optimization and compliance purposes
• REVESALES – Account 456020 ED AN (Other Electric Rev-Sale of Excess BPA Transm)
on the REVESALES journal (record Wholesale Sales Revenue), pertains to the sale of transmission that we have purchased from Bonneville Power Administration (BPA) under a long term point to point agreement, but we were not in need of during the month. This
account is used to record the sale of transmission to other parties.

• REVDECOUPLING USD DL JOURNAL –Records the deferred revenue from the decoupling mechanism. The decoupling mechanism breaks the link between electric/gas
sales and the recovery of fixed costs. Conservation efforts by the company will not impact
the recovery of fixed costs.

• REVTRAN USD DL JOURNAL –Records monthly transmission revenue.
• REVFUEL – Records Gas physical, financial, and intracompany sales transactions related
to managing natural gas purchase and sale transactions.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/03/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 109 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please re-provide the Company’s response to ICNU DRs 24 and 25, including detail for each and every FERC account. Both reports are missing a large number of FERC accounts (e.g., 447, 465,
502, etc.).

RESPONSE: Please see ICNU_DR_109 Attachment A. Detail for each FERC account is provided within this
attachment on a total transaction amount (System as requested in ICNU_DR_024) and Washington
Electric and Washington Gas (as requested in ICNU_DR_025).
Due to the high volume of data in this request, information is being provided electronically only.
Allocation factors and calculation is provided on the tab labeled ‘transaction detail with formula’.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennnifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 110 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference the Company’s response to ICNU DR 25. Does the Company agree that its results include approximately $2.5 million in expense booked to account 925100, injuries and damages, in
the test period?

RESPONSE: The Company agrees to the amount identified above. Please also see ICNU_DR_111 for a
transaction detail of the Injuries and Damages accrual included in the Company’s Electric Injuries
and Damages restating adjustment (2.05 E-ID).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 111 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference “I. UE_AVA Dir Evidence-(Feb16)\3. UE_AVA WP's (Feb16)\L. UE__Smith WP(AVA-Feb16)\Elec. WP's\INJURIES & DAMAGES\1) 2015 inj & dam adj.xls.” Please provide
transaction-level detail supporting the amount of $0.3 million in injuries and damages expense
included in results pursuant to tab “C-ID-4,” cell “E6.”

RESPONSE: Please see ICNU_DR_111 Attachment A for the requested information.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 112 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide transaction-level detail, in a format consistent with the Company’s response to ICNU DR 23 (including a transaction date and a description for all entries), for the following FERC
accounts:
a. 537
b. 539
c. 465
d. 920
e. 923
f. 408.1
g. 408.2
RESPONSE: Please see ICNU_DR_112 Attachment A. See “Transaction Detail” provided in electronic file only for detailed information. Upon review of the 408 detail, the Company identified that the amount
included in the company’s Property tax adjustment contained an error where $24,128.58 of
property tax expense should have been excluded from the Company’s adjustment. This amount
reflects payments of 2013 property tax expense. The effect of this error overstates the property tax adjustment by $22,702 (WA Gas).
[Service Date December 29, 2008]
BEFORE THE WASHINGTON STATE
UTILITIES AND TRANSPORTATION COMMISSION

(consolidated)

Synopsis: The Commission approves and adopts the Multi-party Settlement
Stipulation entered into among Avista, the Commission’s Staff, Northwest Industrial
Gas Users, and The Energy Project, and, in part, the Industrial Customers of
Northwest Utilities as a reasonable resolution of Avista’s request for increases in
electric and natural gas rates.

The Settlement resolves the issue of what rates consumers will pay commencing
January 1, 2009, for electric and natural gas service provided by Avista. The
Commission finds reasonable the parties’ agreed $32.5 million, or 9.1 percent rate
increase, in annual electric revenues, and a $4.8 million, or 2.4 percent, rate increase
in annual natural gas revenues. The Commission requires Avista to file electric
service and natural gas service tariff sheets in compliance with the terms and
conditions of the Settlement.
ICNU_DR_113 Attachment A Page 1 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 2
ORDER 08

TABLE OF CONTENTS

SUMMARY .................................................................................................................. 3
MEMORANDUM ......................................................................................................... 4
I. Background and Procedural History ...................................................................... 4
II. Proposed Multi-party Settlement ........................................................................... 7
III. Standard for Review ........................................................................................ 9
A. Settlements. ..................................................................................................... 9
B. Ratemaking Principles. ................................................................................. 10
IV. Discussion and Decision ............................................................................... 10
A. Joint Parties’ Adjustments to Original Filing. .............................................. 11
1. Federal Income Tax (FIT) Adjustment. ................................................. 11
2. Depreciation. .......................................................................................... 16
B. Settlement Provisions. ................................................................................... 22
1. Power Supply-Related Adjustments: ..................................................... 22
2. Other Revenue Requirement Adjustments. ............................................ 24
4. Revenue Requirement. ........................................................................... 24
Dollars in thousands .............................................................................. 25
5. Reclassification of Non-Legal Asset Removal Obligations (AROs). .... 26
6. Settlement with the Coeur d’Alene Tribe. ............................................. 28
V. Conclusion..................................................................................................... 33
FINDINGS OF FACT ................................................................................................. 33
CONCLUSIONS OF LAW ......................................................................................... 34
ORDER ....................................................................................................................... 35
APPENDIX A ............................................................................................................. 37
MULTI-PARTY SETTLEMENT STIPULATION .................................................... 37

ICNU_DR_113 Attachment A Page 2 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 3
ORDER 08

SUMMARY

1 NATURE OF PROCEEDING. On March 4, 2008, Avista Corporation d/b/a Avista
Utilities (Avista or Company) filed with the Washington Utilities and Transportation
Commission (Commission) revisions to its currently effective Tariff WN U-28,
Electric Service, in Docket UE-080416, and revisions to its currently effective Tariff
WN U-29, Gas Service, in Docket UG-080417. The proposed revisions would
implement a general rate increase of $36.6 million, or 10.3 percent, for electric
service and $6.6 million, or 3.3 percent, for gas service. The Commission suspended
the filings on March 6, 2008, consolidated the two dockets, and set the dockets for
hearing.

2 MULTI-PARTY SETTLEMENT. On September 16, 2008, Avista, the
Commission’s regulatory staff (Commission Staff or Staff) Northwest Industrial
Gas Users (NWIGU), and The Energy Project filed a Multi-party Settlement
Stipulation (Settlement) resolving all disputed issues between those parties. The
Settlement, if approved and adopted by the Commission, would resolve all issues in
the proceeding and allow Avista to recover in rates an increase in annual electric
revenue of $32.5 million (9.1 percent) and an increase in annual natural gas revenue
of $4.8 million (2.4 percent). Industrial Customers of Northwest Utilities (ICNU)
joins in part, and opposes in part, the Settlement’s terms and conditions. Public
Counsel opposes the Settlement.

1In formal proceedings, such as this, the Commission’s regulatory staff functions as an
independent party with the same rights, privileges, and responsibilities as other parties to the
proceeding. There is an “ex parte wall” separating the Commissioners, the presiding
Administrative Law Judge, and the Commissioners’ policy and accounting advisors from all
parties, including regulatory staff. RCW 34.05.455.

ICNU_DR_113 Attachment A Page 3 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 4
ORDER 08

3 APPEARANCES. David Meyer, attorney, Spokane, Washington, represents Avista.
Greg Trautman and Michael Fassio, Assistant Attorneys General, Olympia,
Washington, represent Staff. Ron Roseman, attorney, Seattle, Washington, represents
The Energy Project. Chad Stokes, attorney, Portland, Oregon, represents NWIGU.
Irion Sanger, attorney, Portland, Oregon, represents ICNU. Simon ffitch, Assistant
Attorney General, Seattle, Washington, represents Public Counsel.

4 COMMISSION DETERMINATION. The Commission finds on the basis of the
evidence presented that Avista requires rate relief for its electric and natural gas
service operations and determines that the Settlement results in a reasonable
resolution of the issues in this proceeding and is in the public interest. The rates that
will result from adoption and approval of the Settlement are fair, just, reasonable, and
sufficient.
MEMORANDUM
I. Background and Procedural History

5 Avista provides electric and natural gas service within a 26,000 square mile area of
eastern Washington and northern Idaho including approximately 231,000 electric
customers and 143,561 natural gas customers in Washington.

6 Avista filed tariffs on March 4, 2008, designed to increase electric and natural gas
rates by $36.6 million (10.29 percent) and $6.6 million (3.33 percent), respectively.
The Commission suspended the operation of these tariff revisions by Order 01 entered
March 6, 2008, pending an investigation and hearing concerning the proposed
changes and whether they are just and reasonable. Avista’s initial request was based
on:

A test year ending December 31, 2007.

An overall rate of return of 8.43 percent.

A rate of return on common equity of 10.8 percent.

A capital structure with 46.3 percent common equity.
ICNU_DR_113 Attachment A Page 4 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 5
ORDER 08

Total pro forma electric operating revenues of $448 million; a $36.6
million (10.3 percent) increase.

Total electric rate base of $951 million.

Total pro forma natural gas operating revenues of $206 million; a $6.6
million (3.3 percent) increase

Total natural gas rate base of $173 million.

7 The Commission conducted a prehearing conference on March 28, 2008, and on April
3, 2008, entered Order 02, Prehearing Conference Order, granting various pending
petitions to intervene, authorizing formal discovery, entering a protective order, and
establishing a procedural schedule. On June 16, 2008, the Commission entered a
Notice of Hearing scheduling public comment hearings in Pullman and Spokane,
Washington, on September 18, 2008.

8 On July 28, 2008, Avista filed a Motion for Leave to File Supplemental Testimony,
including supplemental testimony and exhibits based on updated financial data and
power cost inputs which increased its revised electric revenue requirement to $47.7
million. However, Avista did not revise its tariff filing to increase its “as-filed”
revenue requirement. Public Counsel opposed the Motion for Leave to File
Supplemental Testimony. On August 8, 2008, the Commission entered Order 04,
Order Granting the Motion for Leave to File Supplemental Testimony.

9 On September 16, 2008, Avista, Commission Staff, NWIGU, and The Energy Project
(collectively referred to as the “settling parties”) filed a Settlement. The Settlement,
if approved and adopted by the Commission, would resolve all issues in this
proceeding and allow Avista to recover in rates an increase in annual electric revenue
of $32.5 million (9.1 percent) and an increase in annual natural gas revenue of $4.8
million (2.4 percent).

10 ICNU supports, in part, and opposes, in part, the Settlement. Public Counsel opposes
the Settlement. ICNU and Public Counsel (collectively referred to as the “joint
parties”) filed joint responsive testimony on September 19, 2008. The joint parties
ICNU_DR_113 Attachment A Page 5 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 6
ORDER 08

proposed 11 adjustments, including some to Avista’s original filing that purported to
support an electric revenue requirement of $20.1 million, or a 5.6 percent increase,
and a natural gas revenue requirement of $.63 million or a .32 percent rate increase.2
Their proposed adjustments included: adopting a consolidated tax adjustment that
reduces Avista’s federal income tax rate; modifying depreciation expense; sharing the
cost of Director’s and Officer’s (D&O) insurance between shareholders and
ratepayers; disapproving the costs of the confidential litigation; reclassifying non-
legal asset removal obligations (AROs), removing certain advertising, administrative
and general (A&G), and charitable contribution expenses; removing half of Avista’s
claim for directors’ compensation and all claims for shareholder services expenses;
disallowing certain dues and membership fees; and, reducing executive
compensation.

11 On September 23, 2008, the settling parties, except ICNU, filed joint testimony in
support of the Settlement. On September 26, 2008, the Commission convened a
second prehearing conference to consider revising the procedural schedule in light of
the settling parties’ request that the Settlement be approved effective January 1, 2009.
By Order 06, Prehearing Conference Order, entered October 8, 2008, the Commission
established a revised procedural schedule and scheduled this matter for hearing
November 6, and 7, 2008.

12 On October 10, 2008, the joint parties filed testimony in response to the Settlement
adhering to the recommendations in their responsive testimony. On October 22,
2008, Avista filed rebuttal and Staff filed cross-answering testimony opposing the
joint parties’ testimony. On November 5, 2008, the joint parties filed a corrected
exhibit on behalf of their witness, Michael Majoros. On November 6, 2008, and
again on November 10, the joint parties filed a second and third corrected exhibit on
behalf of Mr. Majoros. On November 19, 2008, the joint parties filed a revised
exhibit on behalf of witness Charles King. On November 21, 2008, the joint parties
filed a fourth corrected exhibit on behalf of Mr. Majoros.

2 At hearing, Public Counsel and ICNU corrected some computational errors that increased the
proposed electric revenue requirement to $24.8 million and the gas revenue requirement to $3.47
million. The joint parties’ revised revenue requirement is fully discussed later in this Order.
ICNU_DR_113 Attachment A Page 6 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 7
ORDER 08

13 The Commission conducted public comment hearings in Pullman and Spokane,
Washington, on September 18, 2008. One consumer presented testimony in Pullman,
ten consumers presented testimony in Spokane, and more than 1,700 consumers filed
written comments largely in opposition to the proposed rate increase.3

14 The parties prefiled extensive testimony and exhibits sponsored by 25 witness,
including 19 for Avista, two for Staff, one for NWIGU, one for The Energy Project,
and two by the joint parties. The Commission convened an evidentiary hearing in this
consolidated proceeding at Olympia, Washington on November 6, 2008, before
Chairman Mark H. Sidran, Commissioners Patrick J. Oshie and Philip B. Jones and
Administrative Law Judge Patricia Clark. Altogether, the record includes more than
192 exhibits entered during the evidentiary hearing. Avista, Staff, Public Counsel,
and ICNU filed simultaneous post-hearing briefs on November 24, 2008.
II. Proposed Multi-party Settlement

15 A copy of the Settlement is attached to this Order as Appendix A and, by this
reference, incorporated herein. If there is any discrepancy between our summary and
the terms and conditions in the Settlement, the latter controls. We summarize here the
primary provisions of the Settlement:

An increase of $32.5 million in Avista’s annual revenue requirement for
electric service and $4.8 million for natural gas service. Both of these figures
include the effect of the agreed-upon return on equity and overall rate of
return.

An overall rate of return of 8.22 percent including a return on equity of 10.2
percent and a capital structure equity share of 46.3 percent.

Power Supply-Related Adjustments. These adjustments include a hydro
filtering adjustment that lowers the pro forma power costs by $1.6 million,
lowers net power costs of $136,000 reflecting an adjustment to the WNP-3

3 Absent objection, the Commission admits into evidence two exhibits received after the
evidentiary hearing; Exhibit No. 6 which is a compilation of public comments filed by Public
Counsel on November 14, 2008, and Public Counsel and ICNU’s response to Bench Request No.
4, filed November 19, 2008.
ICNU_DR_113 Attachment A Page 7 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 8
ORDER 08

contract, adjusts natural gas fuel costs upward by $8.5 million, corrects a
mathematical error in Colstrip fuel cost lowering fuel costs by $877,000, and
adjusts rate base upward by $8.7 million to reflect an upgrade at the Noxon
hydroelectric generation plant. Altogether, these five adjustments to power
supply costs increase revenue requirement $7.4 million.

Accounting Treatment for Spokane River Project Relicensing and certain
Litigation Expenses. The settling parties agree that the expenses filed in this
case were prudently incurred, but should not be collected in rates until Avista
receives the final license for the Spokane River Project from the Federal
Energy Regulatory Commission (FERC). They further agree, once Avista
receives the license, to defer as a regulatory asset Washington’s share of the
depreciation/amortization associated with relicensing costs and related
expenditures, together with a carrying charge on the deferral, as well as a
carrying charge on the amount of relicensing costs not yet included in rate
base. Any costs that exceed the pro formed costs filed in this case would be
considered in a separate filing.

Treatment of Montana Riverbed Litigation Expenses. The settling parties
agree to Avista’s requested amortization of costs, together with recovery of
accrued interest on Washington’s share of the deferral and the weighted cost of
debt, net of the related deferred tax benefit.

Modify the Energy Recovery Mechanism (ERM). This adjustment
incorporates a level of asymmetry in the ERM by giving customers a greater
share of benefits when power expenses are lower than the authorized level and
retaining the current sharing proportion when power expenses exceed the
authorized level.

Increase the Low Income Rate Assistance Program (LIRAP) and Demand Side
Management (DSM) funding. LIRAP annual funding is increased by $500,000
to an annual funding level for electric low- income customers of $2,864,000
and $1,580,000for natural gas customers. DSM funding increases by
$350,000 over the existing level of $1,132,000.

Consolidate all Line Item Adjustments to a stipulated amount.

The proposed change in rates would go into effect of January 1, 2009.
ICNU_DR_113 Attachment A Page 8 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 9
ORDER 08

III. Standard for Review

A. Settlements.

16 Our standard for reviewing proposed settlements is found in WAC 480-07-750(1):
“The commission will approve settlements when doing so is lawful, the settlement
terms are supported by an appropriate record, and when the result is consistent with
the public interest in light of all the information available to the commission.”

17 In reviewing the settlement we ask:

(1) Whether any aspect of the proposal is contrary to law.

(2) Whether any aspect of the proposal offends public policy.

(3) Whether the evidence supports the proposed elements of the settlement as
reasonable resolution of the issues at hand.

18 We may decide to:

Approve the proposed settlement without condition.

Approve the proposed settlement subject to condition(s).

Reject the proposed settlement.

19 If we approve the proposed settlement without condition, it is adopted as the
Commission’s resolution of the proceeding. If we approve the proposed settlement
subject to one or more conditions, the settling parties will have an opportunity to give
notice, within seven days, that they find the condition(s) unacceptable and withdraw
from the Settlement. If that occurs, or if we reject the proposed settlement, our rules
provide that the proceeding will return to its posture as of the day before the
settlement was filed. If this occurs, then we will conduct such further process as is
ICNU_DR_113 Attachment A Page 9 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 10
ORDER 08

required to allow fully adjudicated results considering the parties’ respective litigation
positions and due process rights.

20 In reaching a decision, we emphasize that our purpose is to determine whether the
settlement terms are lawful and in the public interest. We do not consider the
settlement’s terms and conditions to be a “baseline” subject to further litigation. If
opponents of a settlement demonstrate that its terms are not in the public interest, we
may modify the terms in question, or reject the settlement in its entirety. Should we
modify a settlement, the settling parties may withdraw from the agreement, which has
the same practical effect as our rejecting a settlement; the case goes to hearing.

B. Ratemaking Principles.

21 The Commission is charged by statute with the responsibility to regulate public
utilities in the public interest. In the context of establishing rates for electric and
natural gas companies, this responsibility is reflected by the Commission’s
determination that proposed rates are fair, just, reasonable, and sufficient. This
standard balances consumers’ interests in paying the lowest reasonable rates for
utility service, while providing the utility with rates sufficient to recover prudently
incurred costs and an opportunity to earn a return on its investment. The allowed
return on investment must be adequate to allow the utility to attract required capital at
reasonable rates and on reasonable terms.

IV. Discussion and Decision

22 Avista bears the burden of proof in this proceeding and supports adoption and
approval of the Settlement. Our focus here is to determine whether the Settlement is
lawful and in the public interest. Ordinarily we would address the terms and
conditions of the Settlement first. However, two adjustments proposed by the joint
parties form the basis for a significant portion of the difference between the revenue
requirements proposed by the settling parties and the joint parties. Accordingly, in
the interest of judicial economy we address those adjustments first as our ruling on
those issues substantially affects the outcome of our final determination.

ICNU_DR_113 Attachment A Page 10 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 11
ORDER 08

A. Joint Parties’ Adjustments to Original Filing.

1. Federal Income Tax (FIT) Adjustment.

23 In responsive testimony, the joint parties proposed that Avista Utilities’ federal
income tax rate be lowered from the 35 percent statutory rate to an “effective tax rate”
of 31 percent based on a Consolidated Tax Adjustment (CTA) which offsets Avista
Utilities’ projected tax liability with the tax liabilities of some, but not all, of Avista
Corporation’s subsidiaries. According to the joint parties’, the CTA recognizes that
Avista Corporation has several subsidiary companies that incurred tax losses during
the 2005 and 2006 tax years. Thus, they argue that Avista’s parent paid less in total
federal income taxes than the sum of the tax liabilities of each company.5 They
conclude that the Commission should recognize the unregulated subsidiaries’ tax
losses as a benefit that should flow through to ratepayers of the regulated utility.

24 In preparing the CTA, the joint parties also adjust Avista Utilities’ taxable income to
remove the benefits of accelerated depreciation and income tax credits based on a
private letter ruling from the Internal Revenue Service (IRS).6 The joint parties
contend that Avista will not lose its accelerated depreciation tax benefits as result of
this adjustment. With these benefits removed, the CTA reduces the revenue
requirement by $3.4 million for electric service and $3.1 million for gas service.

25 In rebuttal, Avista explains that while all Avista companies file a consolidated tax
return, the IRS requires that actual taxable income be computed for each separate
legal entity.7 The statutory tax rate for the consolidated companies and for Avista is
the same, 35 percent.8 In addition, Avista corrects a computational error in the joint
parties’ CTA calculation that incorrectly applied the full pre-tax impact of subsidiary
losses as a reduction to Avista’s tax expense rather than the tax effect of the losses.9
While not supporting a CTA, Avista calculates the corrected effective tax rate to be

4 Majoros, Exh. No. MJM-1TC at 11-14 and Exh. No. MJM-6.
5 Majoros, Exh. No. MJM-4TC at 12.
6 Majoros, Exh. No, MJM-4TC at 13.
7 Fallkner, Exh. No. DMF-1T at 4.
8 Id.
9 Id. at 5.
ICNU_DR_113 Attachment A Page 11 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 12
ORDER 08

34 percent rather than 31 percent, and points out that the CTA does not properly
allocate between the jurisdictions in which it operates. Correcting for the proper
allocation between jurisdictions and calculating Washington’s jurisdictional share of
the loss, the combined electric and natural gas tax savings associated with subsidiary
company losses would reduce the joint parties’ proposed $4.324 million adjustment to
$910,717.10

26 After correcting the computational and jurisdictional allocation errors, Avista
confronts the CTA’s premise by noting that the joint parties selected only subsidiaries
with tax losses and excluded those with taxable gains.11 Avista argues that legal
entities under the same parent should not necessarily share taxable gains and losses.12
Rather, tax liabilities should be segregated based on whether the taxable event
resulting in a gain or loss occurred because of regulated or unregulated activities.13
Finally, Avista asserts that the theory of a CTA may violate IRS normalization
principles.14

27 At hearing, the joint parties acknowledged a computational error in the calculation of
the CTA and revised their exhibits to reflect a proposed increase to electric revenue
requirement from $20,118,000 to $24,477,000 and a proposed increase to gas revenue
requirement from $627,000 to $3,441,000.15

Commission Determination.

28 In establishing rates for regulated utilities, we have followed well-established
principles regarding the segregation of regulated and non-regulated operations, as
they are fundamentally different in nature and purpose.16 Regulated operations serve

10 Id.
11 Id. at 10.
12 Id. at 9.
13 Id.
14 Id. at 2.
15 Majoros, Exh. No. MJM-9C at 1-2.
16 WUTC v. Washington Natural Gas Company, Docket UG-920840, 4th Supplemental Order,
(September 27, 1993) at 14-16; In the Matter of the Application of Puget Sound Energy, Inc. For
an Order Approving a Corporate Reorganization to Create a Holding Company, Puget Energy,
Inc., Docket UE-991779, Order Accepting Stipulation (August 15, 2000) at 2; WUTC v. Avista
Corporation d/b/a Avista Utilities, Docket UG-021584 (February 13, 2004) at 3; In the Matter of
ICNU_DR_113 Attachment A Page 12 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 13
ORDER 08

the public with rates and conditions of service established by the Commission
according to regulatory principles embodied in statutes and rules that protect the
public from monopoly rents and unreasonable terms and conditions. On the other
hand, non-regulated operations are competitive enterprises offering services and
products unnecessary to, and many times wholly unrelated to, the utility service
offered to the public.17

29 Consistent with our regulatory principles, if a utility’s costs are prudently incurred
and if property is used and useful in providing utility service, it is entitled to recover
those costs and to place such property in its rate base, where it may recover and have
an opportunity to earn a reasonable return on its original investment.18 Conversely, a
utility is not allowed to recover in customer rates costs or expenses related to
activities that do not provide service to its ratepayers.19 For this reason, we strive to
isolate ratepayers from the impacts of a utility’s non-regulated activities, concluding
that ratepayers should not be required to subsidize or be exposed to the risks of the
non-regulated operations of a utility. Should a compelling reason be shown to
commingle regulated and non-regulated operations, the costs and benefits must go
hand in hand. We must ensure that the costs and burdens do not flow
disproportionately to regulated operations, while the beneficial aspects flow
disproportionately to non-regulated activities.

30 The principle of segregating regulated and non-regulated operations has been
emphasized in several recent proceedings involving the acquisition of utility
companies or the formation of holding companies following enactment of the federal

the Application of Avista Corporation d/b/a Avista Utilities, for an Order Approving a Corporate
Reorganization To Create a Holding Company, AVA Formation Corp,, Docket U-060273, Order
03(February 28, 2007) at 5-7.
17 The prices and quality of services or products offered by such competitive enterprises are
governed by the actions of the consumer, who is expected to act according to the principles of a
free market.
18 Calculation of the rate base and the reasonableness of return on investment are fundamental
elements of a utility’s revenue requirement.
19 See n.16; Docket U-060273, Order 03 (February 28, 2007) at 6. In fact, we have required
“ring-fencing” provisions in acquisition cases in order to isolate utility operations from any
negative financial impacts that could flow from unregulated operations. See Order 03 in Docket
U-060273 cited above and WUTC v. PacifiCorp d/b/a Pacific Power & Light Company, Docket
UE-050684, Order 04 (April 17, 2006) at 59.
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Energy Policy Act of 2005, including repeal of the Public Utility Holding Company
Act of 1935, effective February 8, 2006.20 These acquisitions were approved with
specific “ring-fencing” provisions intended to isolate utility operations from any
negative financial impacts flowing from unregulated units.21 The isolation aspects of
ring-fencing provisions are intended: “(1) to ensure that the utility maintains a strong
credit rating and can attract capital; (2) to prevent cross-subsidization of non-
regulated ventures; and (3) to ensure regulators’ access to timely and accurate
information.”22 In our approval of the Avista Corporation’s reorganization, we
specifically found that after reorganization there would be “no link between the non-
regulated businesses and Avista [Utilities]” and that several measures were in place to
ensure that “there are appropriate cost allocation principles and standards in effect to
ensure that Avista [Utilities] will not be subject to cross-subsidization.”23 Our recent
reinforcement of the principle of segregating regulated and non-regulated operations
means the proponent of consolidation should present a compelling reason for us to
stray from these principles.24 The joint parties do not offer one here.

31 Rather, the CTA proposes a simple, though unbalanced adjustment that would offset
Avista Utilities’ tax liability with the tax benefits associated with some, but not all, of
Avista Corporation’s non-regulated subsidiaries. Specifically, it isolates, for
ratemaking consideration, only those operations of non-regulated enterprises that had

20 In the Matter of the Joint Application of MidAmerican Energy Holdings Company and
PacifiCorp, d/b/a Pacific Power & Light Company For an Order Authorizing Proposed
Transaction, Docket UE-005190, Order 07 (February 22, 2006); Docket U-060273, Order 03
(February 28, 2007); In re Application of MDU Resources Group, Inc. & Cascade Natural Gas
Corp. Docket UG-061721, Order 06 (June 27, 2007).
21 Order 03 in Docket U-060273 at 6. For a full citation, see n. 16.
22 Order 03 in Docket U-060273 at 6 quoting Mergers and Ring-Fencing Issues: An Oregon
Perspective, Oregon Public Utility Commissioner Ray Baum presentation at the Technical
Conference on Public Utility Holding Company Act of 2005, December 7, 2006.
23 Order 03 in Docket U-060273 at 7. We note that AVA Holdings will not be formed until the
commissions in all jurisdictions in which Avista operates approves the transaction.
24 While we recently found moot a CTA proposed by ICNU, we concluded that should parties
recommend similar adjustments in future proceedings, we expected a full airing of the appropriate
accounting for deferred taxes arising from the parent company’s payment of taxes on a
consolidated basis as well as the principles of the benefit-burden test in this context. WUTC v.
PacifiCorp d/b/a Pacific Power & Light Company, Docket UE-050684, Order 04 (April 17,
2006) at 59. The benefit-burden test was not adequately addressed by the joint parties in the
proposed CTA.
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taxable losses and does not include those that had taxable income in the 2005 and
2006 tax years. In other words, the joint parties “cherry pick” those subsidiaries
with a tax impact that is favorable to a CTA without including those that had tax
liabilities. Focusing solely on those entities with tax losses is inconsistent,
unbalanced and unfair; reasons enough to reject the concept. Even if we “corrected”
the CTA to base the adjustment on the performance of all non-regulated operations,
we would be placed in the untenable position of requiring ratepayers to subsidize
those operations with taxable gains. Finally, under either circumstance, the CTA
violates the principle, if not the letter, of our recent decisions establishing “ring-
fences” that protect ratepayers from non-regulated activities by declining to pull
benefits or burdens from activities “outside the ring-fence” into the regulated
business. Not only are we provided no reason to act contrary to our recent precedent
in this regard, doing so here could jeopardize the integrity of the rationale for “ring-
fencing” and undermine its defensibility if it were attacked.

32 Even ignoring our concerns for the CTA’s adherence to our established regulatory
framework, we find it has little impact on the revenue requirement proposed by the
Settlement. First, we note that the CTA was replete with computational errors that
were corrected by Avista on rebuttal and acknowledged by the joint parties at
hearing.26 The joint parties initially applied the entire pre-tax loss, not the tax impact
of the loss and failed to allocate it between the jurisdictions in which Avista
operates.27 After correcting these errors, the difference between the statutory rate of
35 percent and the corrected “effective tax rate” of 34 percent is de minimis; a
difference that would not warrant adoption of the CTA or rejection of the Settlement.

33 Finally, we are concerned that the isolation aspect of the CTA may violate provisions
of the Internal Revenue Code (IRC). Avista must apply consistent treatment to its tax
expense, depreciation expense, reserve for deferred taxes, and rate base or it may
violate the normalization provisions of the IRC. The joint parties propose an

25 Falkner, Exh. No. DMF-1 at 4 and 7. As noted by Falkner, only one subsidiary of the Avista
consolidated group had a loss in 2007.
26 In its uncorrected form, we give this testimony little, if any, weight given the number of errors
embodied in the CTA.
27 Falkner, Exh. No. DMF-1T at 5.
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adjustment only to tax expense. This creates a classic Hobson’s choice:28 if Avista
consistently includes non-regulated property in tax expense and rate base in order to
comply with the normalization provisions of the IRC, then it will run afoul of the
basic ratemaking principle that non-regulated property cannot be placed in rate base.

34 In sum, we reject the joint parties’ CTA for the reasons expressed above, finding the
weaknesses of its theory and application in this case to overwhelm any alleged
benefits.

2. Depreciation.

35 In its original filing, Avista makes pro forma adjustments to reduce electric
depreciation expense by $326,000 and gas depreciation expense by $330,000 pursuant
to the depreciation study approved by the Commission in the last general rate case. 29
The joint parties propose to further decrease depreciation expense by modifying
Avista’s calculation of removal costs for certain categories of electric and natural gas
plant in service. Their proposal would reduce the Company’s depreciation expense
for electric transmission and distribution plant downward by $3,733,975 and for
natural gas distribution plant downward by $1,808,729.30

36 In response to Bench Request No. 4, the joint parties corrected an error in their
depreciation adjustment thereby increasing their proposed depreciation expense by
$513,268 for the electric utility and by $195,422 for the natural gas utility.31 As a
result, the joint parties’ further revised their exhibits to reflect increases in their
proposed recommended electric revenue requirement from $24,477,000 to

28 An apparently free choice that offers no real alternative. [After Thomas Hobson (1544-1630),
English keeper of a livery stable, from his requirement that customers take either the horse
nearest the stable door or none.]
29 Andrews, Exh. No. EMA-1T at 14 and 33. Andrews, Exh. No. EMA-2 at 5. Andrews, Exh.
No. EMA-3 at 4. WUTC v. Avista Utilities, Dockets UE-070804/UG-070805, Order 05
(December 19, 2007). In Order 05, the Commission approved and adopted an uncontested
settlement stipulation.
30 King, Exh. No. CWK-1T at 2.
31 See n. 3 and King, Exh. No. CWK-4 (revised November 19, 2008) at 1.
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$24,841,000 and the proposed gas revenue requirement from $3,341,000 to
$3,471,000.32

37 The joint parties contend that Avista’s depreciation study is flawed because it uses an
inappropriate method to estimate and recover “removal costs” for plant that is treated
in aggregate, or as “mass property.”33 They assert that the conventional procedure for
accruing removal costs increases the depreciation rate in an amount sufficient to
collect these costs over the life of the plant.34 By using a ratio that compares current
dollars of removal expense to past dollars of original plant cost, they argue that
Avista’s method “grossly overestimates removal cost.”35

38 They argue further that the proper method for accruing removal costs should be based
on the accounting standards in Financial Accounting Standard (FAS) 143, applicable
to removal costs required by law, regulation, or contract.36 They point out that the
FAS 143 method recognizes the change in the value of dollars (due to inflation)
during the life of an asset and allocates that value to each of the years in which
removal costs are accrued.37 Using the FAS 143 method, the joint parties recalculate
and reduce Avista’s depreciation expense in the amounts expressed above.38 The
joint parties contend such a reduction would remedy the “intergenerational inequity”
created by Avista’s depreciation methodology.”39

32 Majoros, Exh. No. MJM-9C (revised November 21, 2008) at 1-2. This exhibit further revises
the joint parties’ revenue requirement to account for the corrected King, Exh. No. CWK-4.
33 King, Exh. No. CWK-1T at 7. Removal costs reflect the cost of removing plant at the end of
its useful life, net of any salvage value.
34 King, Exh. No. CWK-1T at 3.
35 Id. at 6. The joint parties refer to this method as the “Traditional Inflated Future Cost
Approach or TIFCA” and assert that TIFCA is unfair to customers because it: (1) projects the rate
of historical inflation that occurred between the times of the original plant investment and
removal of that plant into the future to estimate net removal cost at asset retirement; and 2)
charges current customers future removal costs in inflated dollars.
36 King, Exh. No. CWK-1T at 11.
37 Id.
38 See ¶ 35.
39 King, Exh. No. CWK-1T at 16. “Intergenerational equity” is a regulatory principle designed to
ensure that ratepayers are charged only for the costs to serve them, at the time the service is
rendered and the costs are incurred.
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39 In cross-answering testimony, Staff opposes the joint parties’ depreciation
adjustment, arguing their proposed treatment of removal costs would create a
“mismatch in timing of the actual dollars collected . . . because . . . fewer dollars are
collected in the early years and more dollars will have to be collected in the later
years.”40 Staff contends the remaining life depreciation method used by Avista and
all other regulated electric companies in Washington will not over-charge customers
for removal costs because it allows for adjustment of the depreciation rate to adjust
balances over the asset’s remaining life. Staff argues further that customers are
compensated for the removal costs collected in depreciation because accumulated
depreciation is deducted from rate base under original cost regulation.41

40 In its rebuttal to the joint parties’ proposal, Avista also argues that the depreciation
adjustment should be rejected as it is based upon a depreciation method that fails to
properly match the accrual of funds to cover the costs of removal with the “service
value” received by customers.42 Avista characterizes the joint parties’ approach as a
“sinking fund” that requires collection of a progressively higher amount to cover
removal costs instead of the equal, annual accrual collected under the traditional,
straight-line method. Avista contends that the “sinking fund” method requires two
steps: 1) the ratable depreciation of the present value of future removal cost; and 2) an
annual accretion to the ratable depreciation to account for each year’s inflation.43
They point out that this method would require an annual adjustment to depreciation
rates to accomplish the inflation adjustment. As to effect, Avista argues that this
method charges future customers greater net removal costs which both violates the
matching principle (offending intergenerational equity) and makes it probable that
Avista will never fully recover net removal costs if rates are not adjusted annually.44

41 In addition, Avista argues that the straight-line remaining-life depreciation method,
including the accrual of net removal costs, was proposed in the Company’s last
general rate case, settled by all parties, and approved by the Commission.45 It points
out that the depreciation study received careful attention from the parties including

40 Parvinen, Exh. No. MPP-1T at 7.
41 Id.
42 Spanos, Exh. No. JJS-1T at 4.
43 Id.
44 Id. at 5. See also Felsenthal, ADF-1T at 9.
45 Order 05, Docket UE-070804/UG-070805.
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Public Counsel, who voiced no objection to the study’s net removal cost method,
which has now been approved by commissions in all states served by Avista.46

42 Next, Avista contends that it is inconsistent to modify depreciation rates to reflect
present value costs for net removal, but not all other costs, including original asset
cost. It argues that, to be consistent, the method proposed by the joint parties should
apply removal cost ratios to the current (not original) cost of the asset.47

43 Turning to its approved method, Avista claims that method is conservative because it
may actually underestimate the ultimate cost of removal. Avista explains that under
the approved method the removal cost ratio is based on the current cost of removal
compared to the original cost of the asset. This method captures inflation between the
date of original investment and the date of removal from the statistical data base but
fails to account for any future inflation. Therefore, if technological improvements fail
to offset inflation, the accruals will fail to fully cover the net cost of future removals.
Should costs be over-recovered, Avista agrees with Staff that any over-recovery is
compensated by the commensurate reduction in rate base and can be mitigated in the
next depreciation study.48

44 In conclusion, Avista contends that FAS 143 is not relevant to regulatory
accounting.49 It argues the standard is focused on ensuring that financial accounting
makes clear to investors what removal costs are company liabilities based on legal
obligations, and that it has no application to removal obligations that are not
specifically required by law.50 Finally, the Company argues that FAS 143 does not
address the ratemaking principles of deferral accounting and matching, which ensure
intergenerational equity in ratemaking.

Commission Determination.

45 The depreciation study under scrutiny in this proceeding was conducted only three
years ago. The depreciation rates developed from that study were an issue in the last

46 Spanos, Exh. No. JJS-1T at 11.
47 Id. at 6.
48 Id. at 16.
49 Id. at 14 and Felsenthal, Exh. No. ADF-1T at 3.
50 Spanos, Exh. No. JJS-1T at 15.
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general rate case and were modified on the basis of recommendations from parties in
that proceeding. Ultimately, the parties reached an uncontested settlement which we
accepted and adopted. While settlement agreements do not serve as precedent, having
recently resolved this issue to the satisfaction of all parties, including Public Counsel,
we are not inclined to reconsider Avista’s depreciation methodology absent a change
in circumstances, which has not been shown. 51

46 This Commission has long favored use of the straight-line depreciation methodology
for determining depreciation expense.52 Our goal is to allocate the cost of an asset
over its useful life in a manner that matches the benefits utility customers receive
from an asset with its cost burdens. Avista’s depreciation methodology accomplishes
this goal while preserving “intergenerational equity” over the asset’s useful life.
Finally, we favor a methodology that requires few changes or adjustments to
accomplish its objectives. With this background, we turn to the merits of the joint
parties’ proposal.

47 First, the joint parties’ proposal would require Avista to annually adjust depreciation
rates to conform to changes in the rate of inflation. In turn, rates would have to
change to give the adjustment effect. As regulating in the public interest includes
promoting rate stability, we are reluctant to adopt a depreciation methodology that
would result in even more rate changes than those faced by ratepayers in the current
regulatory environment. Absent annual consideration of the Company’s depreciation
rates, Avista would likely under-collect net removal costs and be forced to turn to
future ratepayers to compensate for these under-collections. In this circumstance, the
joint parties’ proposal neither observes the “matching” principle nor preserves
“intergenerational equity”.

48 As to the joint parties’ contention that Avista’s accrual of removal costs should be
based on FAS 143, we conclude that the Financial Accounting Standards Board
(FASB) standards are applicable to financial reporting, not the regulatory processes

51 Litigating the company’s depreciation methodology on an annual basis is not an efficient use of
the time and resources of the parties to these proceedings or the Commission.
52 Parvinen, Exh. No. MPP-1T at 6. Spanos, JJS-1T, at 19 noting that 47 commissions, including
the Washington commission, primarily or exclusively use the traditional straight-line depreciation
method. See also our recent order in WUTC v. Puget Sound Energy, Inc., Dockets U-072300 and
UG-072301, Order 12 (October 8, 2008) at 20.
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used to formulate utility rates.53 In fact, FAS 143 acknowledges that regulated
utilities can recover removal costs over the life of assets through depreciation rates:

The amounts charged to customers for the costs related to the retirement of
long-lived assets may differ from the period costs recognized in accordance
with this Statement, and therefore, may result in a difference in the timing of
recognition for financial reporting and rate-making purposes.54

49 Therefore, we find that FAS 143 does not control Avista’s treatment of removal costs
in its depreciation methodology. Finally, we turn to the quality of the evidence the
joint parties have provided on this matter. We have examined Mr. King’s testimony
closely, and particularly his Exhibit No. CWK-4, which purports to calculate the
depreciation expense that would result from implementing his proposed methodology.
The joint parties rely on this exhibit as an accurate calculation applying Mr. King’s
theory to net removal costs for mass property accounts derived from Avista’s
depreciation study. Indeed, Exhibit No. CWK-4 is the sole source for the magnitude
of their proposed depreciation adjustments. In response to our bench inquiry about a
formula used in two of the spreadsheets included in Exhibit No. CWK-4, Mr. King
acknowledged an error and provided a revised set of spreadsheets. However, his
revised spreadsheets may have introduced a second error or, at the very least, a reason
to question the reliability of the spreadsheet. Mr. King’s revised spreadsheet not only
corrects an error in the form of the calculation used in Schedule 4 of Exhibit No.
CWK-4 to produce the “Present Value of Removal Costs at 3%,” it also modifies the
period of years used in this formula. Mr. King’s revised calculation is based on the
average service life of the assets. His original calculation was based on the expired
service life of the assets. Mr. King does not provide an explanation of why he made
this additional change. Moreover, the revised calculation is arguably inconsistent
with testimony where he describes his method as calculating “removal costs
discounted back to the beginning of the account.”55 In the end, we find Exhibit No.
CWK-4 not reliable.

53 Felsenthal, Exh. No. ADF-1T at 21.
54 Id. at 24. (Emphasis added).
55 King, Exh. No. CWK-1T at 14.
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50 In conclusion, we reject the joint parties’ proposed depreciation adjustment, finding it
neither conforms to the removal cost methodology approved in our most recent rate
case, nor promotes rate stability for ratepayers. Nor do we accept the joint parties’
assertion that FAS 143 necessitates use of their methodology. We find the FAS 143
permissive as applied to regulated utilities; allowing regulators discretion in applying
its terms to removal costs. We see no reason to do so on the record before us.
Finally, we find the errors in the joint parties’ testimony significant enough to affect
its weight and thus the evidence insufficient to support their proposed adjustment.

51 We turn now to the terms and conditions of the Settlement and address the largest
adjustment first.

B. Settlement Provisions.

1. Power Supply-Related Adjustments:

52 The settling parties propose the following power supply-related adjustments :

Hydro-filtering. Remove the power supply expense from the 50-year average
for months when hydro generation was either higher or lower by more than
one standard deviation from the average generation for that month.56

WNP-3 Contract. Increase the amount of energy purchased under the contract
by including 2007 energy purchases in the five-year average, which lowers
power supply expense because the contract price is lower than market power
prices in the AURORA model.57

Natural Gas Fuel Costs. Reflect a pro forma period natural gas price of
$8.30/Dth58 for gas-fired generation for the unhedged portion of 2009
generation.

Colstrip Coal Cost. Correct a mathematical error to properly reflect the 2009
pro forma period fuel price.

56 Settlement, Exh. No. 5 at 5.
57 Id. at 6.
58 Decatherm (Dth) is a unit of energy equal to 10 therms or one million British thermal units
(MMBtu).
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Noxon Generation Upgrade. Properly match the capital investment in a plant
upgrade with the resulting increase in generation.

Energy Recovery Mechanism (ERM) Adjustment. Incorporate an element of
asymmetry in the ERM by giving customers a greater share of the benefits
when power expenses are lower than the authorized level. The sharing level in
the second ERM band ($4 million to $10 million) is changed to 75 percent
customer/25 percent Company when power supply expenses are lower (rebate
direction), while maintaining the current 50 /50 sharing in the second band
when power supply expenses are higher (surcharge direction).59

53 ICNU joined in the section of the Settlement regarding power supply-related
adjustments. Public Counsel did not address any power cost-related issues in its
testimony. However, in its post-hearing brief, Public Counsel opposes acceptance of
these adjustments because it disagrees with our decision to accept the Supplemental
Testimony filed by Avista arguing that power supply costs are based on that
testimony.

Commission Determination.

54 Public Counsel’s opposition is legal argument rather than evidence. In its post-
hearing brief, filed simultaneously with Public Counsel’s, Avista characterizes its
position on this issue as “unopposed.”60 As a practical matter, Avista is correct. We
must base our decisions on the weight of evidence in the record. As there is none in
opposition to these power supply-related adjustments, we consider them unopposed.

55 We find that the settlement terms respecting power supply-related costs are supported
by an appropriate record and are consistent with the public interest in light of all the
information in the record.

59 Settlement, Exh. No. 5 at 5-7; Joint Testimony in Support of Settlement, Exh. No. 4T at 4-6,
12-21.
60 Avista Brief at ¶ 55.
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2. Other Revenue Requirement Adjustments.

56 The joint parties propose a number of other adjustments to the operating costs that
support the revenue requirement proposed in the Settlement.61 We have examined
each of the proposed adjustments in light of the evidence presented and the parties’
arguments.62 We considered, among other things, whether the evidence discloses any
errors on the part of the settling parties in the data that underlies the Settlement. We
find no errors in the evidence that supports the Settlement’s terms and conditions
regarding these adjustments. Accordingly, we find that the settlement terms
respecting these revenue requirements are consistent with the public interest.

3. Uncontested Settlement Provisions.

57 The remainder of the settlement provisions including, but not limited to, the overall
rate of return of 8.22 percent, the rate of return on common equity of 10.2 percent, a
capital structure with 46.3 percent common equity, the Spokane River Relicensing
costs, the Montana Riverbed litigation adjustment, the customer deposit adjustment,
the incentives adjustment, the correction to the error in officers’ salaries, the
adjustment to union and non-executive salaries, the Colstrip generation and operation
and maintenance expense, the administrative and general expense adjustment, the
production property adjustment, the adjustment to restate debt, the modification of
customer service charge, and increases to the LIRAP, DSM funding levels, are not in
dispute.63 We accept these provisions as supported by substantial evidence in the
record and in the public interest.

4. Revenue Requirement.

58 As we noted earlier, we addressed the joint parties’ proposed adjustments to the initial
filing before considering the Settlement’s terms and conditions because they have a

61 These include adjustments to D&O insurance, advertising, sports sponsorship, charitable
contributions, director’s compensation, other shareholder-related expenses, dues and
memberships, and executive compensation.
62 This evidence includes: Majoros, Exh. No. MJM-4TC, Majoros, Exh. No. MJM-8T, Andrews,
Exh. No. EMA- 7T, and Norwood, Exh. No. KON-1T.
63Settlement, Exh. No. 5 at 4-5, 7-14; Joint Testimony in Support of Settlement, Exh. No. 4T at 4-
5, 9, 11-19, 24-29, and Majoros, Exh. No. 8T at 2.
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significant impact on the outcome of our final determination. As reflected in the
following table, our rejection of the joint parties’ proposed CTA and depreciation
adjustments together with our acceptance of the Settlement’s power supply-related
adjustments has a dramatic effect on the joint parties’ proposed gas and electric
revenue requirements:

Dollars in
thousands

Electric Service

Natural Gas Service
Correct for FIT
Computational Error
(& resulting conversion
factor flow through
impact)

$ 4,358

$ 2,714
Net Power Supply-
Related Adjustments in
Settlement

7,433

Affirm Straight-line
Depreciation (Re: cost
of removal

3,057

1,197

Total 14,848 3,911
Joint Parties’ Initial
Recommended Revenue
Requirement

20,118

627
Addition of above 3
items to Joint Parties’
Recommended Revenue
Requirement

34,966

4,538
Multi-party Settlement
Recommended Revenue
Requirement

$ 32,538

$ 4,768

64 Norwood, Exh. No. KON-1T at 1.
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59 The joint parties’ electric revenue requirement increases to $35 million compared to
the Settlement’s $32.5 million, or $2.5 million higher than the Settlement Their gas
revenue requirement increases from $627,000 to $4,538,000 compared to the
Settlement’s $4,768,000, or $230,000 lower than the Settlement.

60 We are not bound to follow a specific formula or method when calculating rates.
Rather, we are to establish rates that balance both investor and consumer interests to
arrive at rates that are fair, just, reasonable, and sufficient.66 In light of all the
evidence in the record, we find the Settlement’s electric and gas revenue requirements
result in rates that meet this criteria. The fact that the Settlement’s electric revenue
requirement is substantially lower than that produced by the joint parties after our
rejection of their principal adjustments supports our conclusion. Similarly, the
$230,000 reduction in gas revenue requirement that follows from our rejection of the
joint parties’ adjustments is a reduction of less than five percent from the Settlement’s
proposed gas revenue requirement. In the context of public policy which favors
settlements, this is not a reduction of sufficient magnitude to warrant rejection of the
Settlement.67

5. Reclassification of Non-Legal Asset Removal Obligations
(AROs).68

61 A portion of depreciation expense, including depreciation expense in the proposed
Settlement, is for AROs or the future asset removal costs of long-lived plant net of
any salvage value. For ratemaking purposes, Avista classifies a portion of the
depreciation expense collected for AROs as accumulated depreciation and separately
accounts for it in sub-accounts.

65 Norwood, Exh. No. KON-1T at 4.
66 Federal Power Comm’n v. Hope Natural Gas Co., 320 U.S. 591,603 (1944), RCW 80.28.010
and 80.28.020.
67 RCW 34.05.060.
68 The term “non-legal asset removal obligations” refers to net removal costs for general plant
assets that are not required to be incurred by law or regulation – so called “legal removal costs.”
Examples of legal removal costs include the cost of required site restoration or environmental
remediation.
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62 The joint parties’ recommend reclassifying a portion of the depreciation expense
collected for non-legal AROs to Account 254 – Other Regulatory Liabilities and
creating a new account for these funds.69 The joint parties assert that Avista has over-
collected $209.4 million for future removal costs.70 The joint parties contend that it is
appropriate to treat these funds in accordance with FAS 143 and recognize these
AROs as a regulatory liability.71

63 The joint parties contend that, regardless of being included in accumulated
depreciation, these monies have already been collected from ratepayers for the future
cost of removal.72 The joint parties argue that unless the Commission requires it,
there is no provision to refund ratepayers these amounts if Avista fails to use these
funds for removal costs.73 The joint parties’ proposed reclassification does not have
an impact on the revenue requirement.74

64 In rebuttal, Avista states that FAS 143 is not applicable to ratemaking, in general.75
Moreover, Avista considers the reclassification unnecessary and inappropriate and
points out that Avista maintains sub-accounts within the accumulated depreciation
account to track removal costs.76 Avista contends that there is no need to place these
funds in a separate account to ensure that the funds will be spent for their intended
purpose (costs of removal) and notes that the Federal Energy Regulatory Commission
(FERC) has the authority to prohibit a utility from making other use of these funds.77

65 In cross-answering testimony, Staff argues that reclassification is unnecessary
because there is no Commission or FERC requirement to do so and there is no
revenue requirement impact.78 Staff contends that collections over actual removal

69 Majoros, Exh. No. MJM-4TC at 5.
70 Id.
71 Id.
72 Id. at 9.
73 Id. at 10.
74 Id. at 11.
75 Spanos, Exh. No. JJS-1T at 15.
76 Felsenthal, ADF-1T at 4.
77 Felsenthal, ADF-1 at 12.
78 Parvinen, Exh. No. MPP-1T at 3.
ICNU_DR_113 Attachment A Page 27 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 28
ORDER 08

costs are returned under current methods and customers would “receive no greater
safeguard” with the proposed reclassification.79

Commission Decision.

66 We conclude that the joint parties have failed to demonstrate the need for
reclassifying AROs as regulatory liabilities and accordingly deny their request. There
is no evidence that Avista has failed to properly use these funds for their intended
purpose. Moreover, the joint parties failed to demonstrate that reclassification of
these funds would afford ratepayers any greater protection should that contingency
arise. .

6. Settlement with the Coeur d’Alene Tribe.80

67 Avista requests recovery of costs associated with the settlement of the Coeur d’Alene
Tribe’s (Tribe) claim for damages related to the operation of Avista’s Spokane River
Hydroelectric Project (Project), including its Post Falls hydroelectric facility located
on the Spokane River downstream of Lake Coeur d’Alene.81 As designed, the
Project uses Lake Coeur d’Alene as a water storage facility – manipulating water
levels as necessary to optimize system efficiency.

68 From 1907 to 1972, Avista operated the Project under authority granted by the State
of Idaho.82 In 1972, Avista filed a petition with the FERC seeking a federal license to
operate the Project. In 1973, the Tribe intervened in the proceeding, claiming a
portion of Lake Coeur d’Alene was on its reservation and under its exclusive use and
control.83 In response, Avista argued that ownership of the lake was held by the State
of Idaho, which had issued all relevant permits necessary for the Project’s operation.
After years of litigation in a number of forums, the United States Supreme Court
ultimately determined in 2001 that the United States holds, in trust for the Coeur

79 Id. at 3-4.
80 This issue addresses information that was protected from public disclosure by the terms and
conditions of Order 03, Protective Order, entered April 3, 2008, until Avista relinquished its
claim of confidentiality to most information on December 19, 2008.
81 Pessemier, Exh. No. TEP-1T at 1.
82 Id. at 3.
83 Id.
ICNU_DR_113 Attachment A Page 28 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 29
ORDER 08

d’Alene Tribe, those portions of the lake within the boundaries of the Coeur d’Alene
Reservation.84 The Court’s ruling did not, however, settle the Tribe’s dispute with
Avista related to the historic and future use of the lake to benefit Project operations,
including compensatory claims founded in §10(e) of the Federal Power Act for
inundating reservation lands.85

69 In 2008, Avista and the Tribe reached a comprehensive settlement whereby Avista
agrees to compensate the Tribe for past damages and future use of the lake to serve
the Project. Additional settlement terms include the issuance of a tribal water rights
permit for the Project’s benefit, and new or renewed rights-of-way to maintain
“existing transmission lines across Tribal Trust Lands.”86 As compensation for past
trespass and §10(e) water storage claims, Avista will pay the Tribe $25 million in
2008, $10 million in 2009, and $4 million in 2010.87 Future §10(e) compensation
consists of flat annual payments of $400,000 for the first 20 years of the license and
$700,000 flat annual payments for the remaining 30 years of the license.88 The
settling parties would allow recovery of Avista’s immediate settlement payments and
offer a ratemaking treatment set forth below.

70 The Settlement would defer Washington’s share of Avista’s 2008 and 2009 payments
to the Tribe, totaling $35.4 million, as a regulatory asset.89 The deferral would
include depreciation/amortization associated with said payments together with a
carrying charge of five percent.90 In addition, Avista would be allowed to defer a
carrying charge on the costs not yet included in rate base for subsequent recovery in
rates.91 Finally, the deferral’s recovery in rates would be spread over the remaining
life of the Project.

84 Id.
85 Id. at 4-5.
86 Pessemier, Exh. No. TEP-1T at 5-6, and Exh. No. TEP-4TC at 19.
87 Andrews, Exh. No. EMA-1T at 24.
88 Id.
89 The deferral would commence when Avista makes its first payment to the Tribe. Avista Brief at
10.
90 Andrews, Exh. No. EMA-1T at 24.
91 Id.
ICNU_DR_113 Attachment A Page 29 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 30
ORDER 08

71 The proposed ratemaking treatment would result in a pro forma adjustment that
decreases Washington net operating income by $499,000 and increases rate base by
$15,084,000.92 The settling parties agree that the pro forma costs associated with the
settlement with the Tribe are prudent93 and that any costs that exceed the pro formed
costs in this case would be addressed in a separate proceeding.94

72 The joint parties argue that Avista’s payments to the Tribe should be disallowed as
imprudent because Avista “admitted to past trespass.”95 They assert that the
settlement with the Tribe would require current customers to pay for past misconduct
and usage charges resulting in retroactive ratemaking in violation of RCW 80.28.020,
which requires the Commission to set rates prospectively.96 The joint parties argue
that the past §10(e) usage costs and past trespass damages are costs that should have
been included in ratemaking for previous periods.97 If the Commission approves
these expenses, the joint parties propose that these funds be offset by monies collected
under non-legal asset removal obligations (AROs).98

73 In rebuttal, Avista denies that its settlement expenses were imprudently incurred and
asserts that it has not admitted to trespass.99 Avista contends that ownership of Lake
Coeur d’Alene was not conclusively determined until the Supreme Court ruling and
that, even then, it reasonably believed that its rights were protected by an earlier
assignment of rights to operate the Post Falls dam site and the issuance of a permit in
1909 to use the lake to store water.100 Avista further contends that the settlement does
not constitute retroactive ratemaking because there were no “past management
mistakes.”101 It argues that settlement payments to the Tribe could not have been
anticipated or previously recovered through rates; there was no obligation until an

92 Id.
93 Settlement, Exh. No. 5 at 4 and 11; Joint Testimony in Support of Settlement, Exh. Nos. 4TC at
27; Pessemier, Exh. No. TEP-1TC at 1-7, TEP-3C at 1-12, and TEP-4TC at 2-21.
94 Settlement, Exh. No. 5 at 4 and 11, Joint Testimony in Support of Settlement, Exh. No. 4TC at
27.
95 Majoros, Exh. No. MJM-4TC at 16.
96 Id.
97 Public Counsel’s Brief at 24.
98 Majoros, Exh. No. MJM-4TC at 18.
99 Pessemier, Exh. No. TEP-4TC at 4-6 and Exh. No. TEP-5.
100 Pessimier, Exh. No. TEP-4TC at 2-3.
101 Id. at 6; Avista’s Brief at 54.
ICNU_DR_113 Attachment A Page 30 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 31
ORDER 08

agreement was reached with the Tribe in 2008.102 Avista argues further that the
settlement resolves all disputed issues, settles historic claims over use of the lake for
hydroelectric generation and, for the next 50 years, preserves a valuable, low cost
energy resource for the benefit of its customers.103 Staff joins in its arguments.

74 Finally, Avista and Staff oppose the use of ARO funds to offset any settlement
expenses arguing to do so would be inappropriate.104 In cross-answering testimony,
Staff contends that it is inappropriate to use the non-legal ARO’s for any purpose
other than the cost of asset removal.105 Staff contends that the joint parties ignore the
fact that these funds were collected specifically for future removal costs.106

Commission Decision.

75 The evidence demonstrates that Avista began operating the Project under authority
granted by the State of Idaho to control the level of Lake Coeur d’Alene. The joint
parties do not explain why Avista knew or should have known that the Tribe shared
jurisdiction over Lake Coeur d’Alene with the State of Idaho prior to the Supreme
Court’s 2001 ruling. Indeed, the long, complex legal history of this issue belies the
joint parties’ assertion.

76 The controversy over the lake’s ownership arose approximately 35 years ago when
the Tribe first asserted its claim of ownership of those portions of the lake within its
reservation. Litigation ensued before the FERC, which ruled initially that the lake
was owned by Idaho.107 FERC’s decision was appealed and eventually remanded for
review, where it decided that it lacked jurisdiction to resolve this issue in 1988.108
Finally, the United States, acting in its capacity as trustee for the Tribe, brought suit
against Idaho to settle the question. In 2001, the Court ruled 5-4 in favor of the

102 Avista’s Brief at 54.
103 Pessemier, Exh. No. TEP-4TC at 3.
104 Felsenthal, Exh. No. ADF-1T at 16.
105 Parvinen, Exh. No. MPP-1T at 5.
106 Id. at 6.
107 Pessemier, Exh. No. TEP-4TC at 15.
108 Id. at 7.
ICNU_DR_113 Attachment A Page 31 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 32
ORDER 08

United States, finally resolving the Tribe’s ownership claim.109 Throughout this
dispute’s long legal history, Avista either pursued all legal remedies at its disposal or
had no choice but to await the litigation’s outcome. The matter now decided, Avista
pursued an opportunity to settle all claims raised by the Tribe, including those
affecting the relicensing of the Project. We believe Avista’s actions were both
reasonable and prudent.

77 In sum, we reject the joint parties’ argument that Avista’s operation of the Project or
its actions in response to the Tribe’s claim were imprudent. Avista operated the
Project with authority from the entity it reasonably believed was the lawful owner, the
State of Idaho, and, when challenged, it defended its right to operate it pursuant to the
authority granted. Without further legal recourse, Avista acted prudently to settle its
dispute with the Tribe and wrap the Project’s relicensing issues into a comprehensive
agreement ensuring long-term availability of valuable hydroelectric resources for the
benefit of Avista’s current and future ratepayers.110

78 Finally, we find that the settling parties’ treatment of the costs related to the
settlement with the Tribe is reasonable and well supported by the evidence in the
record.111 The costs associated with the settlement will be recouped over time and
with reasonable carrying charges. Contrary to the joint parties’ assertion, the
settlement does not constitute retroactive ratemaking. Retroactive ratemaking
involves the current collection, through rates, of past obligations.112 Until Avista
reached a settlement earlier this year, it had no obligation to the Tribe. This case
presents Avista’s first opportunity to recover the charges associated with that
obligation.113 We also reject the joint parties’ alternative proposal to use ARO’s to

109 Idaho v. United States, 533 U.S. 262 (2001). In that case, the Court held that the post-Idaho
statehood ratification of treaties with the Tribe demonstrated Congressional intent to reserve
certain submerged lands of the lake for the benefit of the Tribe.
110 The Tribe’s original claims potentially exposed Avista to much higher damages. (Pessemier,
Exh. No. TEP-4TC at 17). If successful, these claims could threaten the Project’s future
economic viability.
111 See n. 93.
112 In the Matter of the Application of Puget Sound Energy For Authorization Regarding the
Deferral of the Net Impact of the Conservation Incentive Credit Program, Schedule 125, and
Subsequent Recovery Thereof Through Schedule 120, Conservation Rider, Docket UE-010410,
Order Denying Petition to Amend Accounting Order (November 9, 2001).
113 Pessemier, Exh. No. TEP-4TC at 6.
ICNU_DR_113 Attachment A Page 32 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 33
ORDER 08

offset any settlement expenses; it is inappropriate to use ARO’s for any purpose other
than the cost of asset removal. We conclude that the Settlement’s terms dealing with
payments made to the Tribe are reasonable and supported by the record.
V. Conclusion.

79 We favor the resolution of contested issues through settlement when a settlement’s
terms and conditions comply with the law and are consistent with the public interest.
After thorough consideration, we find the Settlement to be lawful and in the public
interest and that the resulting rates are fair, just, reasonable, and sufficient. We adopt
the Settlement as the Commission’s resolution of all matters in this proceeding.

FINDINGS OF FACT

80 Having discussed above in detail the evidence received in this proceeding concerning
all material matters, and having stated above our findings and conclusions upon issues
in dispute among the parties and the reasons supporting the findings and conclusions,
the Commission now makes and enters the following summary findings of fact,
incorporating by reference pertinent portions of the preceding detailed findings:

81 (1) The Washington Utilities and Transportation Commission is an agency of the
State of Washington, vested by statute with authority to regulate rates, rules,
regulations, practices, and accounts of public service companies, including
electric and gas companies.

82 (2) Avista Utilities is a “public service company,” an “electrical company,” and a
“gas company,” as those terms are defined in RCW 80.04.010, and as those
terms are used in RCW Title 80. Avista is engaged in Washington State in the
business of supplying utility services and natural gas to the public for
compensation.

83 (3) The existing rates for electric and natural gas service provided by Avista in
Washington are insufficient to yield reasonable compensation for the services
rendered. Avista requires prospective rate relief for its electric and natural gas
services in Washington.
ICNU_DR_113 Attachment A Page 33 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 34
ORDER 08

CONCLUSIONS OF LAW

84 Having discussed above all matters material to this decision, and having stated
detailed findings, conclusions, and the reasons therefore, the Commission now makes
the following summary conclusions of law incorporating by reference pertinent
portions of the preceding detailed conclusions:

85 (1) The Washington Utilities and Transportation Commission has jurisdiction over
the subject matter of, and parties to, this proceeding. RCW Title 80.

86 (2) The rates proposed by tariff revisions filed by Avista Utilities on March 4,
2008, and suspended by prior Commission order, were not shown to be fair,
just or reasonable and should be rejected.

87 (3) Avista Utilities’ existing rates for electric and natural gas service provided in
Washington are insufficient to yield reasonable compensation for the service
rendered. Avista Utilities requires relief with respect to the rates it charges for
electric and natural gas service provided in Washington.

88 (4) Informal settlements in administrative proceedings are encouraged. RCW
34.05.060. The Commission may approve settlements “when doing so is
lawful, when the settlement terms are supported by an appropriate record, and
when the result is consistent with the public interest in light of all the
information available to the commission.” WAC 480-07-750(1).

89 (5) The Settlement is supported by the record, and is consistent with the law and
the public interest.

90 (6) The electric and natural gas rates resulting from adoption of the Settlement are
fair, just, reasonable, and sufficient for services Avista Utilities provides to
customers in Washington.

ICNU_DR_113 Attachment A Page 34 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 35
ORDER 08

91 (7) Avista should have the opportunity to earn an overall rate of return of 8.22
percent based on the capital structure and costs of capital set forth in the body
of this Order, including a return on equity of 10.2 percent on an equity share of
46.3 percent.

92 (8) Avista should be authorized and required to make a compliance filing to
recover its revenue deficiency of $32.5 million for electric service and $4.8
million for natural gas service, consistent with the terms of this Order.

93 (9) The Commission Secretary should be authorized to accept by letter, with
copies to all parties to this proceeding, a filing that complies with the
requirements of this Order.

94 (10) The Commission should retain jurisdiction over the subject matter of and the
parties to this proceeding to effectuate the terms of this Order. RCW Title 80.
ORDER

THE COMMISSION ORDERS THAT:

95 (1) The proposed tariff revisions filed by Avista Utilities on March 4, 2008, and
suspended by prior Commission order, are rejected.

96 (2) The Settlement attached as Appendix A and incorporated into this Order by
prior reference is approved and adopted.

97 (3) Avista Utilities is authorized and required to file tariff sheets following the
effective date of this Order that are necessary and sufficient to effectuate its
terms. The required tariff sheets must be filed by 5:00 p.m. on December 30,
2008.

98 (4) The Commission Secretary is authorized to accept by letter, with copies to all
parties to this proceeding, a filing that complies with the requirements of this
Order.

99 (5) The Commission retains jurisdiction to effectuate the terms of this Order.
ICNU_DR_113 Attachment A Page 35 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 36
ORDER 08

Dated at Olympia, Washington, and effective December 29, 2008.

WASHINGTON STATE UTILITIES AND TRANSPORTATION COMMISSION

MARK H. SIDRAN, Chairman

PATRICK J. OSHIE, Commissioner

PHILIP B. JONES, Commissioner

NOTICE TO PARTIES: This is a final order of the Commission. In addition to
judicial review, administrative relief may be available through a petition for
reconsideration, filed within 10 days of the service of this order pursuant to
RCW 34.05.470 and WAC 480-07-850, or a petition for rehearing pursuant to
RCW 80.04.200 or RCW 81.04.200 and WAC 480-07-870.
ICNU_DR_113 Attachment A Page 36 of 37
DOCKET UE-080416/UG-080417 (Consolidated) PAGE 37
ORDER 08

APPENDIX A

MULTI-PARTY SETTLEMENT STIPULATION

ICNU_DR_113 Attachment A Page 37 of 37

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/09/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 113 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference FERC account 540100. Please provide an explanation for why the Company is incurring approximately $5.7 million ($3.7 million, Washington-allocated) per year in connection with a
settlement agreement with the State of Montana.

RESPONSE: Please refer to the Direct Testimony of Mrs. Smith (JSS-IT) on page 17:

In the Montana Riverbed lease settlement, the Company agreed to pay the State of Montana
$4.0 million annually beginning in 2007, with annual inflation adjustments, for a 10-year period for leasing the riverbed under the Noxon Rapids Project and the Montana portion of
the Cabinet Gorge Project. The first two annual payments were deferred by Avista as
approved in Docket No. UE-072131. In Docket No. UE-080416 (see Order No. 08), the
Commission approved the Company’s accounting treatment of the deferred payments,
including accrued interest, to be amortized over the remaining eight years of the agreement starting on January 1, 2009.

Please also see ICNU_DR_113 Attachment A for a copy of the order referenced in Mrs. Smith’s
accounting testimony regarding Commission approval of the deferred treatment and amortization of
the first two annual payments, as well as recovery of the annual lease expense payment.
See ICNU_DR_114 for copies of the settlement document with the State of Montana requiring the
annual payment. Also please see ICNU_DR_115 for a description of the litigation and basis for the
settlement.
ICNU_DR_114 Attachment A Page 1 of 3
ICNU_DR_114 Attachment A Page 2 of 3
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ICNU_DR_114 Attachment D Page 1 of 2
ICNU_DR_114 Attachment D Page 2 of 2

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/11/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 114 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a copy of the settlement agreement with the State of Montana leading to the annual charge of $5.7 million ($3.7 million, Washington-allocated) per year described in the prior request.
RESPONSE: Please see the following attachments:

• ICNU_DR_114 Attachment A for a copy of the Memorandum of Negotiated Settlement Terms
• ICNU_DR_114 Attachment B for a copy of the Hydropower Lease
• ICNU_DR_114 Attachment C for a copy of the Consent Judgment Between Avista and Montana
• ICNU_DR_114 Attachment D for a copy of the Final Order and Judgment See also Avista’s response to ICNU_DR_113 and 115.

Page 1 of 2
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Elizabeth Andrews
REQUESTER: ICNU RESPONDER: David Meyer
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 115 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Does the Company agree that in the U.S. Supreme Court case PPL Montana, LLC v. Montana, 132 S. Ct. 1215 (2012), the Court held that “[t]he Montana Supreme Court’s ruling that Montana owns
and may charge for use of the riverbeds at issue was based on an infirm legal understanding of this
Court’s rules of navigability for title under the equal-footing doctrine”? If yes, please provide an
explanation for why ratepayers are continuing to pay settlement costs to the State of Montana
identified in account 540100.
RESPONSE:
While the Supreme Court did so rule, the Court remanded the case back to Montana for further
proceedings to apply the “rule of navigability” to the specific facts of each river segment. As discussed below, that case is now pending before the U.S. District Court for the District of Montana.

The following background information will provide additional context: Several weeks before trial
was to start against Avista and PPL Montana (“PPL”), District Court Judge Honzel entered an Order in 2007 finding that the Clark Fork River and various other rivers on which PPL had hydro facilities were navigable and therefore the bed and banks of those rivers were owned by the State of
Montana (“State”). As a result, the only issues for trial was the amount of past damages and future
rental payments owed by Avista and PPL.
Prior to trial, the State, through its expert, claimed that Avista owed $200,374,752 in damages for past rent, and rent of $8,416,510 per year starting in 2006. Faced with the District Court’s ruling on
navigability, the significant judgment being sought, and the probability that the Montana Supreme
Court would affirm the District Court’s ruling (which it ultimately did), Avista reached a settlement
with the State. In exchange for Avista agreeing to pay $4,000,000 per year in rent (with an annual CPI adjustment), the State agreed to dismiss all of its other claims, including all damages for past rent. In addition, the Settlement Agreement contained a Most Favored Nation provision which
provides, among other things, that if PPL achieves a more favorable outcome at trial or through
settlement, Avista will receive the benefit of that outcome.
Following Avista’s settlement, the case proceeded to trial against PPL. After hearing the evidence, Judge Honzel entered judgment against PPL for past rent of $34,743,261 and for annual payments
of $6,207,919 starting in 2007. Based upon Judge Honzel’s ruling, if Avista had remained in the
case, it is likely judgment would have been entered against it for approximately $58 million for past
rents and more than $7 million per year in future rents beginning in 2007, which, including post-judgment interest, would have exposed Avista’s ratepayers to an additional $98 million in costs,

Page 2 of 2
beyond the agreed-upon level of rent. Since Avista’s settlement was much more favorable than the
outcome PPL obtained at trial, the Most Favored Nation provision was not triggered.
After the Montana Supreme Court affirmed the District Court’s ruling, PPL sought review in the
U.S. Supreme Court. Of the 7,713 cases filed in the U.S. Supreme Court during its 2011 Term, the
Court only accepted 79 cases. PPL’s appeal was one of those few cases. Had the Court not
accepted review, the decision of the Montana Supreme Court against PPL would have stood.
The U.S. Supreme Court ultimately ruled that the determination of riverbed title, under the Equal-
Footing Doctrine, should be made on a segment-by-segment basis depending on the facts.
Consequently, the U.S. Supreme Court reversed the Montana Supreme Court and remanded the
case against PPL back to Montana for further proceedings surrounding the navigability of each
river segment.
The case is currently pending in the United States District Court for the District of Montana. A trial
date concerning the navigability of the various rivers at issue on a segment-by-segment basis, has
not yet been scheduled. Given the Most Favored Nation provision in Avista’s Settlement
Agreement, if PPL (or its successor in interest, NorthWestern) achieves a more favorable outcome at trial or through settlement, the Most Favored Nation provision will be triggered and Avista will
receive the benefit of that outcome through a reduction or elimination of the annual rent it is
paying.

Also see Avista’s responses to ICNU_DR_113 and 114.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 116 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Subledger transaction ID: PA.15842441.147.15842441 (Project Desc: “Nez Perce Payment – Washington”). Please provide a description of this payment and an overview of why it
is assigned a WA jurisdiction code.

RESPONSE: The $43,292.00 referenced above represents the monthly accrual of Washington’s share of the Nez
Perce annual payment ($835,498 System and $519,506 Washington).

As explained in the Company’s Nez Perce adjustment (2.14), the $835,498 payments is allocated to Washington and Idaho using the original PT ratio of 62.18% Washington and 37.82% Idaho within
the Company’s General Ledger (GL).

Restated Adjustment 2.14 “Nez Perce Adjustment” restates Washington’s expense based on that
approved in Washington Docket No. UE-991606. See Company witness Ms. Smith Testimony Exhibit No.__(JSS-1T) page 26, lines 14-22 and accompanying workpapers with the Company’s
direct filed case.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/29/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Jennifer Smith
REQUESTER: ICNU RESPONDER: Ryan Finesilver
TYPE: Data Request DEPT: State & Fed Regulation
REQUEST NO.: ICNU – 117 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide transaction-level detail of all amounts paid (either directly or indirectly) to the Nez Perce tribe in the test period.
RESPONSE: Please see ICNU_DR_117 Attachment A for the requested information. See also Avista’s response
to ICNU_DR_116.

ICNU_DR_118 Attachment A

Page 1 of 235

ICNU_DR_118 Attachment A

Page 2 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
LIST OF SCHEDULES (Electric Utility)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
101General Information 1
102Control Over Respondent 2
103Corporations Controlled by Respondent 3
104Officers 4
105Directors 5
106(a)(b)Information on Formula Rates 6
108-109Important Changes During the Year 7
110-113Comparative Balance Sheet 8
114-117Statement of Income for the Year 9
118-119Statement of Retained Earnings for the Year 10
120-121Statement of Cash Flows 11
122-123Notes to Financial Statements 12
122(a)(b)Statement of Accum Comp Income, Comp Income, and Hedging Activities 13
200-201Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 14
202-203Nuclear Fuel Materials 15
204-207Electric Plant in Service 16
213Electric Plant Leased to Others 17
214Electric Plant Held for Future Use 18
216Construction Work in Progress-Electric 19
219Accumulated Provision for Depreciation of Electric Utility Plant 20
224-225Investment of Subsidiary Companies 21
227Materials and Supplies 22
228(ab)-229(ab)Allowances 23
230Extraordinary Property Losses 24
230Unrecovered Plant and Regulatory Study Costs 25
231Transmission Service and Generation Interconnection Study Costs 26
232Other Regulatory Assets 27
233Miscellaneous Deferred Debits 28
234Accumulated Deferred Income Taxes 29
250-251Capital Stock 30
253Other Paid-in Capital 31
254Capital Stock Expense 32
256-257Long-Term Debt 33
261Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 34
262-263Taxes Accrued, Prepaid and Charged During the Year 35
266-267Accumulated Deferred Investment Tax Credits 36
FERC FORM NO. 1 (ED. 12-96)Page 2

ICNU_DR_118 Attachment A

Page 3 of 235
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
269Other Deferred Credits 37
272-273Accumulated Deferred Income Taxes-Accelerated Amortization Property 38
274-275Accumulated Deferred Income Taxes-Other Property 39
276-277Accumulated Deferred Income Taxes-Other 40
278Other Regulatory Liabilities 41
300-301Electric Operating Revenues 42
302Regional Transmission Service Revenues (Account 457.1) 43
304Sales of Electricity by Rate Schedules 44
310-311Sales for Resale 45
320-323Electric Operation and Maintenance Expenses 46
326-327Purchased Power 47
328-330Transmission of Electricity for Others 48
331Transmission of Electricity by ISO/RTOs 49
332Transmission of Electricity by Others 50
335Miscellaneous General Expenses-Electric 51
336-337Depreciation and Amortization of Electric Plant 52
350-351Regulatory Commission Expenses 53
352-353Research, Development and Demonstration Activities 54
354-355Distribution of Salaries and Wages 55
356Common Utility Plant and Expenses 56
397Amounts included in ISO/RTO Settlement Statements 57
398Purchase and Sale of Ancillary Services 58
400Monthly Transmission System Peak Load 59
400aMonthly ISO/RTO Transmission System Peak Load 60
401Electric Energy Account 61
401Monthly Peaks and Output 62
402-403Steam Electric Generating Plant Statistics 63
406-407Hydroelectric Generating Plant Statistics 64
408-409Pumped Storage Generating Plant Statistics 65
410-411Generating Plant Statistics Pages 66
FERC FORM NO. 1 (ED. 12-96)Page 3

ICNU_DR_118 Attachment A

Page 4 of 235
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
422-423Transmission Line Statistics Pages 67
424-425Transmission Lines Added During the Year 68
426-427Substations 69
429Transactions with Associated (Affiliated) Companies 70
450Footnote Data 71
Stockholders' Reports Check appropriate box:
X Two copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO. 1 (ED. 12-96)Page 4

ICNU_DR_118 Attachment A

Page 5 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
GENERAL INFORMATION
Avista Corporation X
04/15/2016 2015/Q4
State of Washington, Incorporated March 15, 1889
R. Krasselt, Vice President, Controller, and Principal Accounting Officer
1411 E. Mission Avenue
Spokane, WA 99207
1. Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) Yes...Enter the date when such independent accountant was initially engaged:
(2) NoX
Not Applicable
Electric service in the states of Washington, Idaho, and Montana
Natural gas service in the states of Wasington, Idaho, and Oregon
FERC FORM No.1 (ED. 12-87)PAGE 101

ICNU_DR_118 Attachment A

Page 6 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
CORPORATIONS CONTROLLED BY RESPONDENT
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Name of Company Controlled Kind of Business Percent Voting
Stock Owned
(c)(b)(a)
Footnote
Ref.
(d)
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual
agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the
Uniform System of Accounts, regardless of the relative voting rights of each party.
Parent company to the 100 1 Avista Capital, Inc.
Company's subsidiaries. 2
3
Maintains an investment 100 4 Avista Development, Inc.Subsidiary of
portfolio of real estate and 5 Avista Capital
other investments. 6
7
Inactive 100 8 Avista Energy, Inc.Subsidiary of
9 Avista Capital
10
Parent company of Bay Area 100 11 Pentzer Corporation Subsidiary of
Manufacturing and Pentzer 12 Avista Capital
Venture Holdings. 13
14
Inactive 100 15 Pentzer Venture Holdings II, Inc.Subsidiary of
16 Pentzer Corporation
17
Holding Company 100 18 Bay Area Manufacturing, Inc.Subsidiary of
19 Pentzer Corporation
20
Performs custom sheet metal 82.95 21 Advanced Manufacturing and Development, Inc.Subsidiary of
manufacturing of electronic 22 dba Metalfx Bay Area
enclosures, parts and systems 23 Manufacturing.
for the computer, telecom and 24
medical industries. AM&D 25
also has a wood products 26
division. 27
FERC FORM NO. 1 (ED. 12-96)Page 103

ICNU_DR_118 Attachment A

Page 7 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
CORPORATIONS CONTROLLED BY RESPONDENT
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Name of Company Controlled Kind of Business Percent Voting
Stock Owned
(c)(b)(a)
Footnote
Ref.
(d)
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual
agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the
Uniform System of Accounts, regardless of the relative voting rights of each party.
1
An affiliated business trust 100 2 Avista Capital II Affliate of
formed by the Company. 3 Avista Corp.
Issued Pref. Trust Securities 4
5
Formed in 2009 to own 100 6 Avista Northwest Resources, LLC Affiliate of
an interest in a venture 7 Avista Capital
fund investment 8
9
Commercial office and retail 85 10 Steam Plant Square, LLC Affiliate of
leasing. 11 Avista Development
12
Commercial office and retail 100 13 Courtyard Office Center, LLC Affiliate of
leasing. 14 Avista Development
15
Restaurant operations 85 16 Steam Plant Brew Pub, LLC Affiliate of Steam
17 Plant Square, LLC
18
Formed in 2014 to explore 100 19 Salix Subsidiary of
markets that could be served 20 Avista Capital
with Liquefied Natural Gas 21
mostly in Western N. America 22
23
Parent company of Alaska 100 24 Alaska Energy and Resources Company (AERC)Subsidiary of
operations. 25 Avista Corp.
26
Utility operations based in 100 27 Alaska Electric Light and Power Company Subsidiary of
FERC FORM NO. 1 (ED. 12-96)Page 103.1

ICNU_DR_118 Attachment A

Page 8 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
CORPORATIONS CONTROLLED BY RESPONDENT
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Name of Company Controlled Kind of Business Percent Voting
Stock Owned
(c)(b)(a)
Footnote
Ref.
(d)
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual
agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the
Uniform System of Accounts, regardless of the relative voting rights of each party.
the City and Borough of 1 AERC
Juneau, AK 2
3
Inactive mining company 100 4 AJT Mining Properties, Inc.Subsidiary of
holding certain properties in 5 AERC
the City and Borough of 6
Juneau, AK 7
8
Holds certain rights to 100 9 Snettisham Electric Company Subsidiary of
purchase the Snettisham 10 AERC
Hydroelectric project in the 11
City and Borough of 12
Juneau, AK 13
14
Owns an electric capacity 100 15 Spokane Energy Affiliate of
contract. 16 Avista Corp
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. 1 (ED. 12-96)Page 103.2

ICNU_DR_118 Attachment A

Page 9 of 235
Schedule Page: 103.2 Line No.: 15 Column: a
Spokane Energy was dissolved as of July 2015.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 10 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
OFFICERS
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Title Name of Officer Salaryfor Year(c)(b)(a)
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Chairman of the Board, President 804,231S. L. Morris 1
and Chief Executive Officer 2
3
Senior Vice President, Chief Financial Officer, 421,769M. T. Thies 4
and Treasurer 5
6
Senior Vice President, General Counsel 356,155M. M. Durkin 7
and Chief Compliance Officer 8
9
Senior Vice President, Chief Human Resources Officer, 320,845K. S. Feltes 10
and Corporate Secretary 11
12
Senior Vice President and Environmental 387,520D. P. Vermillion 13
Compliance Officer, President of Avista Utilities 14
15
Senior Vice President, responsible for Energy 299,537J. R. Thackston 16
Resources 17
18
Vice President, Controller, and 194,096C. M. Burmeister-Smith 19
Principal Accounting Officer (retired 10/1/2015) 20
21
Vice President, Controller, and 157,774R. L. Krasselt 22
Principal Accounting Officer (effective 10/1/2015) 23
24
Vice President, Chief Information Officer, and 259,211J. M. Kensok 25
Chief Security Officer 26
27
Vice President, responsible for Energy Delivery 270,894D. F. Kopczynski 28
and Customer Service (retired 12/1/2015) 29
30
Vice President and Chief Counsel for Regulatory 277,250D. J. Meyer 31
and Governmental Affairs 32
33
Vice President, responsible for State and Federal 253,462K. O. Norwood 34
Regulations 35
36
Vice President, responsible for Customer 216,369K. J. Christie 37
Solutions (effective 2/9/2015) 38
39
Vice President, responsible for Energy 208,334H. L. Rosentrater 40
Delivery (effective 12/1/2015) 41
42
Vice President and Chief Strategy Officer 74,442E. D. Schlect 43
(effective 9/8/2015) 44
FERC FORM NO. 1 (ED. 12-96)Page 104

ICNU_DR_118 Attachment A

Page 11 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
OFFICERS
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Title Name of Officer Salaryfor Year(c)(b)(a)
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
Vice President, and 253,462R. D. Woodworth 1
President, Avista Development (effective 11/1/2015) 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 104.1

ICNU_DR_118 Attachment A

Page 12 of 235

This Page Intentionally Left Blank

ICNU_DR_118 Attachment A

Page 13 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
DIRECTORS
Avista Corporation X
04/15/2016
2015/Q4
Line Name (and Title) of Director Principal Business Address(b)(a)No.
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
1411 E Mission Ave., Spokane, WA, 99202Scott L. Morris** 1
(Chairman of the Board, President & CEO) 2
3
3720 Carillon Point, Kirkland, WA 98033Erik J. Anderson 4
5
P.O. Box 28338, Spokane, WA 99228Kristianne Blake*** 6
7
16 Ivy Court, Langhorne, PA 19047Donald C. Burke 8
9
851 Georgia Ave., Winter Park, FL 33143John F. Kelly*** 10
11
P.O. Box 2884, Spokane, WA 99220Heidi B. Stanley 12
13
111 Main Street, Lewiston, ID 83501R. John Taylor*** 14
15
28013 Swan Cove Dr., Big Fork, MT 59911Marc F. Racicot 16
17
611 S. Congress Ave., Suite 125, Austin, TX 78704Rebecca A. Klein 18
19
26 Sanford Ln., Lafayette, CA 94549Janet D. Widmann 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-95)Page 105

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Page 14 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
INFORMATION ON FORMULA RATES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.FERC Rate Schedule or Tariff Number FERC Proceeding
Does the respondent have formula rates?Yes
NoX
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
FERC Rate Schedule/Tariff Number FERC Proceeding
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (NEW. 12-08)Page 106

ICNU_DR_118 Attachment A

Page 15 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.\ Filed DateAccession No.
Date
Docket No.Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
INFORMATION ON FORMULA RATES
Does the respondent file with the Commission annual (or more frequent)Yes
NoX
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
FERC Rate Schedule/Tariff Number FERC Proceeding
filings containing the inputs to the formula rate(s)?
Document
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (NEW. 12-08)Page 106a

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Page 16 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.Page No(s). Schedule Column Line No
INFORMATION ON FORMULA RATES
1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
Formula Rate Variances
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
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23
24
25
26
27
28
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30
31
32
33
34
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36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (NEW. 12-08)Page 106b

ICNU_DR_118 Attachment A

Page 17 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
IMPORTANT CHANGES DURING THE QUARTER/YEAR
Avista Corporation X 04/15/2016 2015/Q4
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto,
and reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts
were submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of
customers added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major
new continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have
occurred during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
FERC FORM NO. 1 (ED. 12-96)Page 108

ICNU_DR_118 Attachment A

Page 18 of 235
1. None
2. None
3. None
4. None
5. None
6. Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0
million that expires in April 2019.
Balances outstanding (including letters of credit) under the Company’s revolving committed lines of credit were
as follows as of December 31, 2015 and December 31, 2014 (dollars in thousands):
December 31, December 31,
2015 2014
Balance outstanding at end of period $105,000 $105,000
Letters of credit outstanding at end of period $44,595 $32,579
In December 2015, Avista Corp. issued $100.0 million of first mortgage bonds to five institutional investors in a
private placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045.
The total net proceeds from the sale of the new bonds were used to repay a portion of the borrowings
outstanding under the Company’s $400.0 million committed line of credit and for general corporate purposes.
The debt issuance was approved by regulatory commissions as follows:WUTC (Docket No. U-111176 Order
02) IPUC (Case No. AVU-U-11-01 Order No. 32338) and the OPUC (Docket UF 4294 Order No. 15-305).
7. None
8. Average annual wage increases were 2.4% for non-exempt employees effective February 23, 2015. Average
annual wage increases were 3.0% for exempt employees effective February 23, 2015. Officers received average
increases of 3.3% effective February 23, 2015. Certain bargaining unit employees received increases of 3.0%
effective March 26, 2015.
9. Reference is made to Note 16 of the Notes to Financial Statements.
10. None
11. Reserved
12. See page 123 of this report.
13. Effective February 2015, Kevin J Christie was promoted to Vice President of Customer Solutions. He had
previously held various other management and staff positions with the Company since 2005.
Effective October 1, 2015, Christy Burmeister-Smith, former Vice President, Controller and Principal
Accounting Officer retired. Ryan Krasselt, formerly the Director of Risk Management was selected to fill
Christy's role upon her retirement. Ryan has previously held various other finance and accounting management
and staff positions with the Company for 14 years.
On September 8, 2015, Ed Schlect, was appointed Vice President and Chief Strategy Officer. Ed was the former
Executive Vice President of Corporate Development at Ecova, Avista Corp.'s former unregulated subsidiary.
Roger Woodworth, previously Vice President and Chief Strategy Officer was promoted to President of Avista
Development, an Avista Corp. subsidiary, in support of economic development within the Company's utility
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1

ICNU_DR_118 Attachment A

Page 19 of 235
service areas.
On December 1, 2015, Don Kopczynski, Vice President, Energy Delivery and Customer Service retired.
Heather Rosentrater, formerly Avista’s Director of Electrical Engineering and Grid Modernization, was
selected to fill Don’s role upon his retirement. Heather has previously held various other management and staff
positions with the Company for 19 years.
14. Proprietary capital is not less than 30 percent.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.2

ICNU_DR_118 Attachment A

Page 20 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
Avista Corporation 04/15/2016 2015/Q4
UTILITY PLANT 1
4,923,194,978 4,513,148,224200-201Utility Plant (101-106, 114) 2
190,108,665 223,330,993200-201Construction Work in Progress (107) 3
5,113,303,643 4,736,479,217TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
1,680,907,938 1,573,767,832200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
3,432,395,705 3,162,711,385Net Utility Plant (Enter Total of line 4 less 5) 6
0 0202-203Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 7
0 0Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8
0 0Nuclear Fuel Assemblies in Reactor (120.3) 9
0 0Spent Nuclear Fuel (120.4) 10
0 0Nuclear Fuel Under Capital Leases (120.6) 11
0 0202-203(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 12
0 0Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13
3,432,395,705 3,162,711,385Net Utility Plant (Enter Total of lines 6 and 13) 14
0 0Utility Plant Adjustments (116) 15
6,992,076 6,992,076Gas Stored Underground - Noncurrent (117) 16
OTHER PROPERTY AND INVESTMENTS 17
2,740,379 5,288,635Nonutility Property (121) 18
201,768 194,911(Less) Accum. Prov. for Depr. and Amort. (122) 19
11,547,000 12,047,000Investments in Associated Companies (123) 20
157,515,280 148,255,851224-225Investment in Subsidiary Companies (123.1) 21
(For Cost of Account 123.1, See Footnote Page 224, line 42) 22
0 0228-229Noncurrent Portion of Allowances 23
23,760,324 11,525,386Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
20,755,670 11,488,865Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
22,687 0Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
216,139,572 188,410,826TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32
CURRENT AND ACCRUED ASSETS 33
0 0Cash and Working Funds (Non-major Only) (130) 34
2,074,149 1,535,172Cash (131) 35
14,430,708 6,832,649Special Deposits (132-134) 36
691,896 971,206Working Fund (135) 37
204,231 15,508,864Temporary Cash Investments (136) 38
0 0Notes Receivable (141) 39
160,488,098 163,095,696Customer Accounts Receivable (142) 40
5,500,743 5,091,552Other Accounts Receivable (143) 41
4,469,344 4,828,572(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
0 0Notes Receivable from Associated Companies (145) 43
469,096 401,126Accounts Receivable from Assoc. Companies (146) 44
3,293,585 4,116,727227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
33,931,771 29,419,472227Plant Materials and Operating Supplies (154) 48
0 0227Merchandise (155) 49
0 0227Other Materials and Supplies (156) 50
0 0202-203/227Nuclear Materials Held for Sale (157) 51
0 0228-229Allowances (158.1 and 158.2) 52
FERC FORM NO. 1 (REV. 12-03)Page 110

ICNU_DR_118 Attachment A

Page 21 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
Avista Corporation 04/15/2016 2015/Q4
(Continued)
0 0(Less) Noncurrent Portion of Allowances 53
0 0227Stores Expense Undistributed (163) 54
12,774,487 28,731,498Gas Stored Underground - Current (164.1) 55
0 0Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56
10,580,934 13,368,084Prepayments (165) 57
0 0Advances for Gas (166-167) 58
39,738 31,080Interest and Dividends Receivable (171) 59
1,749,949 1,740,695Rents Receivable (172) 60
0 0Accrued Utility Revenues (173) 61
527,051 614,449Miscellaneous Current and Accrued Assets (174) 62
706,117 1,524,582Derivative Instrument Assets (175) 63
22,687 0(Less) Long-Term Portion of Derivative Instrument Assets (175) 64
0 460,316Derivative Instrument Assets - Hedges (176) 65
0 0(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 66
242,970,522 268,614,596Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
11,527,001 12,476,292Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
0 0230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
573,031,070 576,247,558232Other Regulatory Assets (182.3) 72
467,080 165,866Prelim. Survey and Investigation Charges (Electric) (183) 73
0 0Preliminary Natural Gas Survey and Investigation Charges 183.1) 74
0 0Other Preliminary Survey and Investigation Charges (183.2) 75
527 28,145Clearing Accounts (184) 76
0 0Temporary Facilities (185) 77
26,759,597 11,803,983233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
15,520,432 17,356,781Unamortized Loss on Reaquired Debt (189) 81
136,036,119 123,261,474234Accumulated Deferred Income Taxes (190) 82
-17,880,236 -3,921,214Unrecovered Purchased Gas Costs (191) 83
745,461,590 737,418,885Total Deferred Debits (lines 69 through 83) 84
4,643,959,465 4,364,147,768TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85
FERC FORM NO. 1 (REV. 12-03)Page 111

ICNU_DR_118 Attachment A

Page 22 of 235
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
Avista Corporation 04/15/2016 2015/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
PROPRIETARY CAPITAL 1
984,400,740984,603,843Common Stock Issued (201) 2 250-251
00Preferred Stock Issued (204) 3 250-251
00Capital Stock Subscribed (202, 205) 4
00Stock Liability for Conversion (203, 206) 5
00Premium on Capital Stock (207) 6
-9,520,161-9,506,476Other Paid-In Capital (208-211) 7 253
00Installments Received on Capital Stock (212) 8 252
00(Less) Discount on Capital Stock (213) 9 254
-25,079,123-29,238,213(Less) Capital Stock Expense (214) 10 254b
507,257,161536,821,476Retained Earnings (215, 215.1, 216) 11 118-119
-15,658,553-5,881,619Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119
00(Less) Reaquired Capital Stock (217) 13 250-251
00 Noncorporate Proprietorship (Non-major only) (218) 14
-7,887,881-6,649,771Accumulated Other Comprehensive Income (219) 15 122(a)(b)
1,483,670,4291,528,625,666Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
1,436,700,0001,536,700,000Bonds (221) 18 256-257
83,700,00083,700,000(Less) Reaquired Bonds (222) 19 256-257
51,547,00051,547,000Advances from Associated Companies (223) 20 256-257
00Other Long-Term Debt (224) 21 256-257
186,550177,666Unamortized Premium on Long-Term Debt (225) 22
1,308,6041,134,563(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
1,403,424,9461,503,590,103Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
03,274,583Obligations Under Capital Leases - Noncurrent (227) 26
00Accumulated Provision for Property Insurance (228.1) 27
240,000239,910Accumulated Provision for Injuries and Damages (228.2) 28
189,489,100201,453,549Accumulated Provision for Pensions and Benefits (228.3) 29
00Accumulated Miscellaneous Operating Provisions (228.4) 30
5,855,84511,476,706Accumulated Provision for Rate Refunds (229) 31
22,093,16652,248,445Long-Term Portion of Derivative Instrument Liabilities 32
40,857,4560Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
3,028,39115,996,704Asset Retirement Obligations (230) 34
261,563,958284,689,897Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
105,000,000105,000,000Notes Payable (231) 37
111,077,010109,244,954Accounts Payable (232) 38
9,934,84322,177,680Notes Payable to Associated Companies (233) 39
714,03918,798Accounts Payable to Associated Companies (234) 40
4,977,2593,273,927Customer Deposits (235) 41
-10,725,2977,186,818Taxes Accrued (236) 42 262-263
13,595,66714,179,517Interest Accrued (237) 43
00Dividends Declared (238) 44
00Matured Long-Term Debt (239) 45
FERC FORM NO. 1 (rev. 12-03)Page 112

ICNU_DR_118 Attachment A

Page 23 of 235
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
Avista Corporation 04/15/2016 2015/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
50,2261,759,040Tax Collections Payable (241) 47
57,483,99857,577,117Miscellaneous Current and Accrued Liabilities (242) 48
4,193,852871,667Obligations Under Capital Leases-Current (243) 49
40,138,12185,797,553Derivative Instrument Liabilities (244) 50
22,093,16652,248,445(Less) Long-Term Portion of Derivative Instrument Liabilities 51
48,202,0460Derivative Instrument Liabilities - Hedges (245) 52
40,857,4560(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53
321,691,142354,838,626Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
1,864,5082,161,687Customer Advances for Construction (252) 56
12,157,50712,639,187Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
21,269,74039,790,303Other Deferred Credits (253) 59 269
48,834,35540,976,484Other Regulatory Liabilities (254) 60 278
2,096,0441,966,507Unamortized Gain on Reaquired Debt (257) 61
00Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
582,721,352646,870,366Accum. Deferred Income Taxes-Other Property (282) 63
224,853,787227,810,639Accum. Deferred Income Taxes-Other (283) 64
893,797,293972,215,173Total Deferred Credits (lines 56 through 64) 65
4,364,147,7684,643,959,465TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66
FERC FORM NO. 1 (rev. 12-03)Page 113

ICNU_DR_118 Attachment A

Page 24 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STATEMENT OF INCOME
Avista Corporation X
04/15/2016
2015/Q4
Line
(c)(b)(a)
Title of Account
No.
Total
Current Year to
Date Balance for
Quarter/Year
(d)
(Ref.)
Page No.
Quarterly
1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the current year quarter.
4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l)
the quarter to date amounts for other utility function for the prior year quarter.
5. If additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
Total
Prior Year to
Date Balance for
Quarter/Year
UTILITY OPERATING INCOME 1
1,530,543,739 1,572,976,141300-301Operating Revenues (400) 2
Operating Expenses 3
980,245,446 1,034,794,124320-323Operation Expenses (401) 4
64,022,756 65,573,481320-323Maintenance Expenses (402) 5
122,488,709 112,562,200336-337Depreciation Expense (403) 6
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
21,544,004 16,874,247336-337Amort. & Depl. of Utility Plant (404-405) 8
99,047 99,047336-337Amort. of Utility Plant Acq. Adj. (406) 9
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
1,619,427 1,871,414Regulatory Debits (407.3) 12
12,818,909 10,536,841(Less) Regulatory Credits (407.4) 13
95,109,798 93,076,918262-263Taxes Other Than Income Taxes (408.1) 14
5,601,404 -55,133,870262-263Income Taxes - Federal (409.1) 15
919,149 -1,858,807262-263 - Other (409.1) 16
65,371,809 135,547,906234, 272-277Provision for Deferred Income Taxes (410.1) 17
2,423,024 4,060,583234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
481,680 -229,524266Investment Tax Credit Adj. - Net (411.4) 19
(Less) Gains from Disp. of Utility Plant (411.6) 20
Losses from Disp. of Utility Plant (411.7) 21
(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
Accretion Expense (411.10) 24
1,342,261,296 1,388,579,712TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
188,282,443 184,396,429Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114

ICNU_DR_118 Attachment A

Page 25 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line Previous Year to Date
(in dollars)
(k)(j)(g)
ELECTRIC UTILITY
No.Current Year to Date
(in dollars)
OTHER UTILITY
(l)
GAS UTILITY
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
(h)(i)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
1
1,006,140,061 557,872,268 524,403,678 1,015,103,873 2
3
567,238,063 450,554,506 413,007,383 584,239,618 4
50,148,482 14,413,103 13,874,274 51,160,378 5
95,895,130 23,464,789 26,593,579 89,097,411 6
7
16,519,997 3,865,760 5,024,007 13,008,487 8
99,047 99,047 9
10
11
2,650,525 335,464 -1,031,098 1,535,950 12
12,146,367 428,185 672,542 10,108,656 13
72,133,173 23,496,384 22,976,625 69,580,534 14
10,884,847 -27,238,957 -5,283,443 -27,894,913 15
936,622 -1,141,835 -17,473 -716,972 16
54,107,931 41,450,511 11,263,878 94,097,395 17
2,599,365 -142,779 -176,341 4,203,362 18
511,740 -33,996 -30,060 -195,528 19
20
21
22
23
24
856,379,825 528,880,323 485,881,471 859,699,389 25
149,760,236 28,991,945 38,522,207 155,404,484 26
FERC FORM NO. 1 (ED. 12-96)Page 115

ICNU_DR_118 Attachment A

Page 26 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
Previous Year
(c)(b)(a)
Title of Account
No.
Current Year
TOTAL
(d)
(Ref.)
Page No.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
188,282,443 184,396,429Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
Revenues From Merchandising, Jobbing and Contract Work (415) 31
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
-17,531Revenues From Nonutility Operations (417) 33
9,566,840 9,837,245(Less) Expenses of Nonutility Operations (417.1) 34
-939 -1,100Nonoperating Rental Income (418) 35
11,164,785 82,361,715119Equity in Earnings of Subsidiary Companies (418.1) 36
645,403 1,845,367Interest and Dividend Income (419) 37
7,961,552 8,678,360Allowance for Other Funds Used During Construction (419.1) 38
795,424Miscellaneous Nonoperating Income (421) 39
142,552 290,479Gain on Disposition of Property (421.1) 40
11,141,937 83,320,045TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
38,668Loss on Disposition of Property (421.2) 43
Miscellaneous Amortization (425) 44
3,208,021 3,879,397 Donations (426.1) 45
3,079,994 2,060,570 Life Insurance (426.2) 46
70,316 -24,718 Penalties (426.3) 47
1,625,650 1,679,329 Exp. for Certain Civic, Political & Related Activities (426.4) 48
1,386,500 3,295,162 Other Deductions (426.5) 49
9,370,481 10,928,408TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
202,511 150,614262-263Taxes Other Than Income Taxes (408.2) 52
-715,329 -314,356262-263Income Taxes-Federal (409.2) 53
-886,632 2,579,615262-263Income Taxes-Other (409.2) 54
1,006,935 -1,467,880234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
5,704,734 6,039,386234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
(Less) Investment Tax Credits (420) 58
-6,097,249 -5,091,393TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
7,868,705 77,483,030Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
69,747,769 67,341,170Interest on Long-Term Debt (427) 62
419,914 424,830Amort. of Debt Disc. and Expense (428) 63
3,004,198 3,219,369Amortization of Loss on Reaquired Debt (428.1) 64
8,883 8,883(Less) Amort. of Premium on Debt-Credit (429) 65
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66
605,274 735,498Interest on Debt to Assoc. Companies (430) 67
2,636,227 2,037,957Other Interest Expense (431) 68
3,480,392 3,911,170(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
72,924,107 69,838,771Net Interest Charges (Total of lines 62 thru 69) 70
123,227,041 192,040,688Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71
Extraordinary Items 72
Extraordinary Income (434) 73
(Less) Extraordinary Deductions (435) 74
Net Extraordinary Items (Total of line 73 less line 74) 75
262-263Income Taxes-Federal and Other (409.3) 76
Extraordinary Items After Taxes (line 75 less line 76) 77
123,227,041 192,040,688Net Income (Total of line 71 and 77) 78
FERC FORM NO. 1/3-Q (REV. 02-04)Page 117

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Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
Avista Corporation X
04/15/2016
2015/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
403,295,872 492,987,406 1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
( 39,369,910) -1,488,991 11 Repurchases from Common Stock
12
13
14
( 39,369,910) -1,488,991 15 TOTAL Debits to Retained Earnings (Acct. 439)
109,678,973 112,062,256 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 4,555,754) -5,158,174 18 Excess Earnings
19
20
21
( 4,555,754) -5,158,174 22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
( 78,313,788) -82,396,803 31
32
33
34
35
( 78,313,788) -82,396,803 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
102,252,013 1,387,851 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
492,987,406 517,393,545 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
14,269,755 19,427,931 39
40
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118

ICNU_DR_118 Attachment A

Page 29 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
Avista Corporation X
04/15/2016
2015/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Previous
Quarter/Year
Year to Date
Balance
(d)
41
42
43
44
14,269,755 19,427,931 45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
14,269,755 19,427,931 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
507,257,161 536,821,476 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
( 5,918,024) -15,658,553 49 Balance-Beginning of Year (Debit or Credit)
82,361,715 11,164,785 50 Equity in Earnings for Year (Credit) (Account 418.1)
51 (Less) Dividends Received (Debit)
( 92,102,244) -1,387,851 52 Corb Sub Activity
( 15,658,553) -5,881,619 53 Balance-End of Year (Total lines 49 thru 52)
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119

ICNU_DR_118 Attachment A

Page 30 of 235
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STATEMENT OF CASH FLOWS
Avista Corporation X
04/15/2016
2015/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
192,040,688 123,227,041 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
126,986,417 138,235,780 4 Depreciation and Depletion
-14,611,016 21,357,796 5 Amortization of Deferred Power and Natural Gas Costs
3,635,317 3,415,229 6 Amortization of Debt Expense
2,450,031 2,450,031 7 Amortization of Investment in Exchange Power
123,968,809 53,931,102 8 Deferred Income Taxes (Net)
-229,524 481,680 9 Investment Tax Credit Adjustment (Net)
17,645,850 -3,884,715 10 Net (Increase) Decrease in Receivables
-19,413,226 12,267,853 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
-40,191,116 6,880,543 13 Net Increase (Decrease) in Payables and Accrued Expenses
10,925,414 -4,114,779 14 Net (Increase) Decrease in Other Regulatory Assets
4,616,847 2,007,784 15 Net Increase (Decrease) in Other Regulatory Liabilities
8,678,360 7,961,552 16 (Less) Allowance for Other Funds Used During Construction
82,361,715 11,164,785 17 (Less) Undistributed Earnings from Subsidiary Companies
-22,727,203 4,382,761 18 Other (provide details in footnote):
5,200,000 5,749,995 19 Allowance for Doubtful Accounts
-15,740,101 5,891,691 20 Changes in Other Non-Current Assets and Liabilities
21
283,517,112 353,153,455 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
-323,931,192 -381,174,406 26 Gross Additions to Utility Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
-323,931,192 -381,174,406 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
272,897 37 Proceeds from Disposal of Noncurrent Assets (d)
2,529,902 2,730,166 38 Federal and State Grant Payments Received
15,444,378 12,185,571 39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
-4,697,090 -94,643 43 Cash Paid for Acquisition
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. 1 (ED. 12-96)Page 120

ICNU_DR_118 Attachment A

Page 31 of 235
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and Cash
Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be reported
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes to
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STATEMENT OF CASH FLOWS
Avista Corporation X
04/15/2016
2015/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
Previous Year to Date
Quarter/Year
(c)
46 Loans Made or Purchased
47 Collections on Loans
94,098 -62,284 48 Restricted Cash
49 Net (Increase) Decrease in Receivables
50 Net (Increase ) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote):
-373,865 -7,992,961 54 Changes in Other Property and Investments
197,000,000 2,000,000 55 Dividends Received from Subsidiaries
56 Net Cash Provided by (Used in) Investing Activities
-113,933,769 -372,135,660 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
60,000,000 100,000,000 61 Long-Term Debt (b)
62 Preferred Stock
4,059,874 1,559,840 63 Common Stock
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
64,059,874 101,559,840 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-297,339 -734,802 73 Long-term Debt (b)
74 Preferred Stock
-79,855,898 -2,919,781 75 Common Stock
107,021 -1,651,248 76 Other (provide details in footnote):
-1,510,532 -593,969 77 Debt Issuance Costs
-66,000,000 78 Net Decrease in Short-Term Debt (c)
5,429,000 -9,326,000 79 Cash Received (Paid) for Settlement of Interest Rate Swaps
80 Dividends on Preferred Stock
-78,313,788 -82,396,801 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
-156,381,662 3,937,239 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
13,201,681 -15,044,966 86 (Total of lines 22,57 and 83)
87
4,813,561 18,015,242 88 Cash and Cash Equivalents at Beginning of Period
89
18,015,242 2,970,276 90 Cash and Cash Equivalents at End of period
FERC FORM NO. 1 (ED. 12-96)Page 121

ICNU_DR_118 Attachment A

Page 32 of 235
Schedule Page: 120 Line No.: 18 Column: b
Power and natural gas deferrals 1,121,287
Change in special deposits (13,301,265)
Change in other current assets 2,856,640
Non-cash stock compensation 6,913,619
Amortization of Spokane Energy contract 9,499,494
Change in Coyote Springs 2 O&M LTSA (2,260,661)
Preliminary survey and investigation costs (301,214)
Gain on sale of property and equipment (142,552)
Other (2,587)
Schedule Page: 120 Line No.: 18 Column: c
Power and natural gas deferrals 1,104,752
Change in special deposits (23,301,320)
Change in other current assets (5,671,849)
Non-cash stock compensation 6,006,850
Cash paid for foreign currency hedges 20,692
Change in Coyote Springs 2 O&M LTSA (1,082,230)
Preliminary survey and investigation costs 709,287
Tax shortfalls from stock compensation (513,385)
Schedule Page: 120 Line No.: 76 Column: b
Excess tax benefits 180,431
Payment of minimum withholdings
for share based payment awards (1,831,679)
Schedule Page: 120 Line No.: 76 Column: c
Excess tax benefits 107,021
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

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ICNU_DR_118 Attachment A

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Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
NOTES TO FINANCIAL STATEMENTS
Avista Corporation X 04/15/2016 2015/Q4
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of
a claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such
matters shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
FERC FORM NO. 1 (ED. 12-96)Page 122

ICNU_DR_118 Attachment A

Page 35 of 235
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corp. is primarily an electric and natural gas utility with certain other business ventures. Avista Corp. provides electric
distribution and transmission, and natural gas distribution services in parts of eastern Washington and northern Idaho. Avista Corp.
also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Corp. has electric generating
facilities in Washington, Idaho, Oregon and Montana. Avista Corp. also supplies electricity to a small number of customers in
Montana, most of whom are employees who operate Avista Corp.’s Noxon Rapids generating facility.
On July 1, 2014, Avista Corp. acquired AERC, and as of that date, AERC became a wholly-owned subsidiary of Avista Corp. The
primary subsidiary of AERC is AEL&P, comprising regulated electric utility operations in Juneau, Alaska. There are no AERC
earnings included in the overall results of Avista Corp. prior to July 1, 2014. See Note 3 for information regarding the acquisition of
AERC.
Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies except AERC.
During the first half of 2014 and prior, Avista Capital’s subsidiaries included Ecova, which was an 80.2 percent owned subsidiary prior
to its disposition on June 30, 2014. Ecova was a provider of energy efficiency and other facility information and cost management
programs and services for multi-site customers and utilities throughout North America. See Note 4 for information regarding the
disposition of Ecova.
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses of the Company and have been prepared in accordance
with the accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles
generally accepted in the United States of America (U.S. GAAP). As required by the FERC, the Company accounts for its investment
in majority-owned subsidiaries on the equity method rather than consolidating the assets, liabilities, revenues, and expenses of these
subsidiaries, as required by U.S. GAAP. The accompanying financial statements include the Company’s proportionate share of utility
plant and related operations resulting from its interests in jointly owned plants. In addition, under the requirements of the FERC, there
are differences from U.S. GAAP in the presentation of (1) current portion of long-term debt (2) assets and liabilities for cost of
removal of assets, (3) assets held for sale, (4) regulatory assets and liabilities, (5) deferred income taxes associated with accounts other
than utility property, plant and equipment, (6) comprehensive income, (7) unamortized debt issuance costs and (8) operating revenues
and resource costs associated with settled energy contracts that are “booked out” (not physically delivered).
Use of Estimates
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that
affect the amounts reported for assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include:
determining the market value of energy commodity derivative assets and liabilities,
pension and other postretirement benefit plan obligations,
contingent liabilities,
goodwill impairment testing,
recoverability of regulatory assets, and
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.1

ICNU_DR_118 Attachment A

Page 36 of 235
unbilled revenues.
Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the financial
statements and thus actual results could differ from the amounts reported and disclosed herein.
System of Accounts
The accounting records of the Company’s utility operations are maintained in accordance with the uniform system of accounts
prescribed by the FERC and adopted by the state regulatory commissions in Washington, Idaho, Montana and Oregon.
Regulation
The Company is subject to state regulation in Washington, Idaho, Montana and Oregon. The Company is also subject to federal
regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its
operations.
Operating Revenues
Operating revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. The
determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis
throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter
reading is estimated and the corresponding unbilled revenue is estimated and recorded. Our estimate of unbilled revenue is based on:the number of customers,current rates,meter reading dates,actual native load for electricity,actual throughput for natural gas, and
electric line losses and natural gas system losses.
Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading
and customer billing occurs.
Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
2015 2014
Unbilled accounts receivable $59,405 $ 78,007
Depreciation
For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility
plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the
ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31:
2015 2014
Ratio of depreciation to average depreciable property 3.09%2.97%
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.2

ICNU_DR_118 Attachment A

Page 37 of 235
The average service lives for the following broad categories of utility plant in service are (in years):
Avista Corp.
Electric thermal/other production 40
Hydroelectric production 79
Electric transmission 57
Electric distribution 36
Natural gas distribution property 45
Taxes Other Than Income Taxes
Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and
certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes
collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled
the following amounts for the years ended December 31 (dollars in thousands):
2015 2014
Utility taxes $57,716 $ 57,599
Allowance for Funds Used During Construction
The AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period.
As prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant and the debt component is credited
against total interest expense in the Statements of Income in the line item “capitalized interest.” The equity component of AFUDC is
included in the Statement of Income in the line item “other income-net.” The Company is permitted, under established regulatory rate
practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the provision for
depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the related utility
plant is placed in service and included in rate base. The effective AFUDC rate was the following for the years ended December 31:
2015 2014
Effective AFUDC rate 7.32%7.64%
Income Taxes
A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between
the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company’s
consolidated income tax returns. The deferred income tax expense for the period is equal to the net change in the deferred income tax
asset and liability accounts from the beginning to the end of the period. The effect on deferred income taxes from a change in tax rates
is recognized in income in the period that includes the enactment date. Deferred income tax liabilities and regulatory assets are
established for income tax benefits flowed through to customers. The Company recognizes the effect of state tax credits, which are
generated from utility plant, as they are utilized. The Company did not incur any penalties on income tax positions in 2015 or 2014.
The Company would recognize interest accrued related to income tax positions as interest expense and any penalties incurred as other
income deductions.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.3

ICNU_DR_118 Attachment A

Page 38 of 235
Stock-Based Compensation
The Company currently issues three types of stock-based compensation awards - restricted shares, market-based awards and
performance-based awards. Historically, these stock compensation awards have not been material to the Company's overall financial
results. Compensation cost relating to share-based payment transactions is recognized in the Company’s financial statements based on
the fair value of the equity or liability instruments issued and recorded over the requisite service period.
The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the
Statements of Income of the following amounts for the years ended December 31 (dollars in thousands):
2015 2014
Stock-based compensation expense $ 6,914 $ 6,007
Income tax benefits 2,420 2,102
Restricted share awards vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the
end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target
in order for the CEO’s restricted shares to vest. Restricted stock is valued at the close of market of the Company’s common stock on
the grant date.
Total Shareholder Return (TSR) awards are market-based awards and Cumulative Earnings Per Share (CEPS) awards are performance
awards. CEPS awards were first granted in 2014. Both types of awards vest after a period of three years and are payable in cash or
Avista Corp. common stock at the end of the three-year period. The method of settlement is at the discretion of the Company and
historically the Company has settled these awards through issuance of Avista Corp. common stock and intends to continue this
practice. Both types of awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances,
and are subject to meeting specific market or performance conditions. Based on the level of attainment of the market or performance
conditions, the amount of cash paid or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend
equivalent rights are accumulated and paid out only on shares that eventually vest and have met the market and performance
conditions.
For both the TSR awards and the CEPS awards, the Company accounts for them as equity awards and compensation cost for these
awards is recognized over the requisite service period, provided that the requisite service period is rendered. For TSR awards, if the
market-condition is not met at the end of the three-year service period, there will be no change in the cumulative amount of
compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS
awards, at the end of the three-year service period, if the internal performance metric of cumulative earnings per share is not met, all
compensation cost for these awards is reversed as these awards are not considered vested.
The fair value of each TSR award is estimated on the date of grant using a statistical model that incorporates the probability of meeting
the market targets based on historical returns relative to a peer group. The estimated fair value of the equity component of CEPS
awards was estimated on the date of grant as the share price of Avista Corp. common stock on the date of grant, less the net present
value of the estimated dividends over the three-year period.
The following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other
pertinent information related to the Company's stock compensation awards for the years ended December 31:
2015 2014
Restricted Shares
Shares granted during the year 58,302 62,075
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.4

ICNU_DR_118 Attachment A

Page 39 of 235
Shares vested during the year (60,379) (52,899)
Unvested shares at end of year 106,091 112,042
Unrecognized compensation expense at end of year (in thousands)$ 1,705 $ 1,349
TSR Awards
TSR shares granted during the year 116,435 117,550
TSR shares vested during the year (171,334) (167,584)
TSR shares earned based on market metrics 222,734 97,199
Unvested TSR shares at end of year 223,697 287,834
Unrecognized compensation expense (in thousands)$ 3,219 $ 2,833
CEPS Awards
CEPS shares granted during the year 58,259 59,025
Unvested CEPS shares at end of year 111,887 58,017
Unrecognized compensation expense (in thousands)$ 1,840 $ 1,577
Outstanding TSR and CEPS share awards include a dividend component that is paid in cash. This component of the share grants is
accounted for as a liability award. These liability awards are revalued on a quarterly basis taking into account the number of awards
outstanding, historical dividend rate, the change in the value of the Company’s common stock relative to an external benchmark (TSR
awards only) and the amount of CEPS earned to-date compared to estimated CEPS over the performance period (CEPS awards only).
Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid. As of
December 31, 2015 and 2014, the Company had recognized cumulative compensation expense and a liability of $1.5 million and $1.3
million, respectively, related to the dividend component on the outstanding and unvested share grants.
Cash and Cash Equivalents
For the purposes of the Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or
less when purchased to be cash equivalents.
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The
Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts.
Utility Plant in Service
The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of
property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is
charged to accumulated depreciation.
Asset Retirement Obligations
The Company records the fair value of a liability for an asset retirement obligation (ARO) in the period in which it is incurred. When
the liability is initially recorded, the associated costs of the ARO are capitalized as part of the carrying amount of the related long-lived
asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over the useful life of
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5

ICNU_DR_118 Attachment A

Page 40 of 235
the related asset. In addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded
during the period new information becomes available as an increase or decrease to the liability, with the offset recorded to the related
long-lived asset. Upon retirement of the asset, the Company either settles the ARO for its recorded amount or incurs a gain or loss. The
Company records regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and
AROs recorded since asset retirement costs are recovered through rates charged to customers (see Note 7 for further discussion of the
Company's asset retirement obligations).
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Balance Sheets measured at estimated fair value. In certain defined
conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for a derivative depends
on the intended use of such derivative and the resulting designation.
The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities
with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on
energy commodity transactions until the period of delivery. The orders provide for Avista Corp. to not recognize the unrealized gain or
loss on utility derivative commodity instruments in the Statements of Income. Realized gains or losses are recognized in the periods of
delivery, subject to approval for recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in
adjustments to retail rates through purchased gas cost adjustments, the ERM in Washington, the PCA mechanism in Idaho, and
periodic general rates cases. Regulatory assets are assessed regularly and are probable for recovery through future rates.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated
fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual
basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be
other-than-temporary.
For interest rate swap agreements, each period Avista Corp. records all mark-to-market gains and losses as assets and liabilities and
records offsetting regulatory assets and liabilities, such that there is no income statement impact. Upon settlement of interest rate
swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a component of interest expense over the
term of the associated debt. While the Company has not received any formal accounting orders from the various state commissions
allowing for the offset of interest rate swap assets and liabilities with regulatory assets and liabilities, the Company has deemed this
accounting treatment appropriate and future recovery probable due to the regulatory precedents set in prior general rate cases and the
fact that the state commissions view interest rate swap derivatives as risk management tools similar to energy commodity derivatives.
As of December 31, 2015, the Company has multiple master netting agreements with a variety of entities that allow for
cross-commodity netting of derivative agreements with the same counterparty (i.e. power derivatives can be netted with natural gas
derivatives) under ASC 815-10-45. The Company does not have any agreements which allow for cross-affiliate netting among multiple
affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the Balance
Sheets.
Fair Value Measurements
Fair value represents the price that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly
transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred
compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are
reported at estimated fair value on the Balance Sheets. See Note 14 for the Company’s fair value disclosures.
Regulatory Deferred Charges and Credits
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.6

ICNU_DR_118 Attachment A

Page 41 of 235
The Company prepares its financial statements in accordance with regulatory accounting practices because:
rates for regulated services are established by or subject to approval by independent third-party regulators,
the regulated rates are designed to recover the cost of providing the regulated services, and
in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be
charged to and collected from customers at levels that will recover costs.
Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not
currently included in rates, but expected to be recovered or refunded in the future), are reflected as deferred charges or credits on the
Balance Sheets. These costs and/or obligations are not reflected in the Statements of Income until the period during which matching
revenues are recognized. The Company also has decoupling revenue deferrals, which began in 2015. As opposed to cost deferrals
which are not recognized in the Statements of Income until they are included in rates, decoupling revenue is recognized in the
Statements of Income during the period it occurs (i.e. during the period of revenue shortfall or excess due to fluctuations in customer
usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or rebated to customers in
future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be collected
from customers within 24 months of the deferral to qualify for recognition in the current period Statement of Income. Any amounts
included in the Company's decoupling program that won't be collected from customers within 24 months are not recorded in the
financial statements until the period in which revenue recognition criteria are met. This could ultimately result in more decoupling
revenue being collected from customers over the life of the decoupling program than what is deferred and recognized in the current
period financial statements.
If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory
accounting practices for all or a portion of its regulated operations, the Company could be:
required to write off its regulatory assets, and
precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such
amounts are incurred, even if the Company expected to recover these amounts from customers in the future.
Investment in Exchange Power-Net
The investment in exchange power represents the Company’s previous investment in Washington Public Power Supply System Project
3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power
Administration in 1985, Avista Corp. began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-3.
Through a settlement agreement with the UTC in the Washington jurisdiction, Avista Corp. is amortizing the recoverable portion of its
investment in WNP-3 (recorded as investment in exchange power) over a 32.5-year period that began in 1987. For the Idaho
jurisdiction, Avista Corp. fully amortized the recoverable portion of its investment in exchange power.
Unamortized Debt Expense
Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt.
Unamortized Loss on Reacquired Debt
For the Company’s Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums
paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in
connection with the repurchase, these costs are amortized over the life of the new debt. In the Company’s other regulatory
jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding
debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7

ICNU_DR_118 Attachment A

Page 42 of 235
component of interest expense.
Appropriated Retained Earnings
In accordance with the hydroelectric licensing requirements of section 10(d) of the Federal Power Act (FPA), the Company maintains
an appropriated retained earnings account for any earnings in excess of the specified rate of return on the Company's investment in the
licenses for its various hydroelectric projects. Per section 10(d) of the FPA, the Company must maintain these excess earnings in an
appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in
the licenses of the hydroelectric projects at the discretion of the FERC. The Company typically calculates the earnings in excess of the
specified rate of return on an annual basis, usually during the second quarter.
The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
2015 2014
Appropriated retained earnings $19,428 $14,270
Operating Leases
The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to 45 years. Future
minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year
were not material as of December 31, 2015.
Equity in Earnings of Subsidiaries
The Company records all the earnings from its subsidiaries under the equity method. The Company had the following equity in
earnings of its subsidiaries for the years ended December 31 (dollars in thousands):
2015 2014
Avista Capital $4,857 $79,183
Alaska Energy and Resources Company 6,308 3,179
Total equity in earnings of subsidiary companies $11,165 $82,362
Avista Capital, a wholly owned subsidiary of Avista Corp., is the parent company of all of the subsidiary companies, except AERC
(and its subsidiaries). Avista Capital’s subsidiaries and investments include sheet metal fabrication, venture fund investments, real
estate investments, a company that explores markets that could be served with LNG and Ecova prior to its disposition on June 30,
2014.
AERC, a wholly-owned subsidiary of Avista Corp. acquired on July 1, 2014, is the parent company to all the Alaska subsidiary
companies. The primary subsidiary of AERC is AEL&P, comprising the regulated utility operations in Alaska. Also, AERC owns AJT
Mining Properties, Inc., an inactive mining company holding certain properties.
Subsequent Events
Management has evaluated the impact of events occurring after December 31, 2015 up to February 24, 2016, the date that Avista
Corp.’s U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through April 15, 2016.
These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
Contingencies
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8

ICNU_DR_118 Attachment A

Page 43 of 235
The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss
contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated.
The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a material loss
may be incurred. As of December 31, 2015, the Company has not recorded any significant amounts related to unresolved
contingencies. See Note 16 for further discussion of the Company's commitments and contingencies.
NOTE 2. NEW ACCOUNTING STANDARDS
In April 2014, the FASB issued ASU No. 2014-08, "Presentation of Financial Statements (Topic 205) and Property, Plant, and
Equipment (Topic 360): Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity." This ASU
amends the definition of a discontinued operation and requires entities to provide additional disclosures about discontinued operations
as well as disposal transactions that do not meet the discontinued-operations criteria. ASU 2014-08 makes it more difficult for a
disposal transaction to qualify as a discontinued operation. In addition, the ASU requires entities to reclassify assets and liabilities of a
discontinued operation for all comparative periods presented in the Balance Sheet rather than just the current period, and it requires
additional disclosures on the face of the Statement of Cash Flows regarding discontinued operations. This ASU became effective for
periods beginning on or after December 15, 2014; however, early adoption was permitted. The Company evaluated this standard and
determined that it would not early adopt this standard. Since the disposition of Ecova occurred before the effective date of this
standard, and the Company did not early adopt this standard, there is no impact on the Company's financial condition, results of
operations and cash flows in the current year.
In May 2014, the FASB issued ASU No. 2014-09, "Revenue from Contracts with Customers (Topic 606)," which outlines a single
comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current
revenue recognition guidance, including industry-specific guidance. The core principle of the revenue model is that an entity identifies
the various performance obligations in a contract, allocates the transaction price among the performance obligations and recognizes
revenue as the entity satisfies the performance obligations. This ASU was originally effective for periods beginning after December 15,
2016 and early adoption is not permitted. In August 2015, the FASB issued ASU 2015-14 Revenue from Contracts with Customers
(Topic 606): Deferral of the Effective Date," which deferred the effective date of ASU 2014-09 for one year, with adoption as of the
original date permitted. However, while this ASU is not effective until 2018, it will require retroactive application to all periods
presented in the financial statements. As such, at adoption in 2018, amounts in 2016 and 2017 may have to be revised or a cumulative
adjustment to opening retained earnings may have to be recorded. The Company is evaluating this standard and cannot, at this time,
estimate the potential impact on its future financial condition, results of operations and cash flows.
In February 2015, the FASB issued ASU No. 2015-02, "Consolidation (Topic 810): Amendments to the Consolidation Analysis." This
ASU significantly changes the consolidation analysis required under GAAP, including the identification of variable interest entities
(VIE). The ASU also removes the deferral of the VIE analysis related to investments in certain investment funds, which will result in a
different consolidation evaluation for these types of investments. This ASU is effective for periods beginning on or after December 15,
2015; however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this
standard. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial
condition, results of operations and cash flows.
In April 2015, the FASB issued ASU No. 2015-05, "Intangibles - Goodwill and Other - Internal-Use Software (Subtopic 350-40):
Customer’s Accounting for Fees Paid in a Cloud Computing Arrangement." This ASU provides guidance on how organizations should
account for fees paid in a cloud computing arrangement, including helping organizations understand whether their arrangement
includes a software license. If the arrangement includes a software license, the software license would be accounted for in a manner
consistent with internal-use software. If a cloud-computing arrangement does not include a software license, the customer is required to
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9

ICNU_DR_118 Attachment A

Page 44 of 235
account for the arrangement as a service contract. This ASU is effective for periods beginning on or after December 15, 2015;
however, early adoption is permitted. The Company evaluated this standard and determined that it will not early adopt this standard.
Upon adoption, an entity can elect to apply this ASU prospectively or retroactively and disclose the method selected. The Company is
evaluating this standard and cannot, at this time, estimate the potential impact on its future financial condition, results of operations and
cash flows.
In May 2015, the FASB issued ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for Investments in Certain
Entities That Calculate Net Asset Value per Share (or Its Equivalent)." This ASU removes, from the fair value hierarchy,
investments for which the practical expedient is used to measure fair value at net asset value (NAV). Instead, an entity is required to
include those investments as a reconciling line item so that the total fair value amount of investments in the disclosure is consistent
with the amount on the balance sheet. Further, entities must provide certain disclosures for investments for which they elect to use the
NAV practical expedient to determine fair value. This ASU is effective for periods beginning on or after December 15, 2015 and early
adoption is permitted. The Company evaluated this standard and determined that it will early adopt this standard as of December 31,
2015. As required, this ASU is being applied retrospectively to all periods presented. The adoption of this standard did not affect the
Company's future financial condition, results of operations and cash flows; however, it did affect the Company's disclosures. See Note
8 and 14 for the expanded disclosures surrounding the adoption of this ASU.
In February 2016, the FASB issued ASU 2016-02 “Leases (Topic 842).” This ASU introduces a new lessee model that brings most
leases on the balance sheet. The standard also aligns certain of the underlying principles of the new lessor model with those in ASC
606, the FASB’s new revenue recognition standard. Furthermore, the ASU addresses other concerns related to the current leases
model; for example, eliminating the required use of bright-line tests in current GAAP for determining lease classification (operating
leases versus capital leases). This ASU also includes enhanced disclosures surrounding leases. This ASU is effective for periods
beginning on or after December 15, 2018; however, early adoption is permitted. The Company evaluated this standard and determined
that it will not early adopt this standard as of December 31, 2015. Upon adoption, this ASU must be applied using a modified
retrospective approach. The modified retrospective approach includes a number of optional practical expedients that entities may elect
to apply. The Company is evaluating this standard and cannot, at this time, estimate the potential impact on its future financial
condition, results of operations and cash flows.
NOTE 3. BUSINESS ACQUISITIONS
Alaska Energy and Resources Company
On July 1, 2014, the Company acquired AERC, based in Juneau, Alaska, and as of that date, AERC became a wholly-owned subsidiary
of Avista Corp.
The primary subsidiary of AERC is AEL&P, a regulated utility which provides electric services to approximately 17,000 customers in
the City and Borough of Juneau (Juneau), Alaska as of December 31, 2015. In addition to the regulated utility, AERC owns AJT
Mining, which is an inactive mining company holding certain properties.
The purpose of the acquisition was to expand and diversify Avista Corp.’s energy assets and deliver long-term value to its customers,
communities and investors.
In connection with the closing, on July 1, 2014 Avista Corp. issued 4,500,014 new shares of common stock to the shareholders of
AERC based on a contractual formula that resulted in a price of $32.46 per share, reflecting a purchase price of $170.0 million, plus
acquired cash, less outstanding debt and other closing adjustments.
The $32.46 price per share of Avista Corp. common stock was determined based on the average closing stock price of Avista Corp.
common stock for the 10 consecutive trading days immediately preceding, but not including, the trading day prior to July 1, 2014. This
value was used solely for determining the number of shares to issue based on the adjusted contract closing price (see reconciliation
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10

ICNU_DR_118 Attachment A

Page 45 of 235
below). The fair value of the consideration transferred at the closing date was based on the closing stock price of Avista Corp. common
stock on July 1, 2014, which was $33.35 per share.
On October 1, 2014, a working capital adjustment was made in accordance with the agreement and plan of merger which resulted in
Avista Corp. issuing an additional 1,427 shares of common stock to the shareholders of AERC. The number of shares issued on
October 1, 2014 was based on the same contractual formula described above. The fair value of the new shares issued in October was
$30.71 per share, which was the closing stock price of Avista Corp. common stock on that date.
The contract acquisition price and the fair value of consideration transferred for AERC were as follows (in thousands, except "per
share" and number of shares data):
Contract acquisition price (using the calculated $32.46 per share common stock price)
Gross contract price $170,000
Acquired cash 19,704
Acquired debt (excluding capital lease obligation)(38,832)
Other closing adjustments (including the working capital adjustment)37
Total adjusted contract price $150,909
Fair value of consideration transferred
Avista Corp. common stock (4,500,014 shares at $33.35 per share)$150,075
Avista Corp. common stock (1,427 shares at $30.71 per share)44
Cash 4,792
Fair value of total consideration transferred $154,911
The assets acquired and liabilities assumed related to the AERC transaction are not included in the FERC Balance Sheets. The
information below is presented for information purposes only. The fair value of assets acquired and liabilities assumed as of July 1,
2014 (after consideration of the working capital adjustment and the income tax true-ups during the second quarter of 2015) were as
follows (in thousands):
July 1, 2014
Assets acquired:
Current Assets:
Cash $19,704
Accounts receivable - gross totals $3,928 3,851
Materials and supplies 2,017
Other current assets 999
Total current assets 26,571
Utility Property:
Utility plant in service 113,964
Utility property under long-term capital lease 71,007
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11

ICNU_DR_118 Attachment A

Page 46 of 235
Construction work in progress 3,440
Total utility property 188,411
Other Non-current Assets:
Non-utility property 6,660
Electric plant held for future use 3,711
Goodwill (1)52,426
Other deferred charges and non-current assets 5,368
Total other non-current assets 68,165
Total assets $283,147
Liabilities Assumed:
Current Liabilities:
Accounts payable $700
Current portion of long-term debt and capital lease obligations 3,773
Other current liabilities (1)2,807
Total current liabilities 7,280
Long-term debt 37,227
Capital lease obligations 68,840
Other non-current liabilities and deferred credits (1)14,889
Total liabilities $128,236
Total net assets acquired $154,911
(1) During the second quarter of 2015, AEL&P recorded a reduction to goodwill of approximately $0.3 million due to income tax
related adjustments. After consideration of the goodwill adjustment in the second quarter of 2015, the transaction resulted in a
total amount of goodwill of $52.4 million. The goodwill associated with this acquisition is not deductible for tax purposes.
The majority of AERC’s operations are subject to the rate-setting authority of the RCA and are accounted for pursuant to GAAP,
including the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for
AERC’s regulated operations provide revenues derived from costs, including a return on investment, of assets and liabilities included
in rate base. Due to this regulation, the fair values of AERC’s assets and liabilities subject to these rate-setting provisions are assumed
to approximate their carrying values. There were not any identifiable intangible assets associated with this acquisition. The excess of
the purchase consideration over the estimated fair values of the assets acquired and liabilities assumed was recognized as goodwill at
the acquisition date. The goodwill reflects the value paid for the expected continued growth of a rate-regulated business located in a
defined service area with a constructive regulatory environment, the attractiveness of stable, growing cash flows, as well as providing a
platform for potential future growth outside of the rate-regulated electric utility in Alaska and potential additional utility investment.
NOTE 4. DISCONTINUED OPERATIONS
On June 30, 2014, Avista Capital, completed the sale of its interest in Ecova to Cofely USA Inc., an indirect subsidiary of GDF SUEZ,
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12

ICNU_DR_118 Attachment A

Page 47 of 235
a French multinational utility company, and an unrelated party to Avista Corp. The sales price was $335.0 million in cash, less the
payment of debt and other customary closing adjustments. At the closing of the transaction on June 30, 2014, Ecova became a
wholly-owned subsidiary of Cofely USA Inc. and the Company has not had and will not have any further involvement with Ecova after
such date.
The purchase price of $335.0 million, as adjusted, was divided among the security holders of Ecova, including minority shareholders,
option holders and a warrant holder, pro rata based on ownership. Approximately $16.8 million (5 percent of the purchase price) was
held in escrow for 15 months from the closing of the transaction to satisfy certain indemnification obligations under the merger
agreement (Escrow). An additional $1.0 million was held in escrow pending resolution of adjustments to working capital. The
indemnification escrow and the working capital adjustment escrow amounts above represent the full amounts to be divided among all
security holders pro rata based on ownership.
As expected, no claims were made against the Escrow as of September 30, 2015 (the end of the claims period) and accordingly, all
Escrow amounts were released in October 2015 and the Company received its full portion of the Escrow proceeds together with the
remainder of the working capital adjustment escrow for a total amount of $13.8 million. After consideration of the escrow amounts
received, the sales transaction provided cash proceeds to Avista Corp., net of debt, payment to option and minority holders, income
taxes and transaction expenses, of $143.7 million and resulted in a net gain of $74.8 million. Almost all of the net gain was recognized
in 2014 with some true-ups during 2015.
The summary of cash proceeds associated with the sales transaction are as follows (in thousands):
Reconciliation of Gross Proceeds
Contract price $335,000
Closing adjustments 4,103
Litigation settlement at Ecova 588
Gross proceeds from sale (1)339,691
Cash sold in the transaction (95,932)
Gross proceeds from sale of Ecova, net of cash sold (2)$243,759
Reconciliation of total net proceeds
Gross proceeds from sale (1)$339,691
Repayment of long-term borrowings under committed line of credit (40,000)
Payment to option holders and redeemable noncontrolling interests (20,871)
Payment to noncontrolling interests (54,179)
Transaction expenses withheld from proceeds (5,461)
Net proceeds to Avista Capital (prior to tax payments) (2)219,180
Tax payments made in 2014 (74,842)
Tax payments made in 2015 (590)
Total net proceeds related to sales transaction $143,748
(1) Of this total amount, approximately $16.8 million was held in escrow for 15 months from the transaction closing date for any
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13

ICNU_DR_118 Attachment A

Page 48 of 235
indemnity claims and an additional $1.0 million was held in escrow pending resolution of adjustments to working capital. Both of
these escrow accounts were resolved during 2015.
(2) Of the total gross proceeds and total net proceeds received, approximately $229.9 million and $205.4 million was received in
2014, respectively, with the remainder being received in 2015.
NOTE 5. DERIVATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices.
Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by
supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista
Corp. utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these
commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks.
As part of the Company's resource procurement and management operations in the electric business, the Company engages in an
ongoing process of resource optimization, which involves the economic selection from available energy resources to serve the
Company's load obligations and the use of these resources to capture available economic value. The Company transacts in wholesale
markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity,
energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging the related financial
risks. These transactions range from terms of intra-hour up to multiple years.
As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its
natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning
typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply locations
to Avista Corp.’s distribution system. However, daily variations in natural gas demand can be significantly different than monthly
demand projections. On the basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a portion of its
projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as
much as four natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of
its natural gas supply requirements unhedged for purchase in short-term and spot markets.
The following table presents the underlying energy commodity derivative volumes as of December 31, 2015 that are expected to be
settled in each respective year (in thousands of MWhs and mmBTUs):
Purchases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives
Year
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
2016 407 1,954 17,252 142,693 280 2,656 3,182 112,233
2017 397 97 675 49,200 255 483 1,360 26,965
2018 397 — —15,118 286 — 1,360 2,738
2019 235 — 305 6,935 158 — 1,345 —
2020 — —455 905 — —1,430 —
Thereafter — — — — — —1,060 —
(1) Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14

ICNU_DR_118 Attachment A

Page 49 of 235
natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of gain or loss but with
no physical delivery of the commodity, such as futures, swaps, options, or forward contracts.
The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during
the period they are settled and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case
process, and are expected to be collected through retail rates from customers.
Foreign Currency Exchange Contracts
A significant portion of Avista Corp.’s natural gas supply (including fuel for power generation) is obtained from Canadian sources.
Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term
natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled
within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency exchange
contracts when such commodity transactions are initiated. This risk has not had a material effect on the Company’s financial condition,
results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural gas supply
costs for ratemaking. The following table summarizes the foreign currency hedges that the Company has entered into as of December
31 (dollars in thousands):
2015 2014
Number of contracts 24 18
Notional amount (in United States dollars)$ 1,463 $ 5,474
Notional amount (in Canadian dollars)2,002 6,198
Interest Rate Swap Agreements
Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. The
Company hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swaps and U.S.
Treasury lock agreements. These interest rate swaps and U.S. Treasury lock agreements are considered economic hedges against
fluctuations in future cash flows associated with anticipated debt issuances.
The following table summarizes the interest rate swaps that the Company has outstanding as of the balance sheet date indicated below
(dollars in thousands):
Balance Sheet Date Number of Contracts Notional Amount
Mandatory Cash Settlement
Date
December 31, 2015 6 115,000 2016
3 45,000 2017
11 245,000 2018
2 30,000 2019
1 20,000 2022
December 31, 2014 5 75,000 2015
5 95,000 2016
3 45,000 2017
9 205,000 2018
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15

ICNU_DR_118 Attachment A

Page 50 of 235
During the third quarter 2015, in connection with the execution of a purchase agreement for bonds that the Company issued in
December 2015, the Company cash-settled five interest rate swap contracts (notional aggregate amount of $75.0 million) and paid a
total of $9.3 million. The interest rate swap contracts were settled in connection with the pricing of $100.0 million of Avista Corp. first
mortgage bonds that were issued in December 2015 (see Note 12). Upon settlement of interest rate swaps, the regulatory asset or
liability is amortized as a component of interest expense over the term of the associated debt.
The fair value of outstanding interest rate swaps can vary significantly from period to period depending on the total notional amount of
swaps outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. The Company would be
required to make cash payments to settle the interest rate swaps if the fixed rates are higher than prevailing market rates at the date of
settlement. Conversely, the Company receives cash to settle its interest rate swaps when prevailing market rates at the time of
settlement exceed the fixed swap rates.
Summary of Outstanding Derivative Instruments
The amounts recorded on the Balance Sheet as of December 31, 2015 and December 31, 2014 reflect the offsetting of derivative assets
and liabilities where a legal right of offset exists.
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2015 (in thousands):
Fair Value
Derivative Balance Sheet Location
Gross
Asset
Gross
Liability
Collateral
Netting
Net Asset
(Liability)
in Balance
Sheet
Foreign currency
contracts
Derivative instrument liabilities current $2 $(19)$—$(17)
Interest rate
contracts
Long-term portion of derivative assets 23 — —23
Interest rate
contracts
Derivative instrument liabilities current 118 (23,262) 3,880 (19,264)
Interest rate
contracts
Long-term portion of derivative instrument
liabilities
1,407 (62,236) 30,150 (30,679)
Commodity
contracts
Derivative instrument assets current 1,236 (553) —683
Commodity
contracts
Derivative instrument liabilities current 67,466 (85,409) 3,675 (14,268)
Commodity
contracts
Long-term portion of derivative liabilities 6,613 (39,033) 10,851 (21,569)
Total derivative instruments recorded on the balance sheet $76,865 $(210,512)$48,556 $(85,091)
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2014 (in thousands):
Fair Value
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16

ICNU_DR_118 Attachment A

Page 51 of 235
Derivative Balance Sheet Location
Gross
Asset
Gross
Liability
Collateral
Netting
Net Asset
(Liability)
in Balance
Sheet
Foreign currency
contracts
Derivative instrument liabilities –Hedges $1 $(21)$—$(20)
Interest rate
contracts
Derivative instrument assets –Hedges 966 (506) —460
Interest rate
contracts
Derivative instrument liabilities –Hedges — (7,325) —(7,325)
Interest rate
contracts
Long-term portion of derivative liabilities -
Hedges
— (69,737) 28,880 (40,857)
Commodity
contracts
Derivative instrument assets current 2,063 (538) —1,525
Commodity
contracts
Long-term portion of derivative assets 66,421 (97,586) 13,120 (18,045)
Commodity
contracts
Long-term portion of derivative liabilities 29,594 (54,077)2,390 (22,093)
Total derivative instruments recorded on the balance sheet $99,045 $(229,790)$44,390 $(86,355)
Exposure to Demands for Collateral
The Company's derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or
reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company's credit
ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden
and significant demands may be made against the Company's credit facilities and cash. The Company actively monitors the exposure to
possible collateral calls and takes steps to mitigate capital requirements.
The following table presents the Company's collateral outstanding related to its derivative instruments as of as of December 31 (in
thousands):
2015 2014
Energy commodity derivatives
Cash collateral posted $ 28,716 $ 20,565
Letters of credit outstanding 28,200 14,500
Balance sheet offsetting (cash collateral against net derivative positions)14,526 15,510
Interest rate swaps
Cash collateral posted 34,030 28,880
Letters of credit outstanding 9,600 10,900
Balance sheet offsetting (cash collateral against net derivative positions)34,030 28,880
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17

ICNU_DR_118 Attachment A

Page 52 of 235
Certain of the Company’s derivative instruments contain provisions that require the Company to maintain an "investment grade" credit
rating from the major credit rating agencies. If the Company’s credit ratings were to fall below “investment grade,” it would be in
violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand
immediate and ongoing collateralization on derivative instruments in net liability positions.
The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are in
a liability position and the amount of additional collateral the Company could be required to post as of December 31 (in thousands):
2015 2014
Energy commodity derivatives
Liabilities with credit-risk-related contingent features $ 7,090 $ 12,911
Additional collateral to post 6,980 16,227
Interest rate swaps
Liabilities with credit-risk-related contingent features 85,498 77,568
Additional collateral to post 18,750 19,404
Credit Risk
Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their
contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and
customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Credit risk includes potential
counterparty default due to circumstances:
relating directly to it,
caused by market price changes, and
relating to other market participants that have a direct or indirect relationship with such counterparty.
Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are
established. Should a counterparty fail to perform, the Company may be required to honor the underlying commitment or to replace
existing contracts with contracts at then-current market prices.
The Company enters into bilateral transactions with various counterparties. The Company also transacts in energy and related
derivative instruments through clearinghouse exchanges.
In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and
western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company’s overall
exposure to credit risk because the counterparties may be similarly affected by changes in conditions.
The Company maintains credit support agreements with certain counterparties and margin calls are periodically made and/or received.
Margin calls are triggered when exposures exceed contractual limits or when there are changes in a counterparty’s creditworthiness.
Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. Negotiating for
collateral in the form of cash, letters of credit, or performance guarantees is common industry practice.
NOTE 6. JOINTLY OWNED ELECTRIC FACILITIES
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.18

ICNU_DR_118 Attachment A

Page 53 of 235
The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, Colstrip, located in southeastern
Montana, and provides financing for its ownership interest in the project. The Company’s share of related fuel costs as well as
operating expenses for plant in service are included in the corresponding accounts in the Statements of Income. The Company’s share
of utility plant in service for Colstrip and accumulated depreciation were as follows as of December 31 (dollars in thousands):
2015 2014
Utility plant in service $ 362,199 $ 350,518
Accumulated depreciation (243,363) (239,845)
NOTE 7. ASSET RETIREMENT OBLIGATIONS
See Note 1 for a discussion of the Company's accounting policy associated with AROs.
Specifically, the Company has recorded liabilities for future AROs to:
restore coal ash containment ponds at Colstrip,
cap a landfill at the Kettle Falls Plant,
remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease, and
dispose of PCBs in certain transformers.
Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:
removal and disposal of certain transmission and distribution assets, and
abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.
On April 17, 2015, the EPA published a final rule regarding CCRs, also termed coal combustion byproducts or coal ash in the Federal
Register and this rule became effective on October 15, 2015. Colstrip, of which Avista Corp. is a 15 percent owner of units 3 and 4,
produces this byproduct. The rule establishes technical requirements for CCR landfills and surface impoundments under Subtitle D of
the Resource Conservation and Recovery Act, the nation's primary law for regulating solid waste. The Company, in conjunction with
the other Colstrip owners, is developing a multi-year compliance plan to strategically address the new CCR requirements and existing
State obligations while maintaining operational stability. During the second quarter of 2015, the operator of Colstrip provided an initial
cost estimate of the expected retirement costs associated with complying with the new CCR rule and this estimate was subsequently
updated during the fourth quarter of 2015. Based on the initial assessments, Avista Corp. recorded an increase to its ARO of $12.5
million during 2015 with a corresponding increase in the cost basis of the utility plant.
The actual asset retirement costs related to the new CCR rule requirements may vary substantially from the estimates used to record the
increased obligation due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data
used to estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and
cover certain impoundments. Avista Corp. will coordinate with the plant operator and continue to gather additional data in future
periods to make decisions about compliance strategies and the timing of closure activities. As additional information becomes
available, Avista Corp. will update the ARO for these changes in estimates, which could be material. The Company expects to seek
recovery of any increased costs related to complying with the new rule through customer rates.
The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31 (dollars
in thousands):
2015 2014
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19

ICNU_DR_118 Attachment A

Page 54 of 235
Asset retirement obligation at beginning of year $ 3,028 $ 2,859
Liabilities incurred 12,539 —
Liabilities settled (29) (41)
Accretion expense (income)459 210
Asset retirement obligation at end of year $15,997 $3,028
NOTE 8. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering the majority of all regular full-time employees at Avista Corp. that were
hired prior to January 1, 2014. Individual benefits under this plan are based upon the employee’s years of service, date of hire and
average compensation as specified in the plan. Non-union employees hired on or after January 1, 2014 participate in a defined
contribution 401(k) plan in lieu of a defined benefit pension plan. The Company’s funding policy is to contribute at least the minimum
amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts
that are currently deductible for income tax purposes. The Company contributed $12.0 million in cash to the pension plan in 2015,
$32.0 million in 2014 and $44.3 million in 2013. The Company expects to contribute $12.0 million in cash to the pension plan in
2016.
The Company also has a SERP that provides additional pension benefits to executive officers and certain key employees of the
Company. The SERP is intended to provide benefits to individuals whose benefits under the defined benefit pension plan are reduced
due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation
plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note.
The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands):
2016 2017 2018 2019 2020 Total 2021-2025
Expected benefit payments $29,182 $30,260 $31,332 $32,804 $34,430 $189,919
The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments
held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with
maturities similar to that of the expected term of pension benefits.
The Company provides certain health care and life insurance benefits for eligible retired employees that were hired prior to January 1,
2014. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services.
The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January 1,
2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution toward
their medical premium.
The Company has a Health Reimbursement Arrangement (HRA) to provide employees with tax-advantaged funds to pay for allowable
medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee’s years
of service and the ending salary. The liability and expense of the HRA are included as other postretirement benefits.
The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement.
Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base
salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension
benefit). The liability and expense for this plan are included as other postretirement benefits.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20

ICNU_DR_118 Attachment A

Page 55 of 235
The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):
2016 2017 2018 2019 2020 Total 2021-2025
Expected benefit payments $7,345 $7,522 $7,713 $7,933 $6,907 $36,560
The Company expects to contribute $7.3 million to other postretirement benefit plans in 2016, representing expected benefit payments
to be paid during the year excluding the Medicare Part D subsidy. The Company uses a December 31 measurement date for its pension
and other postretirement benefit plans.
The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2015 and 2014 and the
components of net periodic benefit costs for the years ended December 31, 2015, 2014 and 2013 (dollars in thousands):
Pension Benefits
Other Post-
retirement Benefits
2015 2014 2015 2014
Change in benefit obligation:
Benefit obligation as of beginning of year $ 634,674 $ 527,004 $ 127,989 $ 108,249
Service cost 19,791 15,757 2,925 1,844
Interest cost 26,117 26,224 5,158 5,226
Actuarial (gain)/loss (35,790) 97,128 12,668 18,714
Plan change (228) —(1,000) —
Transfer of accrued vacation — — —437
Cumulative adjustment to reclassify liability — —(1,521) —
Benefits paid (31,061)(31,439)(7,424)(6,481)
Benefit obligation as of end of year $613,503 $634,674 $138,795 $127,989
Change in plan assets:
Fair value of plan assets as of beginning of year $ 539,311 $ 481,502 $ 31,312 $ 29,732
Actual return on plan assets (4,305) 55,974 (444) 1,580
Employer contributions 12,000 32,000 — —
Benefits paid (29,772)(30,165)——
Fair value of plan assets as of end of year $517,234 $539,311 $30,868 $31,312
Funded status $ (96,269) $(95,363) $(107,927) $(96,677)
Unrecognized net actuarial loss 162,961 175,596 92,433 82,421
Unrecognized prior service cost 25 256 (10,180)(10,379)
Prepaid (accrued) benefit cost 66,717 80,489 (25,674) (24,635)
Additional liability (162,986)(175,852)(82,253)(72,042)
Accrued benefit liability $(96,269)$(95,363)$(107,927)$(96,677)
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21

ICNU_DR_118 Attachment A

Page 56 of 235
Accumulated pension benefit obligation $542,209 $551,615 — —
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22

ICNU_DR_118 Attachment A

Page 57 of 235
Pension Benefits
Other Post-
retirement Benefits
2015 2014 2015 2014
Accumulated postretirement benefit obligation:
For retirees $ 65,652 $ 58,276
For fully eligible employees $ 34,498 $ 31,843
For other participants $ 38,645 $ 37,870
Included in accumulated other comprehensive loss (income) (net of tax):
Unrecognized prior service cost $ 16 $ 166 $ (6,617) $(6,747)
Unrecognized net actuarial loss 105,925 114,138 60,081 53,574
Total 105,941 114,304 53,464 46,827
Less regulatory asset (99,414)(106,484)(53,341)(46,759)
Accumulated other comprehensive loss (income) for unfunded
benefit obligation for pensions and other postretirement
benefit plans $6,527 $7,820 $123 $68
Pension Benefits
Other Post-
retirement Benefits
2015 2014 2015 2014
Weighted average assumptions as of December 31:
Discount rate for benefit obligation 4.57% 4.21% 4.57% 4.16%
Discount rate for annual expense 4.21% 5.10% 4.16% 5.02%
Expected long-term return on plan assets 5.30% 6.60% 6.36% 6.40%
Rate of compensation increase 4.87% 4.87%
Medical cost trend pre-age 65 – initial 7.00% 7.00%
Medical cost trend pre-age 65 – ultimate 5.00% 5.00%
Ultimate medical cost trend year pre-age 65 2022 2021
Medical cost trend post-age 65 – initial 7.00% 7.00%
Medical cost trend post-age 65 – ultimate 5.00% 5.00%
Ultimate medical cost trend year post-age 65 2023 2022
Pension Benefits Other Postretirement Benefits
2015 2014 2015 2014
Components of net periodic benefit
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23

ICNU_DR_118 Attachment A

Page 58 of 235
cost:
Service cost $ 19,791 $ 15,757 $ 2,925 $ 1,844
Interest cost 26,117 26,224 5,158 5,226
Expected return on plan assets (28,299) (32,131) (1,991) (1,903)
Amortization of prior service cost 2 22 (1,199) (1,116)
Net loss recognition 9,451 4,731 5,095 4,289
Net periodic benefit cost $27,062 $14,603 $9,988 $8,340
Plan Assets
The Finance Committee of the Company’s Board of Directors approves investment policies, objectives and strategies that seek an
appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and
funding policies.
The Company has contracted with investment consultants who are responsible for managing/monitoring the individual investment
managers. The investment managers’ performance and related individual fund performance is periodically reviewed by an internal
benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies.
Pension plan assets are invested in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate,
absolute return and commodity funds. In seeking to obtain the desired return to fund the pension plan, the investment consultant
recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which
then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation
percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically
the midpoint of the established range. The target investment allocation percentages by asset classes are indicated in the table below:
2015 2014
Equity securities 27% 27%
Debt securities 58% 58%
Real estate 6% 6%
Absolute return 9% 9%
The fair value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair
value of investment securities traded on a national securities exchange is determined based on the reported last sales price; securities
traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not
readily available or for which market prices do not represent the value at the time of pricing, the investment manager estimates fair
value based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry).
Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit value of the
fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund’s net assets by its units
outstanding at the valuation date. The Company's investments in common/collective trusts have redemption limitations that permit
quarterly redemptions following notice requirements of 45 to 60 days. The fair values of the closely held investments and partnership
interests are based upon the allocated share of the fair value of the underlying assets as well as the allocated share of the undistributed
profits and losses, including realized and unrealized gains and losses. Most of the Company's investments in closely held investments
and partnership interests have redemption limitations that range from bi-monthly to semi-annually following redemption notice
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24

ICNU_DR_118 Attachment A

Page 59 of 235
requirements of 60 to 90 days. One investment in a partnership has a lock-up for redemption currently expiring in 2022 and is subject
to extension.
The fair value of pension plan assets invested in real estate was determined by the investment manager based on three basic
approaches:
properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be
performed as warranted by specific asset or market conditions,
property valuations are reviewed quarterly and adjusted as necessary, and
loans are reflected at fair value.
The fair value of pension plan assets was determined as of December 31, 2015 and 2014.
Effective December 31, 2015, the Company adopted ASU No. 2015-07, "Fair Value Measurement (Topic 820): Disclosures for
Investments in Certain Entities That Calculate Net Asset Value per Share (or Its Equivalent)," which removed from the fair value
hierarchy, investments for which the practical expedient is used to measure fair value at net asset value (NAV). In prior years, the
Company held investments fair valued using NAV and these amounts were included as level 3 items. This ASU was adopted
retrospectively; therefore, the 2014 amounts have been reclassified to conform to the 2015 presentation. Also, since these amounts are
no longer included in the fair value hierarchy as level 3 items, the level 3 reconciliations are no longer applicable and have been
excluded from this footnote.
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of the
pension plan’s assets measured and reported as of December 31, 2015 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Cash equivalents $ 86 $ 10,641 $ — $10,727
Fixed income securities:
U.S. government issues — 47,845 — 47,845
Corporate issues — 187,308 — 187,308
International issues — 34,458 — 34,458
Municipal issues — 22,416 — 22,416
Mutual funds:
U.S. equity securities 87,678 — —87,678
International equity securities 40,343 — —40,343
Absolute return (1)13,996 — —13,996
Plan assets measured at NAV (not subject to hierarchy disclosure)
Common/collective trusts:
Real estate — — —24,147
Partnership/closely held investments:
Absolute return (1)— — —38,302
Private equity funds (2)— — —73
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25

ICNU_DR_118 Attachment A

Page 60 of 235
Real estate ———9,941
Total $142,103 $302,668 $—$517,234
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of the
pension plan’s assets measured and reported as of December 31, 2014 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Cash equivalents $—$3,138 $—$3,138
Fixed income securities:
U.S. government issues 19,681 — —19,681
Corporate issues 104,959 — —104,959
International issues 19,935 — —19,935
Municipal issues 2,762 7,788 — 10,550
Mutual funds:
Fixed income securities 157,415 8 —157,423
U.S. equity securities 103,203 — —103,203
International equity securities 40,838 — —40,838
Absolute return (1)15,334 — —15,334
Plan assets measured at NAV (not subject to hierarchy disclosure)
Common/collective trusts:
Real estate — — —21,303
Partnership/closely held investments:
Absolute return (1)— — —36,114
Private equity funds (2)— — —73
Real estate ———6,760
Total $464,127 $10,934 $—$539,311
(1) This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven,
relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and
(d) market neutral strategies.
(2) This category includes private equity funds that invest primarily in U.S. companies.
The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on market prices. The fair
value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities
traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not
readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the investment manager
based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry). The target
asset allocation was 60 percent equity securities and 40 percent debt securities in both 2015 and 2014.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26

ICNU_DR_118 Attachment A

Page 61 of 235
The fair value of other postretirement plan assets was determined as of December 31, 2015 and 2014.
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of other
postretirement plan assets measured and reported as of December 31, 2015 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Cash equivalents $—$9 $—$9
Mutual funds:
Fixed income securities 12,000 — —12,000
U.S. equity securities 13,224 — —13,224
International equity securities 5,635 ——5,635
Total $30,859 $9 $—$30,868
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of other
postretirement plan assets measured and reported as of December 31, 2014 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Cash equivalents $—$3 $—$3
Mutual funds:
Fixed income securities 11,968 — —11,968
U.S. equity securities 13,210 — —13,210
International equity securities 6,131 ——6,131
Total $31,309 $3 $—$31,312
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point
increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of
December 31, 2015 by $9.7 million and the service and interest cost by $0.5 million. A one-percentage-point decrease in the assumed
health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as of December 31, 2015 by
$7.5 million and the service and interest cost by $0.4 million.
401(k) Plans and Executive Deferral Plan
Avista Corp. has a salary deferral 401(k) plans that is a defined contribution plans and cover substantially all employees. Employees
can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The
Company matches a portion of the salary deferred by each participant according to the schedule in the respective plan.
Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):
2015 2014
Employer 401(k) matching contributions $ 7,875 $ 6,741
The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27

ICNU_DR_118 Attachment A

Page 62 of 235
until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of
their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust.
There were deferred compensation assets and corresponding deferred compensation liabilities on the Balance Sheets of the following
amounts as of December 31 (dollars in thousands):
2015 2014
Deferred compensation assets and liabilities $ 8,093 $ 8,677
NOTE 9. ACCOUNTING FOR INCOME TAXES
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards..The realization of deferred
income tax assets is dependent upon the ability to generate taxable income in future periods. The Company evaluated available
evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that deferred income tax
assets will be realized.
As of December 31, 2015, the Company had $15.3 million of state tax credit carryforwards of which it is expected $2.9 million will
expire unused; the Company has reflected the net amount of $12.4 million as an asset at December 31, 2015. State tax credits expire
from 2019 to 2028.
The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns
in certain jurisdictions, including Idaho, Oregon and Montana. Subsidiaries are charged or credited with the tax effects of their
operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2011 and
all issues were resolved related to these years. The IRS has not completed an examination of the Company’s 2012 and 2014 federal
income tax returns. The Company believes that any open tax years for federal or state income taxes will not result in adjustments that
would be significant to the financial statements.
The Company had net regulatory assets related to the probable recovery of certain deferred income tax liabilities from customers
through future rates as of December 31 (dollars in thousands):
2015 2014
Regulatory assets for deferred income taxes $ 101,240 $ 100,412
Regulatory liabilities for deferred income taxes 17,609 14,534
NOTE 10. ENERGY PURCHASE CONTRACTS
Avista Corp. has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the
purchase or exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year
2042. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility
resource costs in the Statements of Income, were as follows for the years ended December 31 (dollars in thousands):
2015 2014
Utility power resources $ 511,937 $ 556,915
The following table details Avista Corp.’s future contractual commitments for power resources (including transmission contracts) and
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28

ICNU_DR_118 Attachment A

Page 63 of 235
natural gas resources (including transportation contracts) (dollars in thousands):
2016 2017 2018 2019 2020 Thereafter Total
Power resources $ 261,560 $ 168,831 $ 149,375 $ 145,074 $ 104,688 $ 838,536 $ 1,668,064
Natural gas resources 79,335 64,400 65,144 57,105 45,446 427,435 738,865
Total $340,895 $233,231 $214,519 $202,179 $150,134 $1,265,971 $2,406,929
These energy purchase contracts were entered into as part of Avista Corp.’s obligation to serve its retail electric and natural gas
customers’ energy requirements, including contracts entered into for resource optimization. As a result, these costs are recovered either
through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery mechanisms.
The above future contractual commitments for power resources include fixed contractual amounts related to the Company's contracts
with certain PUDs to purchase portions of the output of certain generating facilities. Although Avista Corp. has no investment in the
PUD generating facilities, the fixed contracts obligate Avista Corp. to pay certain minimum amounts whether or not the facilities are
operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in
utility resource costs in the Statements of Income. The contractual amounts included above consist of Avista Corp.’s share of existing
debt service cost and its proportionate share of the variable operating expenses of these projects. The minimum amounts payable under
these contracts are based in part on the proportionate share of the debt service requirements of the PUD's revenue bonds for which the
Company is indirectly responsible. The Company's total future debt service obligation associated with the revenue bonds outstanding at
December 31, 2015 (principal and interest) was $72.0 million.
In addition, Avista Corp. has operating agreements, settlements and other contractual obligations related to its generating facilities and
transmission and distribution services. The following table details future contractual commitments under these agreements (dollars in
thousands):
2016 2017 2018 2019 2020 Thereafter Total
Contractual obligations $33,694 $31,134 $26,405 $31,117 $31,811 $192,295 $346,456
NOTE 11. NOTES PAYABLE
Avista Corp.
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in April
2019. The Company has the option to request an extension for an additional one or two years beyond April 2019, provided, 1) that no
event of default has occurred and is continuing prior to the requested extension and 2) the remaining term of agreement, including the
requested extension period, does not exceed five years. The committed line of credit is secured by non-transferable first mortgage
bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the extent, that
the Company defaults on its obligations under the committed line of credit.
The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant
which does not permit the ratio of “consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65
percent at any time. As of December 31, 2015, the Company was in compliance with this covenant.
Balances outstanding and interest rates of borrowings (excluding letters of credit) under the Company’s revolving committed lines of
credit were as follows as of December 31 (dollars in thousands):
2015 2014
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29

ICNU_DR_118 Attachment A

Page 64 of 235
Balance outstanding at end of period $105,000 $105,000
Letters of credit outstanding at end of period $ 44,595 $ 32,579
Average interest rate at end of period 1.18% 0.93%
As of December 31, 2015 and 2014, the borrowings outstanding under Avista Corp.’s committed line of credit were classified as
short-term borrowings on the Balance Sheet.
NOTE 12. BONDS
The following details long-term debt outstanding as of December 31 (dollars in thousands):
Maturity
Year Description
Interest
Rate 2015 2014
2016 First Mortgage Bonds 0.84% $ 90,000 $ 90,000
2018 First Mortgage Bonds 5.95% 250,000 250,000
2018 Secured Medium-Term Notes 7.39%-7.45% 22,500 22,500
2019 First Mortgage Bonds 5.45%90,000 90,000
2020 First Mortgage Bonds 3.89%52,000 52,000
2022 First Mortgage Bonds 5.13% 250,000 250,000
2023 Secured Medium-Term Notes 7.18%-7.54% 13,500 13,500
2028 Secured Medium-Term Notes 6.37%25,000 25,000
2032 Secured Pollution Control Bonds (1)(1)66,700 66,700
2034 Secured Pollution Control Bonds (1)(1)17,000 17,000
2035 First Mortgage Bonds 6.25% 150,000 150,000
2037 First Mortgage Bonds 5.70% 150,000 150,000
2040 First Mortgage Bonds 5.55%35,000 35,000
2041 First Mortgage Bonds 4.45%85,000 85,000
2044 First Mortgage Bonds 4.11%60,000 60,000
2045 First Mortgage Bonds (2)4.37% 100,000 —
2047 First Mortgage Bonds 4.23%80,000 80,000
Total secured bonds 1,536,700 1,436,700
Secured Pollution Control Bonds held by Avista
Corporation (1)(83,700) (83,700)
Total long-term debt $1,453,000 $1,353,000
(1) In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding
Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since
2008 and 2009, respectively, were refunded by new bond issues (Series 2010A and Series 2010B). The new bonds were not
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.30

ICNU_DR_118 Attachment A

Page 65 of 235
offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date,
subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of
these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.’s Balance Sheets.
(2) In December 2015, Avista Corp. issued $100.0 million of first mortgage bonds to five institutional investors in a private
placement transaction. The first mortgage bonds bear an interest rate of 4.37 percent and mature in 2045. The total net
proceeds from the sale of the new bonds were used to repay a portion of the borrowings outstanding under the Company’s
$400.0 million committed line of credit and for general corporate purposes.
The following table details future long-term debt maturities including advances from associated companies (see Note 13) (dollars in
thousands):
2016 2017 2018 2019 2020 Thereafter Total
Debt maturities $90,000 $—$272,500 $90,000 $52,000 $1,000,047 $1,504,547
Substantially all utility properties owned by Avista Corp. are subject to the lien of the Avista Corp.’s mortgage indenture. Under the
Mortgage and Deed of Trust securing the Company’s First Mortgage Bonds (including Secured Medium-Term Notes), the Company
may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of: 1) 66-2/3 percent of the cost or fair
value (whichever is lower) of property additions which have not previously been made the basis of any application under the
Mortgage, or 2) an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any
application under the Mortgage, or 3) deposit of cash. However, the Company may not issue any additional First Mortgage Bonds
(with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the Company’s “net earnings” (as defined in
the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual
interest requirements on all mortgage securities at the time outstanding, including the First Mortgage Bonds to be issued, and on all
indebtedness of prior rank. As of December 31, 2015, property additions and retired bonds would have allowed, and the net earnings
test would not have prohibited, the issuance of $1.1 billion in aggregate principal amount of additional first mortgage bonds at Avista
Corp.
See Note 11 for information regarding first mortgage bonds issued to secure the Company’s obligations under its committed line of
credit agreement.
NOTE 13. ADVANCES FROM ASSOCIATED COMPANIES
In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of
$51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of
Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly. The distribution
rates paid were as follows during the years ended December 31:
2015 2014
Low distribution rate 1.11% 1.10%
High distribution rate 1.29% 1.11%
Distribution rate at the end of the year 1.29% 1.11%
Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the
Company. These debt securities may be redeemed at the option of Avista Capital II at any time and mature on June 1, 2037. In
December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.31

ICNU_DR_118 Attachment A

Page 66 of 235
The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on,
and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available
for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust
Securities will be mandatorily redeemed.
NOTE 14. FAIR VALUE
The carrying values of cash and cash equivalents, special deposits, accounts and notes receivable, accounts payable and notes payable
are reasonable estimates of their fair values. Bonds and advances from associated companies are reported at carrying value on the
Balance Sheets.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted
prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3
measurement).
The three levels of the fair value hierarchy are defined as follows:
Level 1 – Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which
transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly
observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation
methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well
as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term
of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the
marketplace.
Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be
used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and
may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination
of the fair values incorporates various factors that not only include the credit standing of the counterparties involved and the impact of
credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s nonperformance risk on its
liabilities.
The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at
estimated fair value on the Balance Sheets as of December 31 (dollars in thousands):
2015 2014
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
Bonds (Level 2)$951,000 $1,055,797 $951,000 $1,118,972
Bonds (Level 3)502,000 505,768 402,000 432,728
Advances from associated companies (Level 3)51,547 36,083 51,547 38,582
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.32

ICNU_DR_118 Attachment A

Page 67 of 235
These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market
information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The
price ranges obtained from the third party brokers consisted of par values of 70.00 to 119.70, where a par value of 100.00 represents
the carrying value recorded on the Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices;
however, due to their limited trading activity, they are classified as level 2 because brokers must generate quotes and make estimates if
there is no trading activity near a period end. Level 3 long-term debt consists of private placement bonds and Advances from
associated companies, which typically have no secondary trading activity. Fair values in Level 3 are estimated based on market prices
from third party brokers using secondary market quotes for debt with similar risk and terms to generate quotes for Avista Corp. bonds.
The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on the
Balance Sheets as of December 31, 2015 and 2014 at fair value on a recurring basis (dollars in thousands):
Level 1 Level 2 Level 3
Counterparty
and Cash
Collateral
Netting (1) Total
December 31, 2015
Assets:
Energy commodity derivatives $ — $74,637 $ — $(73,954) $683
Level 3 energy commodity derivatives:
Natural gas exchange agreements — —678 (678) —
Foreign currency derivatives — 2 —(2) —
Interest rate swaps — 1,548 — —1,548
Deferred compensation assets:
Fixed income securities 1,727 — — —1,727
Equity securities 5,761 ———5,761
Total $7,488 $76,187 $678 $(74,634)$9,719
Liabilities:
Energy commodity derivatives $ — $97,193 $ — $(88,480) $8,713
Level 3 energy commodity derivatives:
Natural gas exchange agreement — —5,717 (678) 5,039
Power exchange agreement — —21,961 — 21,961
Power option agreement — —124 — 124
Interest rate swaps — 85,498 — —85,498
Foreign currency derivatives —19 —(2)17
Total $—$182,710 $27,802 $(89,160)$121,352
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.33

ICNU_DR_118 Attachment A

Page 68 of 235
Level 1 Level 2 Level 3
Counterparty
and Cash
Collateral
Netting (1)Total
December 31, 2014
Assets:
Energy commodity derivatives $ — $96,729 $ — $(95,204) $1,525
Level 3 energy commodity derivatives:
Natural gas exchange agreement — —1,349 (1,349) —
Foreign currency derivatives — 1 —(1) —
Interest rate swaps — 966 — (506) 460
Deferred compensation assets:
Fixed income securities 1,793 — — —1,793
Equity securities 6,074 ———6,074
Total $7,867 $97,696 $1,349 $(97,060)$9,852
Liabilities:
Energy commodity derivatives $ — $127,094 $ — $(110,714) $16,380
Level 3 energy commodity derivatives:
Natural gas exchange agreement — —1,384 (1,349)35
Power exchange agreement — —23,299 — 23,299
Power option agreement — —424 — 424
Foreign currency derivatives —21 —(1)20
Interest rate swaps —77,568 —(29,386)48,182
Total $—$204,683 $25,107 $(141,450)$88,340
(1) The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable
master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and
receivables for cash collateral held or placed with these same counterparties.
Avista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified
period, in the future. These contracts are entered into as part of Avista Corp.’s management of loads and resources and certain
contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in
respective levels and the amount of derivative assets and liabilities disclosed on the Balance Sheets is due to netting arrangements with
certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative
commodity instruments included in Level 2. In particular, electric derivative valuations are performed using market quotes, adjusted
for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange
(NYMEX) pricing for similar instruments, adjusted for basin differences, using market quotes. Where observable inputs are available
for substantially the full term of the contract, the derivative asset or liability is included in Level 2.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.34

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To establish fair values for interest rate swaps, the Company uses forward market curves for interest rates for the term of the swaps and
discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third party brokers
according to the terms of the swap agreements and evaluated by the Company for reasonableness, with consideration given to the
potential non-performance risk by the Company. Future cash flows of the interest rate swaps are equal to the fixed interest rate in the
swap compared to the floating market interest rate multiplied by the notional amount for each period.
To establish fair value for foreign currency derivatives, the Company uses forward market curves for Canadian dollars against the US
dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward
foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of
the foreign exchange contracts.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan.
These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table
above excludes cash and cash equivalents of $0.6 million as of December 31, 2015 and $0.8 million as of December 31, 2014.
Level 3 Fair Value
Under the power exchange agreement the Company purchases power at a price that is based on the on the average operating and
maintenance (O&M) charges from three surrogate nuclear power plants around the country. To estimate the fair value of this
agreement the Company estimates the difference between the purchase price based on the future O&M charges and forward prices for
energy.
The Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward
price which is based on the average O&M charges from the three surrogate nuclear power plants for the current year. Because the
nuclear power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. In
addition to the forward price being estimated using unobservable inputs, the Company also estimates the volumes of the transactions
that will take place in the future based on historical average transaction volumes per delivery year (November to April). Significant
increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement.
Generally, a change in the current year O&M charges for the surrogate plants is accompanied by a directionally similar change in
O&M charges in future years. There is generally not a correlation between external market prices and the O&M charges used to
develop the internal forward price.
For the power commodity option agreement, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value,
and this model includes significant inputs not observable or corroborated in the market. These inputs include: 1) the strike price (which
is an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and
other O&M charges), 2) estimated delivery volumes, and 3) volatility rates for periods beyond January 2018. Significant increases or
decreases in any of these inputs in isolation would result in a significantly higher or lower fair value measurement. Generally, changes
in overall commodity market prices and volatility rates are accompanied by directionally similar changes in the strike price and
volatility assumptions used in the calculation.
For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however,
the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions.
Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because
the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions
can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based
on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with
market prices and market volatility.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.35

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The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities
above as of December 31, 2015 (dollars in thousands):
Fair Value
(Net) at
December 31,
2015
Valuation
Technique Unobservable Input Range
Power exchange agreement $ (21,961) Surrogate facility
pricing
O&M charges $33.52-$43.65/MWh (1)
Escalation factor 3% - 2016 to 2019
Transaction volumes 233,054 - 397,030 MWhs
Power option agreement (124) Black-Scholes-
Merton
Strike price $35.43/MWh - 2016
$48.78/MWh - 2019
Delivery volumes 157,517 - 285,979 MWhs
Volatility rates 0.20 (2)
Natural gas exchange
agreement
(5,039) Internally derived
weighted average
cost of gas
Forward purchase
prices
$1.67 - $2.84/mmBTU
Forward sales prices $1.88 - $3.68/mmBTU
Purchase volumes 115,000 - 310,000 mmBTUs
Sales volumes 30,000 - 310,000 mmBTUs
(1) The average O&M charges for the delivery year beginning in November 2015 were $39.27 per MWh. For ratemaking purposes the
average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M
charges for the delivery year beginning in 2015 are $43.52 for Washington and $39.27 for Idaho.
(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.37 for 2016 to 0.24 in January 2018.
Avista Corp.’s risk management department and accounting department are responsible for developing the valuation methods
described above and both groups report to the Chief Financial Officer. The valuation methods, significant inputs and resulting fair
values described above are reviewed on at least a quarterly basis by the risk management department and the accounting department to
ensure they provide a reasonable estimate of fair value each reporting period.
The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant
unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands):
Natural Gas
Exchange
Agreement
Power
Exchange
Agreement
Power
Option
Agreement Total
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.36

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Year ended December 31, 2015:
Balance as of January 1, 2015 $ (35) $(23,299) $(424) $(23,758)
Total gains or losses (realized/unrealized):
Included in regulatory assets/liabilities (1)(6,008) (6,198) 300 (11,906)
Settlements 1,004 7,536 — 8,540
Ending balance as of December 31, 2015 (2)$(5,039)$(21,961)$(124)$(27,124)
Year ended December 31, 2014:
Balance as of January 1, 2014 $ (1,219) $(14,441) $(775) $(16,435)
Total gains or losses (realized/unrealized):
Included in regulatory assets/liabilities (1)3,873 (10,002) 351 (5,778)
Settlements (2,689) 1,144 — (1,545)
Ending balance as of December 31, 2014 (2)$(35)$(23,299)$(424)$(23,758)
(1) All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net
income or other comprehensive income during any of the periods presented in the table above.
(2) There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods presented
in the table above.
NOTE 15. COMMON STOCK
The Company had a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company’s shareholders could
automatically reinvest their dividends and make optional cash payments for the purchase of the Company’s common stock at current
market value. This plan was terminated by the Company in 2014.
The payment of dividends on common stock could be limited by:
certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of
Incorporation, as amended (currently there are no preferred shares outstanding),
certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements,
the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1), and.
certain requirements under the Public Utility Commission of Oregon (OPUC) approval of the AERC acquisition. As
of July 1, 2015 (one year following the acquisition date), the OPUC does not permit one-time or special dividends
from AERC to Avista Corp. and does not permit Avista Corp.’s total equity to total capitalization to be less than 40
percent, without approval from the OPUC. However, the OPUC approval does allow for regular distributions of
AERC earnings to Avista Corp. as long as AERC remains sufficiently capitalized and insured.
The Company declared the following dividends for the year ended December 31:
2015 2014
Dividends paid per common share $ 1.32 $1.27
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.37

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Under the covenant applicable to the Company's committed line of credit agreement, which does not permit the ratio of “consolidated
total debt” to “consolidated total capitalization” to be greater than 65 percent at any time, the amount of retained earnings available for
dividends at December 31, 2015 was limited to approximately $385.3 million.
Under the requirements of the OPUC approval of the AERC acquisition as outlined above, the amount available for dividends at
December 31, 2015 was limited to approximately $231.0 million.
The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of
December 31, 2015 and 2014.
Stock Repurchase Programs
During 2014, Avista Corp.’s Board of Directors approved a program to repurchase up to 4 million shares of the Company’s
outstanding common stock (2014 program). Repurchases of common stock under this program began on July 7, 2014 and the program
expired on December 31, 2014. Repurchases were made in the open market or in privately negotiated transactions. Under the 2014
program the Company repurchased 2,529,615 shares at a total cost of $79.9 million and an average cost of $31.57 per share. The
Company did not make any repurchases under this program subsequent to October 2014.
Avista Corp. initiated a second stock repurchase program on January 2, 2015 that expired on March 31, 2015 for the repurchase of up
to 800,000 shares of the Company's outstanding common stock (first quarter 2015 program). The number of shares repurchased
through the first quarter 2015 program was in addition to the number of shares repurchased under the 2014 program, which expired on
December 31, 2014. Under the first quarter 2015 program, the Company repurchased 89,400 shares at a total cost of $2.9 million and
an average cost of $32.66 per share. All repurchased shares under the 2014 program and the first quarter 2015 program reverted to the
status of authorized but unissued shares.
NOTE 16. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters,
including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve litigation
or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its
rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested
proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Corp.’s operations, the Company intends to
seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.
California Refund Proceeding
Recently, APX, a market maker in these proceedings in whose markets Avista Energy participated in the summer of 2000, has asserted
that Avista Energy and its other customer/participants may be responsible for a share of the disgorgement penalty APX may be found
to owe to the California parties. The penalty arises as a result of the FERC finding that APX committed violations in the California
market in the summer of 2000. APX is making these assertions despite Avista Energy having been dismissed in FERC Opinion No.
536 from the on-going administrative proceeding at the FERC regarding potential wrongdoing in the California markets in the summer
of 2000. APX has identified Avista Energy’s share of APX’s exposure to be as much as $16.0 million even though no wrongdoing
allegations are specifically attributable to Avista Energy. Avista Energy believes its settlement insulates it from any such liability and
that as a dismissed party it cannot be drawn back into the litigation. Avista Energy intends to vigorously dispute APX’s assertions of
indirect liability, but cannot at this time predict the eventual outcome.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.38

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Page 73 of 235
Pacific Northwest Refund Proceeding
In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market
sales of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June
2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of
refunds. In August 2007, the Ninth Circuit found that the FERC had failed to take into account new evidence of market manipulation
and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's findings
must be reevaluated in light of the new evidence. The Ninth Circuit expressly declined to direct the FERC to grant refunds. On October
3, 2011, the FERC issued an Order on Remand. On April 5, 2013, the FERC issued an Order on Rehearing expanding the temporal
scope of the proceeding to permit parties to submit evidence on transactions during the period from January 1, 2000 through and
including June 20, 2001. The Order on Remand established an evidentiary, trial-type hearing before an ALJ, and reopened the record
to permit parties to present evidence of unlawful market activity. The Order on Remand stated that parties seeking refunds must submit
evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected
negotiations with respect to the specific contract rate about which they complain. Simply alleging a general link between the
dysfunctional spot market in California and the Pacific Northwest spot market would not be sufficient to establish a causal connection
between a particular seller's alleged unlawful activities and the specific contract negotiations at issue. The hearing was conducted in
August through October 2013.
On July 11, 2012 and March 28, 2013, Avista Energy and Avista Corp. filed settlements of all issues in this docket with regard to the
claims made by the City of Tacoma and the California AG (on behalf of CERS). The FERC has approved the settlements and they are
final. The remaining direct claimant against Avista Corp. and Avista Energy in this proceeding is the City of Seattle, Washington
(Seattle).
With regard to the Seattle claims, on March 28, 2014, the Presiding ALJ issued her Initial Decision finding that: 1) Seattle failed to
demonstrate that either Avista Corp. or Avista Energy engaged in unlawful market activity and also failed to identify any specific
contracts at issue; 2) Seattle failed to demonstrate that contracts with either Avista Corp. or Avista Energy imposed an excessive
burden on consumers or seriously harmed the public interest; and that 3) Seattle failed to demonstrate that either Avista Corp. or Avista
Energy engaged in any specific violations of substantive provisions of the FPA or any filed tariffs or rate schedules. Accordingly, the
ALJ denied all of Seattle’s claims under both section 206 and section 309 of the FPA. On May 22, 2015, the FERC issued its Order on
Initial Decision in which it upheld the ALJ’s Initial Decision denying all of Seattle’s claims against Avista Corp. and Avista Energy.
Seattle filed a Request for Rehearing of the FERC’s Order on Initial Decision which was denied on December 31, 2015. Seattle
appealed the FERC’s decision to the Ninth Circuit. The Company does not expect that this matter will have a material adverse effect
on its financial condition, results of operations or cash flows.
Sierra Club and Montana Environmental Information Center Complaint Against the Owners of Colstrip
On March 6, 2013, the Sierra Club and Montana Environmental Information Center (MEIC) (collectively "Plaintiffs"), filed a
Complaint in the United States District Court for the District of Montana, Billings Division, against the Owners of the Colstrip
Generating Project ("Colstrip"). Avista Corp. owns a 15 percent interest in Units 3 & 4 of Colstrip. The other Colstrip co-Owners are
Talen (formerly PPL Montana), Puget Sound Energy, Portland General Electric Company, NorthWestern Energy and PacifiCorp. The
Complaint alleges certain violations of the Clean Air Act, including the New Source Review, Title V and opacity requirements.
On September 27, 2013, the Plaintiffs filed an Amended Complaint. The Amended Complaint withdrew from the original Complaint
fifteen claims related to seven pre-January 1, 2001 Colstrip maintenance projects, upgrade projects and work projects and claims
alleging violations of Title V and opacity requirements. The Amended Complaint alleges certain violations of the Clean Air Act and
the New Source Review and adds claims with respect to post-January 1, 2001 Colstrip projects.
On August 27, 2014, the Plaintiffs filed a Second Amended Complaint. The Second Amended Complaint withdraws from the
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.39

ICNU_DR_118 Attachment A

Page 74 of 235
Amended Complaint five claims and adds one new claim. The Second Amended Complaint alleges certain violations of the Clean Air
Act and the New Source Review. The Plaintiffs request that the Court grant injunctive and declaratory relief, order remediation of
alleged environmental damages, impose civil penalties, require a beneficial environmental project in the areas affected by the alleged
air pollution and require payment of Plaintiffs’ costs of litigation and attorney fees. The Plaintiffs have since indicated that they do not
intend to pursue two of the seven projects, leaving a total of five projects remaining. A number of motions for summary judgment were
filed by both the Plaintiffs and the defendants. The Court issued its rulings on these motions and, as a result, only two projects remain
for trial. The Plaintiffs have filed objections to the order.
The case has been bifurcated into separate liability and remedy trials. The Court has set the liability trial date for May 31, 2016. No
date has been set for the remedy trial.
Management believes that it is reasonably possible that this matter could result in a loss to the Company. However, due to uncertainties
concerning this matter, Avista Corp. cannot predict the outcome or determine whether it would have a material impact on the
Company.
Cabinet Gorge Total Dissolved Gas Abatement Plan
Dissolved atmospheric gas levels (referred to as "TDG") in the Clark Fork River exceed state of Idaho and federal water quality
numeric standards downstream of Cabinet Gorge during periods when excess river flows must be diverted over the spillway. Under the
terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.’s FERC license for the Clark Fork Project, Avista Corp.
has worked in consultation with agencies, tribes and other stakeholders to address this issue. Under the terms of a gas supersaturation
mitigation plan, Avista is reducing TDG by constructing spill crest modifications on spill gates at the dam, and the Company expects to
continue spill crest modifications over the next several years, in ongoing consultation with key stakeholders. Avista Corp. cannot at
this time predict the outcome or estimate a range of costs associated with this contingency; however, the Company will continue to
seek recovery, through the ratemaking process, of all operating and capitalized costs related to this issue.
Fish Passage at Cabinet Gorge and Noxon Rapids
In 1999, the United States Fish and Wildlife Service (USFWS) listed bull trout as threatened under the Endangered Species Act. In
2010, the USFWS issued a revised designation of critical habitat for bull trout, which includes the lower Clark Fork River. The
USFWS issued a final recovery plan in October 2015.
The Clark Fork Settlement Agreement describes programs intended to help restore bull trout populations in the project area. Using the
concept of adaptive management and working closely with the USFWS, the Company evaluated the feasibility of fish passage at
Cabinet Gorge and Noxon Rapids. The results of these studies led, in part, to the decision to move forward with development of
permanent facilities, among other bull trout enhancement efforts. Fishway designs for Cabinet Gorge have been completed, and the
Company is developing construction cost estimates currently. The Company believes its ongoing efforts through the Clark Fork
Settlement Agreement continue to effectively address issues related to bull trout. Avista Corp. cannot at this time predict the outcome
or estimate a range of costs associated with this contingency; however, the Company will continue to seek recovery, through the
ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids.
Collective Bargaining Agreements
The Company’s collective bargaining agreements with the IBEW represents approximately 45 percent of all of Avista Corp.’s
employees. The agreement with the local union in Washington and Idaho representing the majority (approximately 90 percent) of the
Avista Corp.’s bargaining unit employees expires in March 2016. In October 2015, a new collective bargaining agreement concerning
wages over the three-year period 2016 through 2018 was approved by the local IBEW in Washington and Idaho. The new collective
bargaining agreement will be effective in March 2016.
A three-year agreement in Oregon, which covers approximately 50 employees, expires in March 2017.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.40

ICNU_DR_118 Attachment A

Page 75 of 235
There is a risk that if collective bargaining agreements expire and new agreements are not reached in each of our jurisdictions,
employees could strike. Given the magnitude of employees that are covered by collective bargaining agreements, this could result in
disruptions of our operations. However, the Company believes that the possibility of this occurring is remote.
Customer Information and Work Management Systems Project Cost Recovery
Over the past four years, Avista Corp. has invested significant capital into Project Compass. Project Compass was completed and went
into service during the first quarter of 2015. As part of the Washington electric and natural gas general rate cases filed in February
2015 and the Oregon natural gas general rate case filed in May 2015, Avista Corp. requested the full recovery of the Washington and
Oregon share of the costs associated with this project.
On July 27, 2015, the UTC Staff in the Company's electric and natural gas general rate cases filed responsive testimony. Included in
their testimony was a recommendation to disallow $12.7 million (Washington's share) of Project Compass costs primarily related to the
delay in the completion of the project. In a UTC order received in January 2016, the UTC approved the full recovery of Washington's
share of Project Compass costs with no disallowances.
In October 2015, the OPUC staff filed testimony in the Company's natural gas general rate case which included a recommendation to
disallow $1.2 million (Oregon's share) of Project Compass costs, similar to the initial recommendation in Washington. In an OPUC
order received in February 2016, the OPUC approved the full recovery of Oregon’s portion of Project Compass costs, with no
disallowances.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company
believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of
operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability
being incurred. Such a change, should it occur, could be significant.
The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitments
for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties
who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company’s policy is to accrue
and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation,
cleanup and monitoring costs to be incurred. For matters that affect Avista Corp.’s or AEL&P's operations, the Company seeks, to the
extent appropriate, recovery of incurred costs through the ratemaking process.
The Company has potential liabilities under the Endangered Species Act for species of fish, plants and wildlife that have either already
been added to the endangered species list, listed as “threatened” or petitioned for listing. Thus far, measures adopted and implemented
have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of
all operating and capitalized costs related to these issues.
Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights.
In addition, the company holds additional non-hydro water rights. The state of Montana is examining the status of all water right claims
within state boundaries through a general adjudication. Claims within the Clark Fork River basin could adversely affect the energy
production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated adjudication in
northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d’Alene basin. The
Company is and will continue to be a participant in these and any other relevant adjudication processes. The complexity of such
adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the
impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all operating and
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.41

ICNU_DR_118 Attachment A

Page 76 of 235
capitalized costs related to this issue.
NOTE 17. REGULATORY MATTERS
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge on the Balance Sheets for future prudence review and recovery through
retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista
Corp. and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:
short-term wholesale market prices and sales and purchase volumes,
the level and availability of hydroelectric generation,
the level and availability of thermal generation (including changes in fuel prices), and
retail loads.
In Washington, the ERM allows Avista Corp. to periodically increase or decrease electric rates with UTC approval to reflect changes
in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of
wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. Total net deferred power
costs under the ERM were a liability of $18.0 million as of December 31, 2015 compared to a liability of $14.2 million as of
December 31, 2014, and these deferred power cost balances represent amounts due to customers.
Avista Corp. has a PCA mechanism in Idaho that allows it to modify electric rates on October 1 of each year with IPUC approval.
Under the PCA mechanism, Avista Corp. defers 90 percent of the difference between certain actual net power supply expenses and the
amount included in base retail rates for its Idaho customers. These annual October 1 rate adjustments recover or rebate power costs
deferred during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were a
regulatory asset of $0.2 million as of December 31, 2015 compared to a regulatory asset of $8.3 million as of December 31, 2014.
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Corp. files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation
costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and
transportation costs for the prior year. Total net deferred natural gas costs to be refunded to customers were a liability of $17.9 million
as of December 31, 2015 compared to a liability of $3.9 million as of December 31, 2014.
Decoupling and Earnings Sharing Mechanisms
Decoupling is a mechanism designed to sever the link between a utility's revenues and consumers' energy usage. The Company's actual
revenue, based on kilowatt hour and therm sales will vary, up or down, from the level included in a general rate case, which could be
caused by changes in weather, energy conservation or the economy. Generally, the Company's electric and natural gas revenues will be
adjusted each month to be based on the number of customers, rather than kilowatt hour and therm sales. The difference between
revenues based on sales and revenues based on the number of customers will be deferred and either surcharged or rebated to customers
beginning in the following year.
Washington Decoupling and Earnings Sharing
In Washington, the UTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period that
commenced January 1, 2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to 3 percent on
an annual basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of
rebate rate adjustments.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.42

ICNU_DR_118 Attachment A

Page 77 of 235
The decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural
gas earnings calculations will be made for the prior calendar year. These earnings tests will reflect actual decoupled revenues,
normalized power supply costs and other normalizing adjustments.
As of December 31, 2015, the Company had a total net decoupling surcharge (asset) of $10.9 million for Washington electric and
natural gas customers and a liability (rebate to customers) for earnings sharing of $3.4 million for Washington electric customers.
Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms
In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the
Washington decoupling mechanisms) for an initial term of three years, commencing on January 1, 2016.
For the period 2013 through 2015, the Company had an after-the-fact earnings test, such that if Avista Corp., on a consolidated basis
for electric and natural gas operations in Idaho, earned more than a 9.8 percent ROE, the Company was required to share with
customers 50 percent of any earnings above the 9.8 percent. There was no provision for a surcharge to customers if the Company's
ROE was less than 9.8 percent. This after-the-fact earnings test was discontinued as part of the settlement of the Company's 2015 Idaho
electric and natural gas general rates cases. As of December 31, 2015 and December 31, 2014, the Company had total cumulative
earnings sharing liabilities (rebates to customers) of $8.8 million and $10.1 million, respectively for electric and natural gas customers.
NOTE 18. SUPPLEMENTAL CASH FLOW INFORMATION
2015 2014
Cash paid for interest $72,405 $69,693
Cash paid (received) for income taxes $(10,506) $41,154
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.43

ICNU_DR_118 Attachment A

Page 78 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Other
Adjustments
(e)
Foreign Currency
Hedges
(d)
Minimum Pension
Liability adjustment
(net amount)
(c)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Item
(a)
( 1,585,855) ( 4,234,075)
Balance of Account 219 at Beginning of
Preceding Year
1
460,497
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
1,125,358 ( 3,653,806)
Preceding Quarter/Year to Date Changes in
Fair Value
3
1,585,855 ( 3,653,806)Total (lines 2 and 3) 4
( 7,887,881)
Balance of Account 219 at End of
Preceding Quarter/Year
5
( 7,887,881)
Balance of Account 219 at Beginning of
Current Year
6
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
1,238,110
Current Quarter/Year to Date Changes in
Fair Value
8
1,238,110Total (lines 7 and 8) 9
( 6,649,771)
Balance of Account 219 at End of Current
Quarter/Year
10
FERC FORM NO. 1 (NEW 06-02)Page 122a

ICNU_DR_118 Attachment A

Page 79 of 235
Other Cash Flow
Hedges
[Specify]
(g)
Other Cash Flow
Hedges
Interest Rate Swaps
(f)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Total
Comprehensive
Income
(j)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Totals for each
category of items
recorded in
Account 219
(h)
( 5,819,930) 1
460,497 2
( 2,528,448) 3
192,040,688 189,972,737( 2,067,951) 4
( 7,887,881) 5
( 7,887,881) 6
7
1,238,110 8
123,227,041 124,465,151 1,238,110 9
( 6,649,771) 10
FERC FORM NO. 1 (NEW 06-02)Page 122b

ICNU_DR_118 Attachment A

Page 80 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Avista Corporation X
04/15/2016 2015/Q4
Line
No.(b)(a)
Classification Electric
(c)
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Total Company for the
Current Year/Quarter Ended
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
Utility Plant 1
In Service 2
3,525,164,548 4,912,498,999Plant in Service (Classified) 3
286,715 6,729,064Property Under Capital Leases 4
Plant Purchased or Sold 5
Completed Construction not Classified 6
Experimental Plant Unclassified 7
3,525,451,263 4,919,228,063Total (3 thru 7) 8
Leased to Others 9
3,776,330 3,966,915Held for Future Use 10
152,073,992 190,108,665Construction Work in Progress 11
Acquisition Adjustments 12
3,681,301,585 5,113,303,643Total Utility Plant (8 thru 12) 13
1,264,628,194 1,680,907,938Accum Prov for Depr, Amort, & Depl 14
2,416,673,391 3,432,395,705Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
1,247,691,281 1,626,086,020Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
16,936,912 54,821,918Amort of Other Utility Plant 21
1,264,628,193 1,680,907,938Total In Service (18 thru 21) 22
Leased to Others 23
Depreciation 24
Amortization and Depletion 25
Total Leased to Others (24 & 25) 26
Held for Future Use 27
Depreciation 28
Amortization 29
Total Held for Future Use (28 & 29) 30
Abandonment of Leases (Natural Gas) 31
Amort of Plant Acquisition Adj 32
1,264,628,193 1,680,907,938Total Accum Prov (equals 14) (22,26,30,31,32) 33
FERC FORM NO. 1 (ED. 12-89)Page 200

ICNU_DR_118 Attachment A

Page 81 of 235
(g)
Common
(h)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas Other (Specify)
(d)(e)(f)
Other (Specify)Other (Specify)
1
2
962,527,500 424,806,951 3
858,864 5,583,485 4
5
6
7
963,386,364 430,390,436 8
9
190,585 10
13,516,796 24,517,877 11
12
977,093,745 454,908,313 13
317,998,694 98,281,050 14
659,095,051 356,627,263 15
16
17
316,058,415 62,336,324 18
19
20
1,940,280 35,944,726 21
317,998,695 98,281,050 22
23
24
25
26
27
28
29
30
31
32
317,998,695 98,281,050 33
FERC FORM NO. 1 (ED. 12-89)Page 201

ICNU_DR_118 Attachment A

Page 82 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
1. INTANGIBLE PLANT 1
(301) Organization 2
(302) Franchises and Consents 44,651,922 3
(303) Miscellaneous Intangible Plant 17,361,736 1,259,763 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 62,013,658 1,259,763 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 3,578,172 3,542,814 8
(311) Structures and Improvements 128,235,342 3,183,583 9
(312) Boiler Plant Equipment 167,815,955 2,069,215 10
(313) Engines and Engine-Driven Generators 6,770 11
(314) Turbogenerator Units 53,523,689 1,415,444 12
(315) Accessory Electric Equipment 27,144,546 19,158 13
(316) Misc. Power Plant Equipment 16,989,613 129,722 14
(317) Asset Retirement Costs for Steam Production 585,275 12,539,179 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 397,879,362 22,899,115 16
B. Nuclear Production Plant 17
(320) Land and Land Rights 18
(321) Structures and Improvements 19
(322) Reactor Plant Equipment 20
(323) Turbogenerator Units 21
(324) Accessory Electric Equipment 22
(325) Misc. Power Plant Equipment 23
(326) Asset Retirement Costs for Nuclear Production 24
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 25
C. Hydraulic Production Plant 26
(330) Land and Land Rights 59,736,099 200,554 27
(331) Structures and Improvements 56,709,957 5,065,110 28
(332) Reservoirs, Dams, and Waterways 137,857,126 15,997,037 29
(333) Water Wheels, Turbines, and Generators 167,781,138 65,554 30
(334) Accessory Electric Equipment 38,081,043 4,676,977 31
(335) Misc. Power PLant Equipment 9,307,717 281,710 32
(336) Roads, Railroads, and Bridges 2,673,818 7,534 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 472,146,898 26,294,476 35
D. Other Production Plant 36
(340) Land and Land Rights 905,167 37
(341) Structures and Improvements 16,768,906 24,454 38
(342) Fuel Holders, Products, and Accessories 21,300,798 346,336 39
(343) Prime Movers 23,909,470 40
(344) Generators 205,549,077 1,030,968 41
(345) Accessory Electric Equipment 20,713,551 159,858 42
(346) Misc. Power Plant Equipment 1,524,454 284,567 43
(347) Asset Retirement Costs for Other Production 351,683 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 291,023,106 1,846,183 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 1,161,049,366 51,039,774 46
Page 204FERC FORM NO. 1 (REV. 12-05)

ICNU_DR_118 Attachment A

Page 83 of 235
(f)
Transfers Balance at
End of Year
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent’s plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
1
2
44,651,922 3
18,474,037 40,337 187,799 4
63,125,959 40,337 187,799 5
6
7
7,120,986 8
131,305,776 113,149 9
166,507,956 3,377,214 10
6,770 11
54,444,179 494,954 12
27,022,693 141,011 13
17,116,678 2,657 14
13,124,454 15
416,649,492 4,128,985 16
17
18
19
20
21
22
23
24
25
26
59,936,653 27
61,708,187 66,880 28
153,839,363 14,800 29
167,828,800 17,892 30
42,584,172 -135,752 38,096 31
9,526,404 63,023 32
2,681,352 33
34
498,104,931 -135,752 200,691 35
36
905,167 37
16,793,360 38
21,377,912 269,222 39
23,909,470 40
206,578,655 1,390 41
20,780,726 92,683 42
1,775,348 33,673 43
351,683 44
292,472,321 396,968 45
1,207,226,744 -135,752 4,726,644 46
Page 205FERC FORM NO. 1 (REV. 12-05)

ICNU_DR_118 Attachment A

Page 84 of 235
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 19,563,343 1,601,222 48
(352) Structures and Improvements 20,483,393 83,125 49
(353) Station Equipment 232,781,971 11,100,637 50
(354) Towers and Fixtures 17,125,525 47,030 51
(355) Poles and Fixtures 179,710,422 19,135,353 52
(356) Overhead Conductors and Devices 125,521,124 6,378,487 53
(357) Underground Conduit 2,973,023 14,067 54
(358) Underground Conductors and Devices 2,330,072 12,198 55
(359) Roads and Trails 1,951,875 14,919 56
(359.1) Asset Retirement Costs for Transmission Plant 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 602,440,748 38,387,038 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 7,355,274 -60,015 60
(361) Structures and Improvements 18,850,829 1,593,407 61
(362) Station Equipment 122,584,789 2,550,139 62
(363) Storage Battery Equipment 2,354,235 63
(364) Poles, Towers, and Fixtures 307,104,120 32,093,661 64
(365) Overhead Conductors and Devices 197,953,993 15,666,302 65
(366) Underground Conduit 91,963,445 6,630,736 66
(367) Underground Conductors and Devices 160,182,714 13,858,581 67
(368) Line Transformers 219,388,811 14,856,072 68
(369) Services 142,839,610 8,672,644 69
(370) Meters 48,222,967 1,323,073 70
(371) Installations on Customer Premises 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 40,344,482 9,475,206 73
(374) Asset Retirement Costs for Distribution Plant 129,707 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 1,356,920,741 109,014,041 75
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76
(380) Land and Land Rights 77
(381) Structures and Improvements 78
(382) Computer Hardware 79
(383) Computer Software 80
(384) Communication Equipment 81
(385) Miscellaneous Regional Transmission and Market Operation Plant 82
(386) Asset Retirement Costs for Regional Transmission and Market Oper 83
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 84
6. GENERAL PLANT 85
(389) Land and Land Rights 398,664 86
(390) Structures and Improvements 7,445,146 -26,019 87
(391) Office Furniture and Equipment 8,929,247 1,152,794 88
(392) Transportation Equipment 30,075,182 4,843,605 89
(393) Stores Equipment 395,329 5,177 90
(394) Tools, Shop and Garage Equipment 3,007,814 926,737 91
(395) Laboratory Equipment 677,662 -44 92
(396) Power Operated Equipment 34,564,325 90,558 93
(397) Communication Equipment 57,689,690 3,444,427 94
(398) Miscellaneous Equipment 80,897 95
SUBTOTAL (Enter Total of lines 86 thru 95) 143,263,956 10,437,235 96
(399) Other Tangible Property 97
(399.1) Asset Retirement Costs for General Plant 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 143,263,956 10,437,235 99
TOTAL (Accounts 101 and 106) 3,325,688,469 210,137,851 100
(102) Electric Plant Purchased (See Instr. 8) 101
(Less) (102) Electric Plant Sold (See Instr. 8) 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 3,325,688,469 210,137,851 104
Page 206FERC FORM NO. 1 (REV. 12-05)

ICNU_DR_118 Attachment A

Page 85 of 235
(f)
Transfers Balance at
End of Year
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
21,941,751 777,200 14 48
20,538,173 28,345 49
243,039,879 142,094 984,823 50
17,172,555 51
198,418,239 427,536 52
131,684,983 214,628 53
2,987,090 54
2,342,270 55
1,966,794 56
57
640,091,734 919,294 1,655,346 58
59
7,847,465 611,505 59,299 60
20,387,882 -4,535 51,819 61
124,856,555 285,139 563,512 62
2,354,235 63
338,516,198 29,072 710,655 64
213,576,868 29,072 72,499 65
98,828,188 259,223 25,216 66
173,962,389 98,655 177,561 67
234,112,620 132,263 68
151,461,634 50,620 69
49,503,959 42,081 70
71
72
49,377,953 441,735 73
129,707 74
1,464,915,653 1,308,131 2,327,260 75
76
77
78
79
80
81
82
83
84
85
398,664 86
7,028,571 -340,997 49,559 87
9,190,855 -40,337 850,849 88
34,138,376 108,127 888,538 89
400,506 90
3,725,151 209,400 91
582,187 95,431 92
33,435,575 -62,627 1,156,681 93
61,110,391 49,304 73,030 94
80,897 95
150,091,173 -286,530 3,323,488 96
97
98
150,091,173 -286,530 3,323,488 99
3,525,451,263 1,845,480 12,220,537 100
101
102
103
3,525,451,263 1,845,480 12,220,537 104
Page 207FERC FORM NO. 1 (REV. 12-05)

ICNU_DR_118 Attachment A

Page 86 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Avista Corporation X
04/15/2016 2015/Q4
Line Description and Location Date Originally Included Balance at
End of Year(c)(b)(a)Of Property in This Account
Date Expected to be used
in Utility Service (d)No.
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Land and Rights: 1
2
3
May 2006Distribution Plant Land, Spokane, Washington 559,935Unknown 4
Aug 2008Distribution Plant Land, Spokane, Washington 301,889Unknown 5
Oct 2008Distribution Plant Land, Spokane, Washington 1,457,302Unknown 6
Dec 2010Distribution Plant Land, Carlin Bay, Idaho 162,352Unknown 7
Dec 2010Distribution UG Plant Conduit, Spokane, Washington 22,437Unknown 8
Dec 2010Distribution UG Plant Conductors, Spokane, Washingto 197,444Unknown 9
Mar 2011Distribution Plant Land, Spokane, Washington 540,307Unknown 10
Dec 2011Transmission Plant Land, Spokane, Washington 431,600Unknown 11
Dec 2011Other Production Plant Land, Spokane, Washington 40,896Unknown 12
July 2014Transmission Plant Land, Spokane, Washington 62,168Unknown 13
14
15
16
17
18
19
20
Other Property: 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-96)Page 214
47 Total 3,776,330
ICNU_DR_118 Attachment A

Page 87 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Description of Project Construction work in progress -
(b)(a)
Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
52,871,978Nine Mile Redevelopment 1
17,562,255Little Falls Powerhouse Redevelopment 2
14,553,487CG HED U#1 Refurbishment 3
13,986,517Noxon 230 kV Substation - Rebuild 4
13,949,614PF S Channel Gate Replacement 5
8,954,226Clark Fork Implement PME Agreement 6
2,635,233Spokane River Implementation (PM&E) 7
2,460,761Benton-Othello 115 Recond 8
2,370,029Mobile Substation - Purchase New Mobile Subs 9
2,230,445Regulating Hydro 10
2,034,757Greenacres 115-13kV Sub - New Construct 11
1,840,416Transportation Equip 12
1,129,563WSDOT Highway Franchise Consolidation 13
15,494,300Minor Projects <$1M 14
15
Research, Development, and Demonstrating: 16
411 SGDP-Pullman Smart Grid Demonstration Project 17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-87)Page 216
43 TOTAL 152,073,992
ICNU_DR_118 Attachment A

Page 88 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Item Total
(c)(b)(a)(d)
Section A. Balances and Changes During Year
(c+d+e)Electric Plant inService Electric Plant Held for Future Use Electric PlantLeased to Others
(e)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Balance Beginning of Year 1 1,181,974,217 1,181,974,217
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 81,873,851 81,873,851
(403.1) Depreciation Expense for Asset
Retirement Costs
4
(413) Exp. of Elec. Plt. Leas. to Others 5
Transportation Expenses-Clearing 6 4,587,922 4,587,922
Other Clearing Accounts 7
Other Accounts (Specify, details in footnote): 8 247,123 247,123
9
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 86,708,896 86,708,896
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 11,827,944 11,827,944
Cost of Removal 13 4,650,743 4,650,743
Salvage (Credit) 14 411,182 411,182
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 16,067,505 16,067,505
Other Debit or Cr. Items (Describe, details in
footnote):
16 -4,924,327 -4,924,327
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 1,247,691,281 1,247,691,281
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
283,063,100 283,063,100
Nuclear Production 21
Hydraulic Production-Conventional 22 133,008,042 133,008,042
Hydraulic Production-Pumped Storage 23
Other Production 24 101,483,944 101,483,944
Transmission 25 201,510,322 201,510,322
Distribution 26 461,172,457 461,172,457
Regional Transmission and Market Operation 27
General 28 67,453,416 67,453,416
TOTAL (Enter Total of lines 20 thru 28) 29 1,247,691,281 1,247,691,281
Page 219FERC FORM NO. 1 (REV. 12-05)

ICNU_DR_118 Attachment A

Page 89 of 235
Schedule Page: 219 Line No.: 7 Column: c
Change in Removal Work in Progress $-4,924,328
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 90 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Description of Investment Date Acquired
(c)(b)(a)
Amount of Investment atBeginning of YearDate Of
Maturity (d)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
1
206,138,9711997Investment in Avista Capital 2
-148,878,702Avista Capital - Equity in Earnings 3
89,816,3802014Investment in AERC 4
1,179,202AERC - Equity in Earnings 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89)Page 224
42 Total Cost of Account 123.1 $TOTAL 148,255,851 0
ICNU_DR_118 Attachment A

Page 91 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Equity in Subsidiary
Earnings of Year
Revenues for Year Amount of Investment at
End of Year
Gain or Loss from Investment
Disposed of(e)(f)(g)(h)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
1
206,138,971 2
-144,021,712 4,856,990 3
89,816,380 4
5,581,641 -1,905,356 6,307,795 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89)Page 225
42 11,164,785 -1,905,356 157,515,280
ICNU_DR_118 Attachment A

Page 92 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
MATERIALS AND SUPPLIES
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Account Balance Balance
(c)(b)(a)
Department or
Departments which
(d)
Beginning of Year End of Year
Use Material
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
4,116,727 (1) 3,293,585 1 Fuel Stock (Account 151)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
17,901,172 (1) 23,000,160 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
2,752,174 (1) 3,061,532 7 Production Plant (Estimated)
122,300 (1) 91,062 8 Transmission Plant (Estimated)
359,649 (1) 299,907 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
8,284,177 (1),(2) 7,479,110 11 Assigned to - Other (provide details in footnote)
29,419,472 33,931,771 12 TOTAL Account 154 (Enter Total of lines 5 thru 11)
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)
17
18
19
33,536,199 37,225,356 20 TOTAL Materials and Supplies (Per Balance Sheet)
Page 227FERC FORM NO. 1 (REV. 12-05)

ICNU_DR_118 Attachment A

Page 93 of 235
Schedule Page: 227 Line No.: 1 Column: d
(1) Electric
(2) Natural Gas
Schedule Page: 227 Line No.: 5 Column: d
(1) Electric
(2) Natural Gas
Schedule Page: 227 Line No.: 7 Column: d
(1) Electric
(2) Natural Gas
Schedule Page: 227 Line No.: 8 Column: d
(1) Electric
(2) Natural Gas
Schedule Page: 227 Line No.: 9 Column: d
(1) Electric
(2) Natural Gas
Schedule Page: 227 Line No.: 11 Column: d
(1) Electric
(2) Natural Gas
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 94 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Description
Costs Incurred During
(b)(a)
Period Account Charged
(c)
Reimbursements
Received During
(d)
Account Credited
With Reimbursement
(e)
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement received for performing the study.
the Period
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
6,710Avista Nine Mile Upgrade 186200 22
973Gordon Butte Energy Storage 186200 23
28,791Rattlesnake Flat Intr 186200 24
179Stump Farmers 186200 25
5,930Saddle Mountain East 186200 26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07)Page 231

ICNU_DR_118 Attachment A

Page 95 of 235
Schedule Page: 231 Line No.: 22 Column: b
Total life to date costs.
Schedule Page: 231 Line No.: 23 Column: b
Total life to date costs.
Schedule Page: 231 Line No.: 24 Column: b
Total life to date costs.
Schedule Page: 231 Line No.: 25 Column: b
Total life to date costs.
Schedule Page: 231 Line No.: 26 Column: b
Total life to date costs.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 96 of 235

This Page Intentionally Left Blank

ICNU_DR_118 Attachment A

Page 97 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
OTHER REGULATORY ASSETS (Account 182.3)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Description and Purpose of Debits CREDITS
Written off During
the Quarter/Year
Account Charged
(d)(c)(a)
Balance at end of
Current Quarter/Year
(e)
Other Regulatory Assets Written off During
the Period
Amount
(f)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be
grouped by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Balance at
Beginning of
Current
Quarter/Year
(b)
235,758,103 235,008,848 749,255283Reg Asset Post Ret Liab 1
44,773,122 42,104,242 2,668,880283Regulatory Asset FAS109 Utility Plant 2
1,246,667 1,246,667407Regulatory Asset Lancaster Generation 3
48,022,781 51,827,593 3,804,812Regulatory Asset FAS109 DSIT Non Plant 4
4,238,612 4,652,121 413,509Regulatory Asset FAS109 DFIT State Tax Cr 5
3,441,373 2,703,891 737,482283Regulatory Asset FAS109 WNP3 6
464,890 386,154 78,736407Regulatory Asset- Spokane River Relicense 7
429,262 355,950 73,312557Regulatory Asset- Spokane River PM&E 8
9,015,469 8,804,404 211,065407Regulatory Asset- Lake CDA Fund 9
2,000,000 2,000,000Regulatory Asset- Lake CDA IPA Fund 10
468,893 468,893Regulatory Asset- Spokane River TDG Idaho 11
5,460 5,640 180Reg Assets- Decouplings Surcharge 12
1,277,422 1,244,703 32,719407Regulatory Asset- Lake CDA DEF Costs 13
5,804,313 4,823,298 981,015407DEF CS2 & COLSTRIP 14
170,529 170,529407Reardan Wind Generation 15
46,171 46,171407ID Wind Gen AFUDC 16
153,156 153,156407Regulatory Asset Wartsila Units 17
29,640,374 17,260,177 12,380,197244MTM St Regulatory Asset 18
24,483,175 32,419,723 7,936,548MTM Lt Regulatory Asset 19
2,301,253 2,875,898 574,645Regulatory Asset FAS143 Asset Retirement Obligation 20
34,516,176 33,632,090 884,086407Reg Asset AN- CDA Lake Settlement 21
900,034 747,916 152,118407Reg Asset WA-CDA Lake Settlement 22
2,194,343 2,047,832 146,511407Regulatory Asset Workers Comp 23
932,887 932,887Regulatory Asset ID PCA Deferral 1 24
6,211,802 6,211,802557Regulatory Asset ID PCA Deferral 2 25
2,078,991 2,078,991557Regulatory Asset ID PCA Deferral 3 26
871,184 580,789 290,395407Spokane RIver TDG 27
33,964,535 40,786,512 6,821,977Settled Interest Rate Swap Asset 28
4,603,415 3,167,519 4,603,415407 3,167,519DSM Asset 29
77,062,517 83,972,777 6,910,260Unsettled Interest Rate Swaps Asset 30
103,536 221,213 117,677Other Reg Assets 31
32
33
34
35
36
37
38
39
40
41
42
43
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
44 TOTAL 576,247,558 33,896,502 573,031,070 30,680,014
ICNU_DR_118 Attachment A

Page 98 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
MISCELLANEOUS DEFFERED DEBITS (Account 186)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Description of Miscellaneous Debits CREDITS
Account
(c)(b)(a)
Balance at
End of Year
(d)
Deferred Debits Amount
(e)
Balance at
Beginning of Year
(f)
Charged
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
1
1,110,999 1,110,999406Colstrip Common Fac. 2
631,197 270,513 360,684540Regulatory Asset-Mt Lease Pymt 3
1,353,216 676,584 676,632540Regulatory Asset-Mt Lease Pymt 4
2,355,642 2,355,642Colstrip Common Fac. 5
24,528 441,966 417,438 931Prepaid Airplane Lease LT 6
21,692 515,400 493,708Misc DD- Airplane Lease 7
3,530,342 1,888,049 1,642,293Plant Alloc of Clearing Jrl 8
43,137 115,295 72,158 VARMisc Posting Suspense 9
67,688 21,750 45,938557Renewable Energy-Cert Fees 10
150,325 145,113 5,212557Nez Perce Settlement 11
178,106 147,131 30,975506Reg Asset ID-Lake CDA 12
36,474 62,978 26,504Credit Union Labor and Exp 13
-109,222 -86,092 23,130 VARMisc Work Orders <$50,000 14
433,608 471,651 38,043 VARSubsidiary Billings 15
16,568 16,568MiscDeferred Debits (WA) 16
1,878,235 2,154,581 276,346Regulatory Assets Consv 17
13,305,979 13,305,979Reg Asset-Decoupling deferred 18
-215,056 -206,235 8,821 909Optional Wind Power 19
6,503 4,823 1,680Gas Telemetry equip 20
225,361 225,361Misc Deferred Debits/Res Acctg 21
81,208 81,208Mutual Aid Response PGE 22
3,346,902 3,346,902Deferred Project Compass - ID 23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94)Page 233
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
11,803,983 26,759,597

ICNU_DR_118 Attachment A

Page 99 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Description and Location Balance of Begining
(c)(b)(a)
Balance at Endof Year of Year
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
Electric 1
10,573,200 8,884,982 2
3
4
5
6
Other 7
10,573,200 8,884,982TOTAL Electric (Enter Total of lines 2 thru 7) 8
Gas 9
750,525 1,147,643 10
11
12
13
14
Other 15
750,525 1,147,643TOTAL Gas (Enter Total of lines 10 thru 15 16
124,712,394 113,228,849Other 17
136,036,119 123,261,474TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18
Notes
FERC FORM NO. 1 (ED. 12-88)Page 234

ICNU_DR_118 Attachment A

Page 100 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Class and Series of Stock and Number of shares
(c)(b)(a)
Call Price at
End of Year
Par or Stated
Value per share
(d)
Name of Stock Series Authorized by Charter
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Account 201 - Common Stock Issued 1
200,000,000 No Par Value 2
Restricted shares 3
200,000,000Total Common 4
5
6
10,000,000Account 204 - Preferred Stock Issued 7
8
9
Cumulative 10
11
12
10,000,000Total Preferred 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-91)Page 250

ICNU_DR_118 Attachment A

Page 101 of 235
AS REACQUIRED STOCK (Account 217)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204) (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT
IN SINKING AND OTHER FUNDS
Shares(g)Cost(h)Shares SharesAmount
(Total amount outstanding without reduction
for amounts held by respondent)
Amount(e)(f)(i)(j)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
1
984,603,843 62,312,651 2
3,881,870 106,091 3
3,881,870 106,091 984,603,843 62,312,651 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-88)Page 251

ICNU_DR_118 Attachment A

Page 102 of 235
Schedule Page: 250 Line No.: 2 Column: a
During 2015, the Company executed a stock repurchase program. Through 12/31/15, the Company
repurchased 89,400 shares. All repurchased shares under the program were retired and reverted to
the status of authorized, but unissued shares. The amounts in account 214 applicable to the retired
shares were written off due to the stock repurchase.
Schedule Page: 250 Line No.: 3 Column: i
Restricted share awards vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the
end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target
in order for the CEO’s restricted shares to vest. Restricted stock is valued at the close of market of the Company’s common stock on
the grant date.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 103 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line Item Amount(b)(a)
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
No.
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end
of year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
-9,506,476Equity transactions of subsidiaries 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
FERC FORM NO. 1 (ED. 12-87)Page 253
40 TOTAL -9,506,476

ICNU_DR_118 Attachment A

Page 104 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
CAPITAL STOCK EXPENSE (Account 214)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Class and Series of Stock Balance at End of Year
(b)(a)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
-29,238,213Common Stock - no par 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
FERC FORM NO. 1 (ED. 12-87)Page 254b
22 TOTAL -29,238,213

ICNU_DR_118 Attachment A

Page 105 of 235
Schedule Page: 254 Line No.: 1 Column: b
Beginning Balance $
(25,079,123)
Issuance Costs of Common Stock $
55,902
Repurchase and Retirement of Common Stock $
31,833
Tax Benefit-Options Excercised $
(51,358)
Excess Tax Benefits on stock compensation $
1,831,678
Stock Compensation Accrual $
(6,027,145)
Ending Balance $
(29,238,213)
During 2015, the Company executed a stock repurchase program. Through 12/31/15, the Company
repurchased 89,400 shares. All repurchased shares under the program were retired and reverted to
the status of authorized, but unissued shares. The amounts in account 214 applicable to the retired
shares were written off due to the stock repurchase.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 106 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as
specified by the Uniform System of Accounts.
42,712 5,500,000FMBS - SERIES A - 7.53% DUE 05/05/2023 1
7,766 1,000,000FMBS - SERIES A - 7.54% DUE 5/05/2023 2
54,364 7,000,000FMBS - SERIES A - 7.39% DUE 5/11/2018 3
120,377 15,500,000FMBS - SERIES A - 7.45% DUE 6/11/2018 4
50,220 Discount - FMBS - SERIES A - 7.45% DUE 6/11/2018 5
54,364 7,000,000FMBS - SERIES A - 7.18% DUE 8/11/2023 6
1,296,086 51,547,000ADVANCE ASSOCIATED-AVISTA CAPITAL II (ToPRS) 7
158,304 25,000,000FMBS - 6.37% SERIES C 8
1,192,681 90,000,000FMBS - 5.45% SERIES 9
239,400 Discount- FMBS - 5.45% SERIES 10
1,812,935 150,000,000FMBS - 6.25% SERIES 11
367,500 Discount- FMBS - 6.25% SERIES 12
4,702,304 150,000,000FMBS - 5.70% SERIES 13
222,000 Discount- FMBS - 5.70% SERIES 14
2,246,419 250,000,000FMBS - 5.95% SERIES 15
835,000 Discount- FMBS - 5.95% SERIES 16
2,284,788 250,000,000FMBS - 5.125% SERIES 17
575,000 Discount- FMBS - 5.125% SERIES 18
66,700,000COLSTRIP 2010A PCRBs DUE 2032 19
17,000,000COLSTRIP 2010B PCRBs DUE 2034 20
385,129 52,000,000FMBS - 3.89% SERIES 21
258,834 35,000,000FMBS - 5.55% SERIES 22
692,833 85,000,0004.45% SERIES DUE 12-14-2041 23
730,833 80,000,0004.23% SERIES DUE 11-29-2047 24
515,369 90,000,000FMBS- 0.84% SERIES 25
428,782 60,000,000FMBS- 4.11% SERIES 26
556,713 100,000,000FMBS- 4.37% SERIES 27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 1,588,247,000 19,830,713
ICNU_DR_118 Attachment A

Page 107 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Nominal Date
of Issue
Date of
Maturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding without
reduction for amounts held byrespondent)
Interest for Year
Amount
(d)(e)(f)(g)(h)(i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
5,500,000 414,15005-05-202305-06-199305-05-202305-06-1993 1
1,000,000 75,40005-05-202305-07-199305-05-202305-07-1993 2
7,000,000 517,30005-11-201805-11-199305-11-201805-11-1993 3
15,500,000 1,154,75006-11-201806-09-199306-11-201806-09-1993 4
5
7,000,000 502,60008-11-202308-12-199308-11-202308-12-1993 6
51,547,000 473,35206-01-203706-03-199706-01-203706-03-1997 7
25,000,000 1,592,50006-19-202806-19-199806-19-202806-19-1998 8
90,000,000 4,905,00012-01-201911-18-200412-01-201911-18-2004 9
10
150,000,000 9,375,00012-01-203511-17-200512-01-203511-17-2005 11
12
150,000,000 8,550,00007-01-203712-15-200607-01-203712-15-2006 13
14
250,000,000 14,875,00006-01-201804-02-200806-01-201804-02-2008 15
16
250,000,000 12,812,50004-01-202209-22-200904-01-202209-22-2009 17
18
66,700,00010-1-203212-15-201010-1-203212-15-2010 19
17,000,0003-1-203412-15-20103-1-203412-15-2010 20
52,000,000 2,022,80012-20-202012-20-201012-20-202012-20-2010 21
35,000,000 1,942,50012-20-204012-20-201012-20-204012-20-2010 22
85,000,000 3,782,50012-14-204112-14-201112-14-204112-14-2011 23
80,000,000 3,384,00011-29-204711-30-201211-29-204711-30-2012 24
90,000,000 756,0008-14-20168-13-20138-14-20168-14-2013 25
60,000,000 2,466,00012-1-204412-18-1412-1-204412-18-2014 26
100,000,000 194,22212-1-204512-16-201512-1-204512-16-2015 27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 1,588,247,000 69,795,574
ICNU_DR_118 Attachment A

Page 108 of 235
Schedule Page: 256 Line No.: 7 Column: a
Upon issuance Avista Capital II issued $1.5 million of Common Trust Securities to the
Company. In December 2000, the Company purchased $10.0 million of these Preferred Trust
Securities.
Schedule Page: 256 Line No.: 7 Column: i
Upon issuance Avista Capital II issued $1.5 million of Common Trust Securities to the
Company. In December 2000, the Company purchased $10.0 million of these Preferred Trust
Securities. The interest for the year disclosed in column (i) reflects the net amount
owed to third parties.
Schedule Page: 256 Line No.: 19 Column: a
The Company reacquired this debt in 2010. These bonds have not been retired or canceled; the Company plans, based on
liquidity needs and market conditions, to remarket these bonds at a future date.
Schedule Page: 256 Line No.: 19 Column: c
The Company reacquired these bonds in 2010.
Schedule Page: 256 Line No.: 20 Column: a
The Company reacquired this debt in 2010. These bonds have not been retired or canceled; the Company plans, based on
liquidity needs and market conditions, to remarket these bonds at a future date.
Schedule Page: 256 Line No.: 20 Column: c
The Company reacquired these bonds in 2010.
Schedule Page: 256 Line No.: 27 Column: a
The new issuance is based on the following state commission orders:
1. Order of the Washington Utilities and Transportation Commission entered July 13, 2011, as
amended on August 24, 2011 in Docket No. U-111176;
2. Order of the Idaho Public Utilities Commission, Order No. 32338, entered August 25, 2011;
3. Order of the Public Utility Commission of Oregon, Order No. 15305, entered October 6, 2015;
Order of the Public Service Commission of the State of Montana, Default Order No. 4535
Schedule Page: 256 Line No.: 27 Column: c
Expenses may change as more invoices related to this issuance become known.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 109 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Avista Corporation X
04/15/2016
2015/Q4
Particulars (Details)
(b)(a)
Amount Line
No.
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a
separate return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group
member, tax assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
123,227,041Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
-293,458,641 5
6
7
8
Deductions Recorded on Books Not Deducted for Return 9
167,018,431 10
11
12
13
Income Recorded on Books Not Included in Return 14
32,011,483 15
16
17
18
Deductions on Return Not Charged Against Book Income 19
-50,133,967 20
21
22
23
24
25
26
34,172,612Federal Tax Net Income 27
Show Computation of Tax: 28
919,149State Tax @ 2% Less Idaho ITC 29
35,091,761Federal Tax Net Income Less State Tax 30
12,282,116Federal Tax @ 35% 31
-7,241,736Prior Years Tax Return & Misc True Ups 32
-154,305Cabinet Gorge Tax Credits 33
34
4,886,075Total Federal Tax Expense 35
36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 261

ICNU_DR_118 Attachment A

Page 110 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a)(b)(c)(d)(e)(f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
FEDERAL: 1
-1,078,764 1,078,764Income Tax 2010 2
34,876 -34,876Income Tax 2011 3
-2,279,241 264,697 2,014,544Income Tax 2012 4
4,349,313 123,858 -3,666,967Income Tax 2013 5
-37,000,000 2,166,027 -4,319,636 -34,331,525Income Tax 2014 6
24,130,403 -5,786,505 11,039,712Income Tax (Current) 7
-1,920,588Retained Earnings (Current) 8
2,124,050 -2,124,050Prior Retained Earnings 9
-483,257Prior Retained Earnings 10
470,244 -470,244Prior Retained Earnings 11
-12,869,597 5,188,043 -38,017,611 Total Federal 12
13
STATE OF WASHINGTON: 14
14,117,079 -150,566 14,264,301Property Tax (2014) 15
6,438 15,566,000Property Tax (2015) 16
22,495 -22,495Excise Tax (2010) 17
2,849,769 81,261 2,768,507Excise Tax (2014) 18
23,339,258 26,045,762Excise Tax (2015) 19
3,823 -759 3,710 1,409Natural Gas Use Tax 20
23,888,611 23,837,695 2,953,568Municipal Occupation Tax 21
-105,669Community Solar 22
-1 1Sales & Use Tax (2013) 23
71,906 72,250Sales & Use Tax (2014) 24
957,174 1,085,002Sales & Use Tax (2015) 25
65,234,058 -759 66,385,689 20,037,541 Total Washington 26
27
STATE OF IDAHO: 28
41,220Income Tax (2013) 29
-255,482 113,280Income Tax (2014) 30
555,000 497,695Income Tax (2015) 31
719 -719Property Tax (2013) 32
3,345,172 3,397,575Property Tax (2014) 33
3,569,906 7,127,878Property Tax (2015) 34
5,618 1 5,617Sales & Use Tax (2014) 35
137,989 150,773Sales & Use Tax (2015) 36
-1 1KWH Tax (2012) 37
22,094 -5,049 27,143KWH Tax (2014) 38
369,501 393,696KWH Tax (2015) 39
-3,128 -3,128Franchise Tax (2013) 40
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 101,392,760 83,480,649 2 -10,725,297
ICNU_DR_118 Attachment A

Page 111 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEAR
Prepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items
(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)
(g)(h)(i)(j)(k)(l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
1
2
3
264,697 4
123,858 806,204 5
-4,319,668 32 514,866 6
-2,515,587 13,555,299 -18,877,196 7
-1,920,588 -1,920,588 8
9
-483,257 10
11
-8,367,288 13,555,331 -19,959,971 12
13
14
-14,191 -136,375 -3,344 15
3,193,000 12,373,000 15,559,562 16
22,495 17
130,302 -49,041 -1 18
5,878,949 20,166,813 2,706,504 19
3,710 537 20
5,722,909 18,114,786 2,902,651 21
-105,669 -105,669 22
-1 23
344 24
1,085,002 127,828 25
15,912,797 50,472,892 21,188,412 26
27
28
41,220 29
-51,096 -204,386 -142,202 30
-515,459 1,013,154 -57,305 31
718 1 32
52,403 33
1,410,162 5,717,716 3,557,972 34
1 35
150,773 12,784 36
37
-5,049 38
-19,485 413,181 24,195 39
40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 87,087,842 14,304,919 7,186,818

ICNU_DR_118 Attachment A

Page 112 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a)(b)(c)(d)(e)(f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
1,650,689 1,650,689Franchise Tax (2014) 1
3,084,524 4,611,505Franchise Tax (2015) 2
12,737,365 -1 12,521,736 5,231,678 Total Idaho 3
4
STATE OF MONTANA: 5
-22,865 22,865Income Tax (2011 & Prior) 6
348,781 -423,731Income Tax (2014) 7
305,000 -108,607Income Tax (2015) 8
4,217,182 4,226,439Property Tax (2014) 9
4,250,729 8,484,422Property Tax (2015) 10
3,965 3,965Colstrip Generation Tax 11
263,479 263,479KWH Tax (2014) 12
898,734 1,138,846KWH Tax (2015) 13
61 75 9Consumer Council Tax 14
54 95 19Public Commission Tax 15
9,939,204 9,844,712 4,089,080 Total Montana 16
17
STATE OF OREGON: 18
-200,000 1 -300,000 99,999Income Tax (2012) 19
555,185 -655,185Income Tax (2014) 20
-378,037Income Tax (2015) 21
2,086,108 -2,086,108Property Tax (2013) 22
86,548 -86,548Property Tax (2014) 23
5,445,699 2,722,850Property Tax (2015) 24
-17,483BETC Credit (2010 and Prior) 25
-29,962BETC Credit (2011) 26
-57,789BETC Credit (2012) 27
-34,911Glendate Regulatory Cr. 2009 28
776,332 4 776,328Franchise Tax (2014) 29
2,632,302 -2 3,552,644Franchise Tax (2015) 30
8,654,333 3 8,325,298 -2,091,659 Total Oregon 31
32
STATE OF CALIFORNIA: 33
800 -800Income Tax (2011) 34
1,600 -1,600Income Tax (2014) 35
2,400 -2,400 Total California 36
37
MISCELLANEOUS STATES: 38
1Income Tax (2013) 39
28,632Income Tax (2014) 40
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 101,392,760 83,480,649 2 -10,725,297
ICNU_DR_118 Attachment A

Page 113 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEAR
Prepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items
(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)
(g)(h)(i)(j)(k)(l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
720 -720 1
1,135,070 3,476,436 1,526,981 2
2,111,404 10,410,333 5,016,048 3
4
5
-22,865 6
348,781 -74,950 7
-233,684 125,077 -413,607 8
9,257 9
8,484,422 4,233,693 10
3,965 11
12
1,138,846 240,112 13
-14 89 23 14
14 81 60 15
-233,684 10,078,396 3,994,588 16
17
18
-300,000 19
416,389 138,796 -100,000 20
-378,817 780 -378,037 21
1,175,761 910,347 22
-75,505 162,053 23
1,363,936 1,358,914 -2,722,849 24
-17,483 25
-29,962 26
-57,789 27
-34,911 28
29
3,552,644 920,340 30
5,754,408 2,570,890 -2,420,691 31
32
33
800 34
1,600 35
2,400 36
37
38
1 39
28,632 40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 87,087,842 14,304,919 7,186,818

ICNU_DR_118 Attachment A

Page 114 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a)(b)(c)(d)(e)(f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other
than accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
-646,729Income Tax (2015) 1
-646,729 28,633 Total Misc States 2
3
COUNTY & MUNICIPAL 4
13,850Vehicle Excise Tax 5
-294,364 -294,364 -561WA Renewable Energy 6
65,800 759 65,975 2Misc. 7
-214,714 759 -228,389 -559Total County 8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 262.2
TOTAL41 101,392,760 83,480,649 2 -10,725,297
ICNU_DR_118 Attachment A

Page 115 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEAR
Prepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items
(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)
(g)(h)(i)(j)(k)(l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifying the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
-646,729 -646,729 1
-646,729 -618,096 2
3
4
-13,850 5
-294,364 -561 6
65,975 939 7
-228,389 -13,472 8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.2
41 87,087,842 14,304,919 7,186,818

ICNU_DR_118 Attachment A

Page 116 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Account Balance at Beginning
(c)(b)(a)
of YearSubdivisions AdjustmentsDeferred for Year Allocations toCurrent Year's Income
Account No. Amount Account No. Amount(d)(e)(f)(g)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i)
the average period over which the tax credits are amortized.
Electric Utility 1
3% 2
4% 3
7% 4
10% 5
411 12,038,839 511,740 6
7
TOTAL 12,038,839 511,740 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
Gas Property (100% 33,504 411 10,176 10
85,164 411 19,884 11
TOTAL PROPERTY 118,668 30,060 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89)Page 266

ICNU_DR_118 Attachment A

Page 117 of 235
Balance at End
(i)(h)
of Year
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
ADJUSTMENT EXPLANATIONAverage Periodof Allocation
to Income
1
2
3
4
5
12,550,579 6
7
12,550,579 8
9
23,328 10
65,280 11
88,608 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89)Page 267

ICNU_DR_118 Attachment A

Page 118 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
OTHER DEFFERED CREDITS (Account 253)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Description and Other DEBITS
Credits
Account(c)(b)(a)
Balance at
End of Year
(d)
Deferred Credits Amount
(e)
Balance at
Beginning of Year Contra
(f)
1. Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
Energy Commodity (253020) 14,694,374 14,694,374 1
1,124,990Defer Gas Exchange (253028) 1,125,000 10 2
171,932Rathdrum Refund (253120) 138,110 33,822 3
26,528NE Tank Spill (253130) 3,230 23,298 4
664,699Kettle Falls Diesel Leak (254135) 236,135 428,564 5
311,640Bills Pole Rentals (253140) 184,401 127,239 6
1,164,668CR-CS2 GE LTSA (253150) 1,164,668 7
225,361CR-Credit Resource Actg 225,361 8
177,282DOC EECE Grant (253155) 17,918 159,364 9
10,329Defer Comp Retired Execs (253900) 10,329 10
8,676,886Defer Comp Active Execs (253910) 8,093,780 583,106 11
140,000Executive Incent Plan (253920) 140,000 12
674,258Unbilled Revenue (253990) 848,734 174,476 13
4,224,011WA Energy Recovery Mechanism 11,535,183 7,311,172 14
3,677,156Misc Deferred Credits 2,773,438 903,718 15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94)Page 269
47 TOTAL 22,180,032 3,659,469 39,790,303 21,269,740

ICNU_DR_118 Attachment A

Page 119 of 235

This Page Intentionally Left Blank

ICNU_DR_118 Attachment A

Page 120 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Account
(a)(b)(c)(d)
Balance at
Beginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
Account 282 1
Electric 389,834,132 53,938,541 2
Gas 141,409,318 -5,797,368 3
Other 51,477,902 16,007,841 4
TOTAL (Enter Total of lines 2 thru 4) 582,721,352 64,149,014 5
6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 582,721,352 64,149,014 9
Classification of TOTAL 10
Federal Income Tax 568,018,213 62,428,794 11
State Income Tax 14,703,139 1,720,220 12
Local Income Tax 13
FERC FORM NO. 1 (ED. 12-96)Page 274
NOTES

ICNU_DR_118 Attachment A

Page 121 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
Debits CreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 Account
Credited
Amount
Debited
Account Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
443,772,673 2
135,611,950 3
67,485,743 4
646,870,366 5
6
7
8
646,870,366 9
10
630,447,007 11
16,423,359 12
13
FERC FORM NO. 1 (ED. 12-96)Page 275
NOTES (Continued)

ICNU_DR_118 Attachment A

Page 122 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Account
(a)(b)(c)(d)
Balance at
Beginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
Account 283 1
Electric 2
-869,714 17,343,593 Electric 3
4
5
6
7
8
-869,714 17,343,593TOTAL Electric (Total of lines 3 thru 8) 9
Gas 10
-2,628,563 -708,828 Gas 11
12
13
14
15
16
-2,628,563 -708,828TOTAL Gas (Total of lines 11 thru 16) 17
7,992,949 208,219,022Other 18
4,494,672 224,853,787TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
4,494,672 224,853,787Federal Income Tax 21
State Income Tax 22
Local Income Tax 23
FERC FORM NO. 1 (ED. 12-96)Page 276
NOTES

ICNU_DR_118 Attachment A

Page 123 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
Debits CreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 Account
Credited
Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
1
2
16,367,410 106,469 3
4
5
6
7
8
16,367,410 106,469 9
10
-3,286,746 -50,645 11
12
13
14
15
16
-3,286,746 -50,645 17
214,729,975 -5,173,655 -3,691,659 18
227,810,639 -5,173,655 -3,635,835 19
20
227,810,639 -5,173,655 -3,635,835 21
22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)

ICNU_DR_118 Attachment A

Page 124 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
OTHER REGULATORY LIABILITIES (Account 254)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Description and Purpose of DEBITS
CreditsAccount
(d)(c)(a)
Balance at End
of Current
Quarter/Year
(e)
Other Regulatory Liabilities Amount
(f)
Credited
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining
of Current
Quarter/Year
(b)
10,462,039 11,288,009 825,970Idaho Investment Tax Credit (254005) 1
831,138 1,099,872 268,734Oregon BETC Credit (254010) 2
3,241,231 52,632 3,188,599Noxon, ITC (254025)190 3
190,418 190,418Community Solar ITC (254035) 4
16,423,552 2,152,005 14,271,547Settled Int Rate Swaps (254090)428 5
460,316 437,629 22,687Unsettled Int Rate Swaps (254100)176 6
63,900 16,188 47,712FAS 109 Invest Credit (254180)190 7
638,348 22,008 616,340Nez Perce (254220)557 8
4,275,418 3,515,350 760,068Idaho Earnings Test (254229)407 9
808,136 808,136BPA Parallel Capacity (254331)407 10
1,659,457 1,230,833 428,624BPA RES EXCH (254345)407 11
1,841,650 1,841,650Other Regulatory Liabilities 12
9,962,091 9,962,091 6,457,271 6,457,271WA ERM 13
754,958 754,958ID PCA 14
8,729 8,729Roseburg/Medford 15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
41 TOTAL 10,339,001 18,196,872 40,976,484 48,834,355

ICNU_DR_118 Attachment A

Page 125 of 235

This Page Intentionally Left Blank

ICNU_DR_118 Attachment A

Page 126 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Title of Account
(c)(b)(a)
Operating Revenues Year
to Date Quarterly/Annual
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the close of
each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
Operating Revenues
Previous year (no Quarterly)
Sales of Electricity 1
338,697,524(440) Residential Sales 335,551,962 2
(442) Commercial and Industrial Sales 3
300,108,664Small (or Comm.) (See Instr. 4) 308,210,379 4
110,774,727Large (or Ind.) (See Instr. 4) 111,769,969 5
7,549,449(444) Public Street and Highway Lighting 7,276,497 6
(445) Other Sales to Public Authorities 7
(446) Sales to Railroads and Railways 8
1,163,952(448) Interdepartmental Sales 1,190,013 9
758,294,316TOTAL Sales to Ultimate Consumers 763,998,820 10
150,887,383(447) Sales for Resale 133,316,869 11
909,181,699TOTAL Sales of Electricity 897,315,689 12
7,503,194(Less) (449.1) Provision for Rate Refunds 5,620,861 13
901,678,505TOTAL Revenues Net of Prov. for Refunds 891,694,828 14
Other Operating Revenues 15
(450) Forfeited Discounts 16
527,893(451) Miscellaneous Service Revenues 252,517 17
475,000(453) Sales of Water and Water Power 407,336 18
3,037,405(454) Rent from Electric Property 2,632,221 19
(455) Interdepartmental Rents 20
94,639,088(456) Other Electric Revenues 96,650,358 21
14,745,982(456.1) Revenues from Transmission of Electricity of Others 14,502,801 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
113,425,368TOTAL Other Operating Revenues 114,445,233 26
1,015,103,873TOTAL Electric Operating Revenues 1,006,140,061 27
Page 300FERC FORM NO. 1/3-Q (REV. 12-05)

ICNU_DR_118 Attachment A

Page 127 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
MEGAWATT HOURS SOLD
Previous Year (no Quarterly)Current Year (no Quarterly)
AVG.NO. CUSTOMERS PER MONTH
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)
(d)(e)(f)(g)
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by the
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification
in a footnote.)
7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
1
3,693,787 324,188 329,874 3,571,426 2
3
3,189,422 40,988 41,710 3,196,583 4
1,868,012 1,385 1,364 1,811,996 5
25,116 531 551 23,304 6
7
8
12,585 103 115 12,345 9
8,788,922 367,195 373,614 8,615,654 10
4,050,611 3,326,381 11
12,839,533 367,195 373,614 11,942,035 12
13
12,839,533 367,195 373,614 11,942,035 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
-13,175,657
-194,333
FERC FORM NO. 1/3-Q (REV. 12-05)

ICNU_DR_118 Attachment A

Page 128 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Number
of Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 RESIDENTIAL SALES (440)
3,478,794 313,869 11,084 0.0898 312,235,814 2 1 Residential Service
487 30 16,233 0.0589 28,695 3 2 Residential Service
4 3 Residential Service
81,406 14,147 5,754 0.1380 11,231,423 5 12 Res. & Farm Gen. Service
6 15 MOPS II Residential
45,218 75 602,907 0.0866 3,917,005 7 22 Res. & Farm Lg. Gen. Service
2 1 2,000 0.1160 232 8 30 Pumping-Special
9,743 1,752 5,561 0.1163 1,133,160 9 32 Res. & Farm Pumping Service
4,289 0.2508 1,075,719 10 48 Res. & Farm Area Lighting
242 0.3170 76,718 11 49 Area Lighting-High-Press.
12 56 Centralia Refund
147,714 13 95 Wind Power
14 72 Residential Service
15 73 Residential Service
16 74 Residential Service
17 76 Residential Service
18 77 Residential Service
-30,325 19 58A Tax Adjustment
9,313,223 20 58 Tax Adjustment
3,620,181 329,874 10,974 0.0937 339,129,378 21 SubTotal
-48,755 0.0734 -3,577,416 22 Residential-Unbilled
3,571,426 329,874 10,827 0.0940 335,551,962 23 Total Residential Sales
24
25 COMMERCIAL SALES (442)
26 2 General Service
27 3 General Service
875,090 37,577 23,288 0.1130 98,857,673 28 11 General Service
29 12 Res. & Farm Gen. Service
30 16 MOPS II Commercial
31 19 Contract-General Service
1,882,291 2,948 638,498 0.0887 166,968,084 32 21 Large General Service
383,461 14 27,390,071 0.0637 24,420,971 33 25 Extra Lg. Gen. Service
34 28 Contract-Extra Large Serv
103,589 1,171 88,462 0.0848 8,788,271 35 31 Pumping Service
6,266 0.2274 1,425,183 36 47 Area Lighting-Sod. Vap
2,645 0.2374 628,013 37 49 Area Lighting-High-Press.
38 56 Centralia Refune
87,693 39 95 Wind Power
40 74 Large General Service
11,942,035 897,315,689 373,614 31,964 0.0751
-194,333 -13,175,657 0 0 0.0678
12,136,368 910,491,346 373,614 32,484 0.0750
FERC FORM NO. 1 (ED. 12-95)Page 304
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
ICNU_DR_118 Attachment A

Page 129 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Number
of Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 75 Large General Service
2 76 Large General Service
3 77 General Service
-39,239 4 58A Tax Adjustment
11,203,493 5 58 Tax Adjustment
3,253,342 41,710 77,999 0.0960 312,340,142 6 SubTotal
-56,759 0.0728 -4,129,763 7 Commercial-Unbilled
3,196,583 41,710 76,638 0.0964 308,210,379 8 Total Commercial
9
10 INDUSTRIAL SALES (442)
11 2 General Service
12 3 General Service
13 8 Lg Gen Time of Use
10,674 259 41,212 0.1157 1,235,407 14 11 General Service
15 12 Res. & Farm Gen. Service
215,729 156 1,382,878 0.0856 18,459,806 16 21 Large General Service
1,568,445 19 82,549,737 0.0558 87,453,608 17 25 Extra Lg. Gen. Service
18 28 Contract - Extra Large Service
19 29 Contract Lg. Gen. Service
24,751 31 798,419 0.0702 1,737,710 20 30 Pumping Service - Special
73,277 762 96,164 0.0861 6,305,626 21 31 Pumping Service
5,530 137 40,365 0.0877 484,730 22 32 Pumping Svc Res & Firm
192 0.2089 40,115 23 47 Area Lighting-Sod. Vap.
70 0.2215 15,508 24 49 Area Lighting - High-Press
2,042 25 95 Wind Power
1 0.2330 233 26 48 Area Lighting-Sod. Vap.
27 73 General Service
28 74 Large General Service
29 75 Large General Service
30 76 Pumping Service
31 77 General Service
-1,293 32 58A Tax Adjustment
934,255 33 58 Tax Adjustment
1,898,669 1,364 1,391,986 0.0614 116,667,747 34 SubTotal
-86,673 0.0565 -4,897,778 35 Industrial-Unbilled
1,811,996 1,364 1,328,443 0.0617 111,769,969 36 Total Industrial
37
38 STREET AND HWY LIGHTING (444)
39 6 Mercury Vapor St. Ltg.
40 7 HP Sodium Vap. St. Ltg
11,942,035 897,315,689 373,614 31,964 0.0751
-194,333 -13,175,657 0 0 0.0678
12,136,368 910,491,346 373,614 32,484 0.0750
FERC FORM NO. 1 (ED. 12-95)Page 304.1
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
ICNU_DR_118 Attachment A

Page 130 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Number
of Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12
if all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
2 0.1275 255 1 11 General Service
225 15 15,000 0.2011 45,240 2 41 Co-Owned St. Lt. Service
21,507 425 50,605 0.3322 7,145,489 3 42 Co-Owned St. Lt. Service
4 High-Press. Sod. Vap.
1 1 1,000 0.1290 129 5 43 Cust-Owned St. Lt. Energy
6 and Maint. Service
646 30 21,533 0.1533 99,030 7 44 Cust-Owned St. Lt. Energy
8 and Maint. Svce - High-Pres
9 Sodium Vapor
778 16 48,625 0.0710 55,260 10 45 Cust. Owned St. Lt. Energy Svc
2,291 64 35,797 0.0979 224,383 11 46 Cust. Owned St. Lt. Energy Svc
-824 12 58A Tax Adjustment
278,235 13 58 Tax Adjustment
25,450 551 46,189 0.3083 7,847,197 14 SubTotal
-2,146 0.2659 -570,700 15 Street & Hwy Lighting-Unbilled
23,304 551 42,294 0.3122 7,276,497 16 Total Street & Hwy Lighting
17
18 OTHER SALES TO PUBLIC
19 (445)
20 None
21
12,345 115 107,348 0.0964 1,190,013 22 INTERDEPARTMENTAL SALES
23 58 Tax Adjustment
12,345 115 107,348 0.0964 1,190,013 24 Total Interdepartmental
25
3,326,381 0.0401 133,316,869 26 SALES FOR RESALE (447)
27 61 Sales to Other Utilities (NDA)
28
29
3,326,381 0.0401 133,316,869 30 Total Sales for Resale
31
32
33
34
35
36
37
38
39
40
11,942,035 897,315,689 373,614 31,964 0.0751
-194,333 -13,175,657 0 0 0.0678
12,136,368 910,491,346 373,614 32,484 0.0750
FERC FORM NO. 1 (ED. 12-95)Page 304.2
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
ICNU_DR_118 Attachment A

Page 131 of 235

This Page Intentionally Left Blank

ICNU_DR_118 Attachment A

Page 132 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
ATCO Power Canada Ltd.Tariff 9SF 1
BP Energy Company Tariff 9SF 2
Bonneville Power Administration Tariff 8LF 3
Bonneville Power Administration ACS-06LF 4
Bonneville Power Administration Tariff 9SF 5
Bonneville Power Administration Tariff 12LF 6
British Columbia Hydro and Power Author Tariff 12LF 7
Calpine Energy Services LP Tariff 9SF 8
Cargill Power Markets, LLC Tariff 9SF 9
Chelan County PUD No. 1 Tariff 9SF 10
Chelan County PUD No. 1 Tariff 12LF 11
City of Redding Tariff 9SF 12
Clark County PUD No. 1 Tariff 9SF 13
Clatskanie Peoples PUD Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90)Page 310
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0

ICNU_DR_118 Attachment A

Page 133 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
1,200 1,200 50 1
1,161,300 1,161,300 52,008 2
960,689 960,689 24,203 3
95,991 95,991 4,573 4
2,155,820 2,155,820 86,427 5
2,272 2,272 88 6
534 534 18 7
2,160,797 2,160,797 109,144 8
598,105 598,105 33,290 9
90,740 90,740 4,400 10
156 156 5 11
46,400 46,400 1,280 12
94,675 94,675 3,781 13
57,161 57,161 2,524 14
FERC FORM NO. 1 (ED. 12-90)Page 311
0
60,296,083
60,296,083
0
3,326,381
3,326,381
0 0
55,525,994
55,525,994
133,316,869
133,316,869
0
17,494,792
17,494,792

ICNU_DR_118 Attachment A

Page 134 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
ConocoPhillips Tariff 9SF 1
Douglas County PUD No. 1 Tariff 9SF 2
EDF Trading North America, LLC Tariff 9SF 3
Energy America, LLC Tariff 9LF 4
Energy Keepers, Inc.Tariff 9SF 5
Eugene Water & Electric Board Tariff 9SF 6
Exelon Generation Company, LLC Tariff 9SF 7
Grant County PUD No. 2 Tariff 9SF 8
Grant County PUD No. 2 Tariff 12LF 9
Grant County PUD No. 2 Tariff 9SF 10
Gridforce Energy Management, LLC Tariff 12LF 11
Iberdrola Renewables, LLC Tariff 9SF 12
Iberdrola Renewables, LLC Tariff 9SF 13
Idaho Power Company Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.1
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0

ICNU_DR_118 Attachment A

Page 135 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
22,400 22,400 800 1
107,940 107,940 4,880 2
3,684,314 3,684,314 166,123 3
11,253,310 11,253,310 427,515 4
2,014 2,014 75 5
364,907 364,907 16,428 6
555,734 555,734 24,655 7
254,065 254,065 10,763 8
93 93 5 9
3,170 3,170 10
1,079 1,079 52 11
7,707,319 7,707,319 364,763 12
398,190 398,190 13
33,470 33,470 1,640 14
FERC FORM NO. 1 (ED. 12-90)Page 311.1
0
60,296,083
60,296,083
0
3,326,381
3,326,381
0 0
55,525,994
55,525,994
133,316,869
133,316,869
0
17,494,792
17,494,792

ICNU_DR_118 Attachment A

Page 136 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Idaho Power Company Tariff 12LF 1
Idaho Power Balancing Tariff 9SF 2
J. Aron & Company Tariff 9SF 3
JP Morgan Ventures Energy Tariff 9SF 4
Kootenai Electric Cooperative Tariff 8LF 5
Macquarie Energy, LLC Tariff 9SF 6
Mizuho Securities USA, Inc.ISDASF 7
Modesto Irrigation District Tariff 9SF 8
Morgan Stanley Capital Group, Inc.Tariff 9SF 9
Morgan Stanley Capital Group, Inc.Tariff 9SF 10
Morgan Stanley Capital Group, Inc.Tariff 9SF 11
Morgan Stanley Capital Group, Inc.Tariff 9SF 12
NaturEner Power Watch, LLC Tariff 9SF 13
NaturEner Power Watch, LLC Tariff 12LF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.2
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0

ICNU_DR_118 Attachment A

Page 137 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
536 536 21 1
2,133,750 2,133,750 79,353 2
17,000 17,000 400 3
320,965 320,965 16,814 4
36,593 36,593 1,520 5
2,222,352 2,222,352 103,034 6
14,527,592 14,527,592 7
198,400 198,400 5,120 8
3,587,619 3,587,619 161,377 9
275,940 275,940 10
1,223,420 1,223,420 11
182,847 182,847 12
137,502 137,502 6,249 13
881 881 45 14
FERC FORM NO. 1 (ED. 12-90)Page 311.2
0
60,296,083
60,296,083
0
3,326,381
3,326,381
0 0
55,525,994
55,525,994
133,316,869
133,316,869
0
17,494,792
17,494,792

ICNU_DR_118 Attachment A

Page 138 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
NaturEner Power Watch, LLC Tariff 9SF 1
NaturEner Power Watch, LLC Tariff 9SF 2
Nevada Power Company Tariff 9SF 3
NorthWestern Energy LLC Tariff 9SF 4
NorthWestern Energy LLC Tariff 12LF 5
NorthWestern Energy LLC Tariff 9LF 6
NorthWestern Energy LLC Tariff 10SF 7
Okanogan County PUD Tariff 9SF 8
PacifiCorp Tariff 9SF 9
PacifiCorp Tariff 12LF 10
PacifiCorp Tariff 9LF 11
Peaker LLC Tariff 9LF 12
Pend Oreille Public Utility District Tariff 9IF 13
Pend Oreille Public Utility District Tariff 9IF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.3
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0

ICNU_DR_118 Attachment A

Page 139 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
175,200 175,200 1
275,940 275,940 2
63,433 63,433 5,462 3
1,784,276 1,784,276 52,742 4
1,230 1,230 54 5
168,326 168,326 7,820 6
392,022 392,022 7
597,427 597,427 18,996 8
3,941,860 3,941,860 158,946 9
4,702 4,702 220 10
107,116 107,116 4,977 11
535,770 535,770 12
538,480 538,480 13
326,535 326,535 14,725 14
FERC FORM NO. 1 (ED. 12-90)Page 311.3
0
60,296,083
60,296,083
0
3,326,381
3,326,381
0 0
55,525,994
55,525,994
133,316,869
133,316,869
0
17,494,792
17,494,792

ICNU_DR_118 Attachment A

Page 140 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Pend Oreille Public Utility District Tariff 9SF 1
Portland General Electric Company Tariff 9SF 2
Portland General Electric Company Tariff 9IF 3
Powerex Tariff 9SF 4
Powerex Tariff 9SF 5
Public Service Company of Colorado Tariff 9SF 6
Puget Sound Energy Tariff 9LF 7
Puget Sound Energy Tariff 9SF 8
Puget Sound Energy Tariff 12LF 9
Rainbow Energy Marketing Tariff 9SF 10
Sacramento Municipal Utility District Tariff 9SF 11
Sacramento Municipal Utility District Tariff 12LF 12
Seattle City Light Tariff 9SF 13
Seattle City Light Tariff 12LF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.4
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0

ICNU_DR_118 Attachment A

Page 141 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
1,640,510 1,640,510 66,786 1
4,326,572 4,326,572 198,649 2
13,325,000 13,325,000 3
3,673,697 3,673,697 207,349 4
130 130 5
23,500 23,500 1,200 6
489,674 489,674 22,745 7
2,542,049 2,542,049 127,335 8
588 588 20 9
249,357 249,357 9,841 10
2,410,679 2,410,679 106,686 11
479 479 24 12
569,564 569,564 24,354 13
279 279 8 14
FERC FORM NO. 1 (ED. 12-90)Page 311.4
0
60,296,083
60,296,083
0
3,326,381
3,326,381
0 0
55,525,994
55,525,994
133,316,869
133,316,869
0
17,494,792
17,494,792

ICNU_DR_118 Attachment A

Page 142 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
SG Americas Securities, LLC ISDASF 1
Shell Energy N.A.Tariff 9SF 2
Shell Energy N.A.Tariff 9SF 3
Sierra Pacific Power Company Tariff 12LF 4
Snohomish County PUD Tariff 9SF 5
Southern California Edison Company Tariff 9SF 6
Sovereign Power Tariff 9LF 7
Sovereign Power Tariff 9LF 8
Tacoma Power Tariff 9SF 9
Tacoma Power Tariff 12LF 10
Talen Energy Marketing, LLC Tariff 9SF 11
Talen Energy Marketing, LLC Tariff 9SF 12
Talen Energy Montana, LLC Tariff 9LF 13
Tenaska Power Services Co.Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.5
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0

ICNU_DR_118 Attachment A

Page 143 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
23,990,578 23,990,578 1
3,037,243 3,037,243 144,473 2
6,160 6,160 3
693 693 37 4
349,703 349,703 12,341 5
4,300 4,300 200 6
149,135 149,135 7
297,982 297,982 12,631 8
330,132 330,132 14,722 9
493 493 29 10
13,388 13,388 11
1,622,519 1,622,519 73,423 12
382,558 382,558 17,768 13
728 728 26 14
FERC FORM NO. 1 (ED. 12-90)Page 311.5
0
60,296,083
60,296,083
0
3,326,381
3,326,381
0 0
55,525,994
55,525,994
133,316,869
133,316,869
0
17,494,792
17,494,792

ICNU_DR_118 Attachment A

Page 144 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule orTariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must
be the same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy
from third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the
definition of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is
one year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
The Energy Authority Tariff 9SF 1
TransAlta Energy Marketing Tariff 9SF 2
Tri-State Generation & Transmission As Tariff 9SF 3
Turlock Irrigation District Tariff 9SF 4
WAPA - Western Area Power Admin Tariff 12LF 5
IntraCompany Wheeling LF 6
IntraCompany Generation LF 7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 310.6
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0

ICNU_DR_118 Attachment A

Page 145 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)
Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total'' in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
633,025 633,025 28,570 1
6,010,732 6,010,732 279,398 2
3
9,300 9,300 400 4
22 22 1 5
-15,373,283 15,373,283 6
1,634,541 1,634,541 7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 311.6
0
60,296,083
60,296,083
0
3,326,381
3,326,381
0 0
55,525,994
55,525,994
133,316,869
133,316,869
0
17,494,792
17,494,792

ICNU_DR_118 Attachment A

Page 146 of 235
Schedule Page: 310 Line No.: 3 Column: b
BPA Contract Terminates September 30, 2028.
Schedule Page: 310 Line No.: 4 Column: b
BPA Contract Terminates January 1, 2036.
Schedule Page: 310 Line No.: 6 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310 Line No.: 7 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310 Line No.: 11 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 4 Column: b
Energy America, LLC contract terminates 12/31/2019.
Schedule Page: 310.1 Line No.: 9 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 11 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 13 Column: b
Capacity
Schedule Page: 310.2 Line No.: 1 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.2 Line No.: 5 Column: b
Kootenai Contract Terminates March 31,2019
Schedule Page: 310.2 Line No.: 7 Column: b
SWAP
Schedule Page: 310.2 Line No.: 10 Column: b
Capacity
Schedule Page: 310.2 Line No.: 11 Column: b
Capacity
Schedule Page: 310.2 Line No.: 14 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.3 Line No.: 2 Column: b
Capacity
Schedule Page: 310.3 Line No.: 5 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.3 Line No.: 6 Column: b
NorthWestern Energy LLC sale expires October 31, 2018.
Schedule Page: 310.3 Line No.: 10 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.3 Line No.: 11 Column: b
PacifiCorp sale terminates October 31, 2018.
Schedule Page: 310.3 Line No.: 12 Column: b
Peaker, LLC capacity contract terminates December 31, 2016.
Schedule Page: 310.3 Line No.: 13 Column: b
Contract expires 9/30/2017.
Schedule Page: 310.3 Line No.: 14 Column: b
Contract expires 9/30/2017.
Schedule Page: 310.4 Line No.: 3 Column: b
Contract Expires 12/31/2016.
Schedule Page: 310.4 Line No.: 7 Column: b
Puget Sound Energy sale terminates October 31, 2018.
Schedule Page: 310.4 Line No.: 9 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.4 Line No.: 12 Column: b
NWPP Reserve Sharing Sales
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 147 of 235
Schedule Page: 310.4 Line No.: 14 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 1 Column: b
SWAP - Formerly Newedge USA, LLC
Schedule Page: 310.5 Line No.: 4 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 7 Column: b
Sovereign Power contract terminates 9-30-2019
Schedule Page: 310.5 Line No.: 8 Column: b
Sovereign Power Contract terminates 9-30-2019
Schedule Page: 310.5 Line No.: 10 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 11 Column: a
Name change effective 06/02/2015. Formerly PPL Energy Plus.
Schedule Page: 310.5 Line No.: 12 Column: a
Name change effective 06/02/2015. Formerly PPL Energy Plus.
Schedule Page: 310.5 Line No.: 13 Column: a
Name change effective 06/02/2015. Formerly PPL Montana.
Schedule Page: 310.5 Line No.: 13 Column: b
Sale terminates October 31,2018.
Schedule Page: 310.6 Line No.: 5 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.6 Line No.: 6 Column: a
Intracompany Wheeling
Schedule Page: 310.6 Line No.: 6 Column: b
IntraCompany Wheeling terminates 09/30/2023.
Schedule Page: 310.6 Line No.: 7 Column: a
IntraCompany Generation - Sale of Ancillary Services
Schedule Page: 310.6 Line No.: 7 Column: b
IntraCompany Generation - Sale of Ancillary Services.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2

ICNU_DR_118 Attachment A

Page 148 of 235
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.
Account Amount for
(c)(b)(a)
Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
1. POWER PRODUCTION EXPENSES 1
A. Steam Power Generation 2
Operation 3
(500) Operation Supervision and Engineering 4 208,443 282,011
(501) Fuel 5 29,005,009 30,794,427
(502) Steam Expenses 6 3,835,814 5,199,150
(503) Steam from Other Sources 7
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 984,464 1,228,906
(506) Miscellaneous Steam Power Expenses 10 2,295,553 2,967,067
(507) Rents 11 40,851 33,667
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 36,370,134 40,505,228
Maintenance 14
(510) Maintenance Supervision and Engineering 15 593,388 613,157
(511) Maintenance of Structures 16 795,357 758,347
(512) Maintenance of Boiler Plant 17 5,541,250 4,760,690
(513) Maintenance of Electric Plant 18 2,010,267 601,012
(514) Maintenance of Miscellaneous Steam Plant 19 2,739,562 954,982
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 11,679,824 7,688,188
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 48,049,958 48,193,416
B. Nuclear Power Generation 22
Operation 23
(517) Operation Supervision and Engineering 24
(518) Fuel 25
(519) Coolants and Water 26
(520) Steam Expenses 27
(521) Steam from Other Sources 28
(Less) (522) Steam Transferred-Cr. 29
(523) Electric Expenses 30
(524) Miscellaneous Nuclear Power Expenses 31
(525) Rents 32
TOTAL Operation (Enter Total of lines 24 thru 32) 33
Maintenance 34
(528) Maintenance Supervision and Engineering 35
(529) Maintenance of Structures 36
(530) Maintenance of Reactor Plant Equipment 37
(531) Maintenance of Electric Plant 38
(532) Maintenance of Miscellaneous Nuclear Plant 39
TOTAL Maintenance (Enter Total of lines 35 thru 39) 40
TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41
C. Hydraulic Power Generation 42
Operation 43
(535) Operation Supervision and Engineering 44 2,273,416 2,107,646
(536) Water for Power 45 1,304,313 1,300,900
(537) Hydraulic Expenses 46 7,158,884 7,201,535
(538) Electric Expenses 47 6,065,458 6,559,863
(539) Miscellaneous Hydraulic Power Generation Expenses 48 665,656 876,509
(540) Rents 49 6,931,274 7,109,260
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 24,399,001 25,155,713
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 857,660 1,616,897
(542) Maintenance of Structures 54 891,640 326,758
(543) Maintenance of Reservoirs, Dams, and Waterways 55 1,291,737 1,375,773
(544) Maintenance of Electric Plant 56 2,817,753 2,663,275
(545) Maintenance of Miscellaneous Hydraulic Plant 57 683,027 696,377
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 6,541,817 6,679,080
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 30,940,818 31,834,793
FERC FORM NO. 1 (ED. 12-93)Page 320

ICNU_DR_118 Attachment A

Page 149 of 235
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.
Account Amount for
(c)(b)(a)
Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
D. Other Power Generation 60
Operation 61
(546) Operation Supervision and Engineering 62 1,416,384 1,179,973
(547) Fuel 63 89,150,873 91,777,298
(548) Generation Expenses 64 1,841,494 2,016,313
(549) Miscellaneous Other Power Generation Expenses 65 625,162 461,399
(550) Rents 66 -37,276 -33,315
TOTAL Operation (Enter Total of lines 62 thru 66) 67 92,996,637 95,401,668
Maintenance 68
(551) Maintenance Supervision and Engineering 69 1,113,316 625,187
(552) Maintenance of Structures 70 76,791 110,380
(553) Maintenance of Generating and Electric Plant 71 2,358,167 2,317,590
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 579,369 453,413
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 4,127,643 3,506,570
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 97,124,280 98,908,238
E. Other Power Supply Expenses 75
(555) Purchased Power 76 197,691,167 172,688,007
(556) System Control and Load Dispatching 77 978,453 1,049,171
(557) Other Expenses 78 87,372,432 84,496,416
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 286,042,052 258,233,594
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 462,157,108 437,170,041
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 2,248,616 2,119,618
84
(561.1) Load Dispatch-Reliability 85 45,521 94,738
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 1,334,633 1,377,187
(561.3) Load Dispatch-Transmission Service and Scheduling 87 1,074,917 1,082,332
(561.4) Scheduling, System Control and Dispatch Services 88
(561.5) Reliability, Planning and Standards Development 89
(561.6) Transmission Service Studies 90
(561.7) Generation Interconnection Studies 91
(561.8) Reliability, Planning and Standards Development Services 92
(562) Station Expenses 93 496,548 532,894
(563) Overhead Lines Expenses 94 537,485 458,587
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 18,896,022 17,389,891
(566) Miscellaneous Transmission Expenses 97 1,943,266 2,162,711
(567) Rents 98 154,350 153,599
TOTAL Operation (Enter Total of lines 83 thru 98) 99 26,731,358 25,371,557
Maintenance 100
(568) Maintenance Supervision and Engineering 101 802,377 808,914
(569) Maintenance of Structures 102 379,954 737,752
(569.1) Maintenance of Computer Hardware 103
(569.2) Maintenance of Computer Software 104
(569.3) Maintenance of Communication Equipment 105
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 1,421,588 1,358,489
(571) Maintenance of Overhead Lines 108 1,733,944 1,147,565
(572) Maintenance of Underground Lines 109 -6,721 9,887
(573) Maintenance of Miscellaneous Transmission Plant 110 101,431 107,904
TOTAL Maintenance (Total of lines 101 thru 110) 111 4,432,573 4,170,511
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 31,163,931 29,542,068
FERC FORM NO. 1 (ED. 12-93)Page 321

ICNU_DR_118 Attachment A

Page 150 of 235
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.
Account Amount for
(c)(b)(a)
Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
3. REGIONAL MARKET EXPENSES 113
Operation 114
(575.1) Operation Supervision 115
(575.2) Day-Ahead and Real-Time Market Facilitation 116
(575.3) Transmission Rights Market Facilitation 117
(575.4) Capacity Market Facilitation 118
(575.5) Ancillary Services Market Facilitation 119
(575.6) Market Monitoring and Compliance 120
(575.7) Market Facilitation, Monitoring and Compliance Services 121
(575.8) Rents 122
Total Operation (Lines 115 thru 122) 123
Maintenance 124
(576.1) Maintenance of Structures and Improvements 125
(576.2) Maintenance of Computer Hardware 126
(576.3) Maintenance of Computer Software 127
(576.4) Maintenance of Communication Equipment 128
(576.5) Maintenance of Miscellaneous Market Operation Plant 129
Total Maintenance (Lines 125 thru 129) 130
TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131
4. DISTRIBUTION EXPENSES 132
Operation 133
(580) Operation Supervision and Engineering 134 3,207,049 4,112,229
(581) Load Dispatching 135
(582) Station Expenses 136 598,094 742,050
(583) Overhead Line Expenses 137 2,304,774 1,999,534
(584) Underground Line Expenses 138 1,358,460 1,425,474
(585) Street Lighting and Signal System Expenses 139 62,128 12,587
(586) Meter Expenses 140 1,883,128 1,973,573
(587) Customer Installations Expenses 141 642,752 610,596
(588) Miscellaneous Expenses 142 7,507,882 7,334,740
(589) Rents 143 262,726 262,687
TOTAL Operation (Enter Total of lines 134 thru 143) 144 17,826,993 18,473,470
Maintenance 145
(590) Maintenance Supervision and Engineering 146 1,779,538 2,167,990
(591) Maintenance of Structures 147 296,322 388,297
(592) Maintenance of Station Equipment 148 857,682 1,079,662
(593) Maintenance of Overhead Lines 149 8,750,043 10,484,367
(594) Maintenance of Underground Lines 150 999,281 839,424
(595) Maintenance of Line Transformers 151 846,026 674,935
(596) Maintenance of Street Lighting and Signal Systems 152 714,295 692,950
(597) Maintenance of Meters 153 14,354 25,403
(598) Maintenance of Miscellaneous Distribution Plant 154 568,833 1,073,353
TOTAL Maintenance (Total of lines 146 thru 154) 155 14,826,374 17,426,381
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 32,653,367 35,899,851
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 323,796 356,243
(902) Meter Reading Expenses 160 2,844,990 3,082,621
(903) Customer Records and Collection Expenses 161 8,422,061 8,795,510
(904) Uncollectible Accounts 162 2,751,684 3,041,287
(905) Miscellaneous Customer Accounts Expenses 163 197,184 263,646
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 14,539,715 15,539,307
FERC FORM NO. 1 (ED. 12-93)Page 322

ICNU_DR_118 Attachment A

Page 151 of 235
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.
Account Amount for
(c)(b)(a)
Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165
Operation 166
(907) Supervision 167
(908) Customer Assistance Expenses 168 25,895,701 24,624,682
(909) Informational and Instructional Expenses 169 869,523 880,400
(910) Miscellaneous Customer Service and Informational Expenses 170 178,084 107,115
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 26,943,308 25,612,197
7. SALES EXPENSES 172
Operation 173
(911) Supervision 174
(912) Demonstrating and Selling Expenses 175
(913) Advertising Expenses 176
(916) Miscellaneous Sales Expenses 177
TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178
8. ADMINISTRATIVE AND GENERAL EXPENSES 179
Operation 180
(920) Administrative and General Salaries 181 24,851,565 32,024,875
(921) Office Supplies and Expenses 182 4,477,202 4,229,702
(Less) (922) Administrative Expenses Transferred-Credit 183 135,133 118,479
(923) Outside Services Employed 184 11,883,975 9,631,716
(924) Property Insurance 185 1,367,671 1,313,970
(925) Injuries and Damages 186 3,666,296 3,473,339
(926) Employee Pensions and Benefits 187 2,096,877 1,594,960
(927) Franchise Requirements 188 3,775 3,927
(928) Regulatory Commission Expenses 189 6,081,192 6,138,496
(929) (Less) Duplicate Charges-Cr. 190
(930.1) General Advertising Expenses 191 274 2,207
(930.2) Miscellaneous General Expenses 192 3,222,988 3,633,056
(931) Rents 193 873,738 1,017,563
TOTAL Operation (Enter Total of lines 181 thru 193) 194 58,390,420 62,945,332
Maintenance 195
(935) Maintenance of General Plant 196 9,552,147 10,677,749
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 67,942,567 73,623,081
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 635,399,996 617,386,545
FERC FORM NO. 1 (ED. 12-93)Page 323

ICNU_DR_118 Attachment A

Page 152 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
ATCO Power Canada Ltd.WSPPSF 1
BP Energy Company WSPPSF 2
Black Hills Power, Inc.WSPPSF 3
Bonneville Power Administration WNP#3 Agr.LF 4
Bonneville Power Administration WSPPSF 5
Bonneville Power Administration NWPPLF 6
Bonneville Power Administration Tariff 8LF 7
Bonneville Power Administration BPA OATTOS 8
Bonneville Power Administration BPA OATTLF 9
Calpine Energy Services LP WSPPSF 10
Cargill Power Markets WSPPSF 11
City of Spokane PURPALU 12
City of Spokane PURPAIU 13
Chelan County PUD Rocky ReachIU 14
FERC FORM NO. 1 (ED. 12-90)Page 326
Total

ICNU_DR_118 Attachment A

Page 153 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
2,700 2,700 1 125
116,200 116,200 2 2,800
77,950 77,950 3 2,200
14,160,758 14,160,758 4 343,584
3,232,779 3,232,779 5 158,155
6,056 6,056 6 233
535,965 535,965 7 18,408
61,661 61,661 8
48,577 166,877 215,454 9 2,080
726,300 726,300 10 22,664
527,608 527,608 11 17,408
2,293,742 2,293,742 12 45,476
5,003,151 5,003,151 13 110,119
14 -19,576
FERC FORM NO. 1 (ED. 12-90)Page 327
5,080,211 523,891 525,354 14,797,465 120,669,648 37,220,894 172,688,007

ICNU_DR_118 Attachment A

Page 154 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Chelan County PUD WSPPSF 1
Chelan County PUD NWPPLF 2
Chelan County PUD Chelan SysIU 3
Citigroup Energy WSPPSF 4
Clark County PUD No. 1 WSPPSF 5
Clatskanie PUD WSPPSF 6
Clearwater Paper Corporation PURPAIU 7
Community Solar PURPALU 8
Douglas County PUD No. 1 WellsLU 9
Douglas County PUD No. 1 Wells SettlementLU 10
Douglas County PUD No. 1 WellsIF 11
Douglas County PUD No. 1 WSPPSF 12
Douglas County PUD No. 1 NWPPLF 13
Douglas County PUD No. 1 305EX 14
FERC FORM NO. 1 (ED. 12-90)Page 326.1
Total

ICNU_DR_118 Attachment A

Page 155 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
294,800 294,800 1 10,928
399 399 2 14
13,646,616 13,646,616 3 367,623
6,780 6,780 4 400
103,437 103,437 5 5,946
20,755 20,755 6 920
550 550 7
4,794 4,794 8
1,795,072 1,795,072 9 78,793
1,122,617 1,122,617 10 33,318
1,150,399 1,150,399 11 106,169
705,154 705,154 12 29,770
122 122 13 4
75,036 75,036 1,056,000 -356 1,055,644 14
FERC FORM NO. 1 (ED. 12-90)Page 327.1
5,080,211 523,891 525,354 14,797,465 120,669,648 37,220,894 172,688,007

ICNU_DR_118 Attachment A

Page 156 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
EDF Trading No America WSPPSF 1
Energy America, LLC WSPPSF 2
Energy Keepers, Inc.WSPPSF 3
Eugene Water & Electric Board WSPPSF 4
Exelon Generation Company, LLC WSPPSF 5
Ford Hydro Limited Partnership PURPALU 6
Grant County PUD No. 2 Priest RapidsLU 7
Grant County PUD No. 2 WSPPSF 8
Grant County PUD No. 2 NWPPLF 9
Grant County PUD No. 2 FERC #104EX 10
Grant County PUD No. 2 WSPPSF 11
Gridforce Energy Management, LLC NWPPSF 12
Hydro Technology Systems PURPAIU 13
Iberdrola Renewables LLC WSPPSF 14
FERC FORM NO. 1 (ED. 12-90)Page 326.2
Total

ICNU_DR_118 Attachment A

Page 157 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
820,801 820,801 1 23,104
64,960 64,960 2 1,120
38,823 38,823 3 2,065
173,204 173,204 4 7,174
564,333 564,333 5 21,116
231,039 231,039 6 2,992
7,410,934 7,410,934 7 318,181
272,540 272,540 8 13,808
530 530 9 19
-26,033 -26,033 10
450 450 11
147 147 12 5
333,215 333,215 13 7,619
2,631,107 2,631,107 14 110,095
FERC FORM NO. 1 (ED. 12-90)Page 327.2
5,080,211 523,891 525,354 14,797,465 120,669,648 37,220,894 172,688,007

ICNU_DR_118 Attachment A

Page 158 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Idaho County Power & Light PURPALU 1
Idaho Power Company WSPPSF 2
Idaho Power Company - Balancing WSPPSF 3
Inland Power & Light Company 208RQ 4
J. Aron & Company WSPPSF 5
Jim White PURPALU 6
J P Morgan Ventures Energy LLC WSPPSF 7
Kootenai Electric Cooperative Tariff 8LF 8
Macquarie Energy LLC WSPPSF 9
Mizuho Securities USA, Inc.ISDASF 10
Morgan Stanley Capital Group WSPPSF 11
SG Americas Securities, LLC ISDASF 12
NextEra Energy Power Marketing LLC WSPPSF 13
NorthWestern Energy LLC WSPPSF 14
FERC FORM NO. 1 (ED. 12-90)Page 326.3
Total

ICNU_DR_118 Attachment A

Page 159 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
162,116 162,116 1 3,175
1,175,778 1,175,778 2 71,080
53,400 53,400 3 1,700
6,491 6,491 4 93
20,200 20,200 5 800
100,917 100,917 6 1,009
73,220 73,220 7 4,000
38,320 38,320 8 1,584
1,438,569 1,438,569 9 45,716
13,378,059 13,378,059 10
1,360,757 1,360,757 11 54,454
22,007,926 22,007,926 12
35,223 35,223 13 2,040
963,784 963,784 14 51,014
FERC FORM NO. 1 (ED. 12-90)Page 327.3
5,080,211 523,891 525,354 14,797,465 120,669,648 37,220,894 172,688,007

ICNU_DR_118 Attachment A

Page 160 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
NorthWestern Energy LLC NWPPLF 1
Okanogan County PUD No. 1 WSPPSF 2
PacifiCorp WSPPSF 3
PacifiCorp NWPPLF 4
Palouse Wind LLC PPALU 5
Pend Oreille County PUD No. 1 Pend O'SF 6
Pend Oreille County PUD No. 1 Pend O'IF 7
Phillips Ranch PURPALU 8
Portland General Electric Company 304EX 9
Portland General Electric Company 178EX 10
Portland General Electric Company WSPPSF 11
Portland General Electric Company NWPPLF 12
Powerex Corp WSPPSF 13
Public Service Company of Colorado WSPPSF 14
FERC FORM NO. 1 (ED. 12-90)Page 326.4
Total

ICNU_DR_118 Attachment A

Page 161 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
795 795 1 28
189,949 189,949 2 10,165
969,924 969,924 3 46,813
1,422 1,422 4 52
16,759,512 16,759,512 5 293,563
5,463,600 5,463,600 6 268,168
318,190 318,190 7 14,769
2,613 2,613 8 53
440,265 439,113 9
9,948 9,742 -1,781 -1,781 10
191,662 191,662 11 8,732
1,212 1,212 12 43
4,637,372 4,637,372 13 137,333
8,500 8,500 14 400
FERC FORM NO. 1 (ED. 12-90)Page 327.4
5,080,211 523,891 525,354 14,797,465 120,669,648 37,220,894 172,688,007

ICNU_DR_118 Attachment A

Page 162 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Puget Sound Energy WSPPSF 1
Puget Sound Energy NWPPLF 2
Rainbow Energy Marketing Corp WSPPSF 3
Rathdrum Power LLC LancasterLF 4
Sacramento Municipal Utility District WSPPSF 5
Seattle City Light WSPPSF 6
Seattle City Light NWPPLF 7
Sheep Creek Hydro PURPALU 8
Shell Energy WSPPSF 9
Snohomish County PUD No. 1 WSPPSF 10
Southern California Edison Company WSPPSF 11
Sovereign Power SovereignLF 12
Spokane County PURPALU 13
Stimson Lumber PURPAIU 14
FERC FORM NO. 1 (ED. 12-90)Page 326.5
Total

ICNU_DR_118 Attachment A

Page 163 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1,523,185 1,523,185 1 59,285
1,376 1,376 2 49
71,652 71,652 3 3,957
25,994,755 25,994,755 4 1,525,436
7,500 7,500 5 400
810,920 810,920 6 33,970
608 608 7 22
342,229 342,229 8 8,426
1,749,085 1,749,085 9 72,873
1,082,205 1,082,205 10 59,523
47,250 47,250 11 3,450
163,163 163,163 12 7,760
55,501 55,501 13 919
1,367,174 1,367,174 14 29,412
FERC FORM NO. 1 (ED. 12-90)Page 327.5
5,080,211 523,891 525,354 14,797,465 120,669,648 37,220,894 172,688,007

ICNU_DR_118 Attachment A

Page 164 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate
Monthly Billing
Average
(d)
Statistical
cation
Classifi- Schedule or
Tariff Number Demand (MW)
(e)(f)
(Footnote Affiliations)
Actual Demand (MW)
Average Average
Monthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the
supplier includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must
be the same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for
economic reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency
energy from third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service
which meets the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract
defined as the earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Tacoma Power WSPPSF 1
Tacoma Power NWPPLF 2
Talen Energy Marketing WSPPSF 3
Tenaska Power Services Company WSPPSF 4
The Energy Authority WSPPSF 5
TransAlta Energy Marketing WSPPSF 6
IntraCompany Generation Services OATTOS 7
Other - Inadvertent Interchange EX 8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 326.6
Total

ICNU_DR_118 Attachment A

Page 165 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($)($)($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered
(l)(m)
of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter
the monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the
average monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly
NCP demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand
during the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f)
must be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1,025,401 1,025,401 1 46,389
326 326 2 12
4,471,243 4,471,243 3 236,026
3,279 3,279 4 449
919,648 919,648 5 44,448
2,675,723 2,675,723 6 85,762
1,634,541 1,634,541 7
105 8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 327.6
5,080,211 523,891 525,354 14,797,465 120,669,648 37,220,894 172,688,007

ICNU_DR_118 Attachment A

Page 166 of 235
Schedule Page: 326 Line No.: 4 Column: a
BPA Contract Terminates June 30, 2019
Schedule Page: 326 Line No.: 6 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326 Line No.: 7 Column: a
BPA Contract Terminates September 30, 2028
Schedule Page: 326 Line No.: 8 Column: a
Ancillary Services - Spinning & Supplemental
Schedule Page: 326 Line No.: 9 Column: a
BPA Contract Terminates January 01,2036
Schedule Page: 326 Line No.: 9 Column: l
Non Monetary
Schedule Page: 326.1 Line No.: 2 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.1 Line No.: 13 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.1 Line No.: 14 Column: l
Non Monetary
Schedule Page: 326.2 Line No.: 9 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.2 Line No.: 10 Column: l
Non Monetary
Schedule Page: 326.2 Line No.: 12 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.3 Line No.: 4 Column: a
Service to Deer Lake from Inland Power and Light. No demand charges associated with the
agreement.
Schedule Page: 326.3 Line No.: 8 Column: a
Kootenai Contract Terminates March 31, 2019
Schedule Page: 326.3 Line No.: 10 Column: a
Financial SWAP
Schedule Page: 326.3 Line No.: 12 Column: a
Financial SWAP - Formerly known as Newedge USA, LLC
Schedule Page: 326.4 Line No.: 1 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.4 Line No.: 4 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.4 Line No.: 10 Column: l
Non Monetary
Schedule Page: 326.4 Line No.: 12 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.5 Line No.: 2 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.5 Line No.: 7 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.5 Line No.: 12 Column: a
Sovereign Contract Terminates September 30, 2019
Schedule Page: 326.6 Line No.: 2 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.6 Line No.: 3 Column: a
Formerly PPL Energy Plus
Schedule Page: 326.6 Line No.: 7 Column: a
Ancillary Services
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 167 of 235

This Page Intentionally Left Blank

ICNU_DR_118 Attachment A

Page 168 of 235
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016 2015/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
PacifiCorp PacifiCorp PacifiCorp LFP 1
Seattle City Light Seattle City Light Grant County PUD LFP 2
Tacoma Power Tacoma Power Grant County PUD LFP 3
Grant County PUD Grant County PUD Grant County PUD OS 4
Spokane Tribe of Indians Bonneville Power Administration Spokane Tribe of Indians LFP 5
East Greenacres Irrigation District Bonneville Power Administration East Greenacres Irrigation Distri LFP 6
Consolidated Irrigation District Bonneville Power Administration Consolidated Irrigation District LFP 7
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO 8
City of Spokane City of Spokane Avista Corporation OS 9
Stimpson Plummer Avista Corporation OS 10
Hydro Tech Industries Meyers Falls Avista Corporation OS 11
First Wind Energy Marketing Palouse Wind Avista Corporation OS 12
Deep Creek Hydro Deep Creek Avista Corporation OS 13
Bonneville Power Administration Avista Corporation Bonneville Power Administration OS 14
Shell Energy North America (US) LP Bonneville Power Administration Idaho Power Company SFP 15
Morgan Stanley Capital Group Avista Corporation Bonneville Power Administration SFP 16
Morgan Stanley Capital Group Avista Corporation Idaho Power Company SFP 17
Morgan Stanley Capital Group Avista Corporation Northwestern Montana SFP 18
Morgan Stanley Capital Group Bonneville Power Administration Idaho Power Company SFP 19
Morgan Stanley Capital Group Bonneville Power Administration Northwestern Montana SFP 20
Morgan Stanley Capital Group Northwestern Montana Avista Corporation SFP 21
Morgan Stanley Capital Group Northwestern Montana Bonneville Power Administration SFP 22
Morgan Stanley Capital Group Northwestern Montana Chelan County PUD SFP 23
Morgan Stanley Capital Group Northwestern Montana Idaho Power Company SFP 24
Morgan Stanley Capital Group Northwestern Montana Grant County PUD SFP 25
Morgan Stanley Capital Group Northwestern Montana Pacificorp SFP 26
Morgan Stanley Capital Group Northwestern Montana Portland General Electric SFP 27
Morgan Stanley Capital Group Pacificorp Idaho Power Company SFP 28
Morgan Stanley Capital Group Puget Sound Energy Idaho Power Company SFP 29
Morgan Stanley Capital Group Grant County PUD Idaho Power Company SFP 30
Morgan Stanley Capital Group Grant County PUD Northwestern Montana SFP 31
Morgan Stanley Capital Group Idaho Power Company Northwestern Montana SFP 32
Morgan Stanley Capital Group Chelan County PUD Idaho Power Company SFP 33
Morgan Stanley Capital Group Chelan County PUD Northwestern Montana SFP 34
FERC FORM NO. 1 (ED. 12-90)Page 328
TOTAL

ICNU_DR_118 Attachment A

Page 169 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt Hours
Received(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
Dry Creek Walla WallFERC No. 182 Dry Gulch 20 54,907 54,907 1
Chelan-Stratford 115FERC Trf No. 8 Stratford 115kV SS 242,714 242,714 2
Chelan-Stratford 115FERC Trf No. 8 Stratford 115kV SS 242,699 242,699 3
Stratford SubstationFERC No. 104 Coulee Cy/Wilson Crk 25 93,834 93,834 4
WestsideFERC Trf No. 8 Little Falls 3 3,551 3,551 5
Bell SubstationFERC Trf No. 8 Post Falls 3 4,105 4,105 6
Bell SubstationFERC Trf No. 8 BKR/OPT/EFM/LIB 3 7,726 7,726 7
FERC Trf No. 8 1,826,188 1,826,188 8
Sunset-Westside 115kFERC No. 155 Westside 9
AVA SystFERC Trf No. 8 AVA Syst 10
FERC Trf No. 8 11
FERC Trf No. 8 12
FERC Trf No. 8 13
FERC Trf No. 8 14
FERC Trf No. 8 12,537 12,537 15
FERC Trf No. 8 20 20 16
FERC Trf No. 8 260 260 17
FERC Trf No. 8 10 10 18
FERC Trf No. 8 44,676 44,676 19
FERC Trf No. 8 117 117 20
FERC Trf No. 8 35 35 21
FERC Trf No. 8 94,626 94,626 22
FERC Trf No. 8 3,016 3,016 23
FERC Trf No. 8 213,418 213,418 24
FERC Trf No. 8 16,405 16,405 25
FERC Trf No. 8 4,276 4,276 26
FERC Trf No. 8 1,072 1,072 27
FERC Trf No. 8 2,151 2,151 28
FERC Trf No. 8 1,212 1,212 29
FERC Trf No. 8 6,018 6,018 30
FERC Trf No. 8 312 312 31
FERC Trf No. 8 57 57 32
FERC Trf No. 8 40,039 40,039 33
FERC Trf No. 8 35,432 35,432 34
FERC FORM NO. 1 (ED. 12-90)Page 329
57 3,275,367 3,275,367

ICNU_DR_118 Attachment A

Page 170 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
245,458 245,458 1
145,032 182,148 37,116 2
216,000 253,116 37,116 3
28,482 28,482 4
33,612 33,612 5
15,529 15,529 6
38,837 38,837 7
7,737,824 7,737,824 8
27,973 27,973 9
9,480 9,480 10
6,120 6,120 11
200,000 200,000 12
603 603 13
3,192,000 3,192,000 14
49,842 49,842 15
118 118 16
1,109 1,109 17
50 50 18
183,970 183,970 19
617 617 20
139 139 21
481,419 481,419 22
12,298 12,298 23
962,255 962,255 24
74,511 74,511 25
17,990 17,990 26
5,323 5,323 27
8,069 8,069 28
4,854 4,854 29
25,429 25,429 30
1,556 1,556 31
335 335 32
162,980 162,980 33
180,202 180,202 34
FERC FORM NO. 1 (ED. 12-90)Page 330
12,548,555 16,137,345 3,588,790 0

ICNU_DR_118 Attachment A

Page 171 of 235
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016 2015/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Morgan Stanley Capital Group Portland General Electric Idaho Power Company SFP 1
Portland General Electric Northwestern Montana Bonneville Power Administration SFP 2
Powerex Bonneville Power Administration Idaho Power Company SFP 3
Powerex Puget Sound Energy Idaho Power Company SFP 4
Powerex Grant County PUD Idaho Power Company SFP 5
Powerex Chelan County PUD Idaho Power Company SFP 6
Pacificorp Pacificorp Bonneville Power Administration SFP 7
Pacificorp Pacificorp Idaho Power Company SFP 8
Idaho Power Company LSE Avista Corporation Bonneville Power Administration SFP 9
Idaho Power Company LSE Avista Corporation Idaho Power Company SFP 10
Idaho Power Company LSE Bonneville Power Administration Idaho Power Company SFP 11
Idaho Power Company LSE Bonneville Power Administration Northwestern Montana SFP 12
Idaho Power Company LSE Northwestern Montana Idaho Power Company SFP 13
Kootenai Electric Avista Corporation Idaho Power Company SFP 14
Douglas County PUD Bonneville Power Administration Avista Corporation SFP 15
Bonneville Power Administration Bonneville Power Administration Idaho Power Company NF 16
Shell Energy North America (US) LP Bonneville Power Administration Idaho Power Company NF 17
Shell Energy North America (US) LP Bonneville Power Administration Northwestern Montana NF 18
Shell Energy North America (US) LP Northwestern Montana Bonneville Power Administration NF 19
Shell Energy North America (US) LP Northwestern Montana Idaho Power Company NF 20
Shell Energy North America (US) LP Northwestern Montana Grant County PUD NF 21
PPL Energy Plus Northwestern Montana Bonneville Power Administration NF 22
PPL Energy Plus Northwestern Montana Idaho Power Company NF 23
Morgan Stanley Capital Group Avista Corporation Chelan County PUD NF 24
Morgan Stanley Capital Group Avista Corporation Idaho Power Company NF 25
Morgan Stanley Capital Group Bonneville Power Administration Bonneville Power Administration NF 26
Morgan Stanley Capital Group Bonneville Power Administration Idaho Power Company NF 27
Morgan Stanley Capital Group Bonneville Power Administration Northwestern Montana NF 28
Morgan Stanley Capital Group Northwestern Montana Bonneville Power Administration NF 29
Morgan Stanley Capital Group Northwestern Montana Chelan County PUD NF 30
Morgan Stanley Capital Group Northwestern Montana Idaho Power Company NF 31
Morgan Stanley Capital Group Northwestern Montana Portland General Electric NF 32
Morgan Stanley Capital Group Northwestern Montana Grant County PUD NF 33
Morgan Stanley Capital Group Northwestern Montana Puget Sound Energy NF 34
FERC FORM NO. 1 (ED. 12-90)Page 328.1
TOTAL

ICNU_DR_118 Attachment A

Page 172 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt Hours
Received(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Trf No. 8 40 40 1
FERC Trf No. 8 12,574 12,574 2
FERC Trf No. 8 10,909 10,909 3
FERC Trf No. 8 296 296 4
FERC Trf No. 8 205 205 5
FERC Trf No. 8 1,257 1,257 6
FERC Trf No. 8 1,727 1,727 7
FERC Trf No. 8 8,481 8,481 8
FERC Trf No. 8 10,776 10,776 9
FERC Trf No. 8 800 800 10
FERC Trf No. 8 136,566 136,566 11
FERC Trf No. 8 350 350 12
FERC Trf No. 8 750 750 13
FERC Trf No. 8 3 11,749 11,749 14
FERC Trf No. 8 1,866 1,866 15
FERC Trf No. 8 10,271 10,271 16
FERC Trf No. 8 1,004 1,004 17
FERC Trf No. 8 20 20 18
FERC Trf No. 8 139 139 19
FERC Trf No. 8 68 68 20
FERC Trf No. 8 157 157 21
FERC Trf No. 8 77 77 22
FERC Trf No. 8 1,178 1,178 23
FERC Trf No. 8 150 150 24
FERC Trf No. 8 549 549 25
FERC Trf No. 8 123 123 26
FERC Trf No. 8 5,095 5,095 27
FERC Trf No. 8 514 514 28
FERC Trf No. 8 17,204 17,204 29
FERC Trf No. 8 5,547 5,547 30
FERC Trf No.8 7,157 7,157 31
FERC Trf No. 8 20 20 32
FERC Trf No. 8 5,634 5,634 33
FERC Trf No. 8 54 54 34
FERC FORM NO. 1 (ED. 12-90)Page 329.1
57 3,275,367 3,275,367

ICNU_DR_118 Attachment A

Page 173 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
188 188 1
64,610 64,610 2
43,750 43,750 3
1,197 1,197 4
829 829 5
5,082 5,082 6
35,147 35,147 7
128,685 128,685 8
60,104 60,104 9
3,920 3,920 10
732,895 732,895 11
2,025 2,025 12
3,669 3,669 13
72,000 88,092 16,092 14
9,692 9,888 196 15
66,020 66,020 16
6,105 6,105 17
201 201 18
951 951 19
426 426 20
983 983 21
462 462 22
6,797 6,797 23
1,026 1,026 24
3,349 3,349 25
966 966 26
32,409 32,409 27
3,266 3,266 28
110,451 110,451 29
36,120 36,120 30
47,035 47,035 31
134 134 32
36,807 36,807 33
351 351 34
FERC FORM NO. 1 (ED. 12-90)Page 330.1
12,548,555 16,137,345 3,588,790 0

ICNU_DR_118 Attachment A

Page 174 of 235
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016 2015/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualifying facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General Instruction for definitions of codes.
Morgan Stanley Capital Group Grant County PUD Idaho Power Company NF 1
Morgan Stanley Capital Group Grant County PUD Northwestern Montana NF 2
Morgan Stanley Capital Group Idaho Power Company Bonneville Power Administration NF 3
Morgan Stanley Capital Group Chelan County PUD Idaho Power Company NF 4
Morgan Stanley Capital Group Chelan County PUD Northwestern Montana NF 5
Northwestern Energy Northwestern Montana Bonneville Power Administration NF 6
Northwestern Energy Northwestern Montana Idaho Power Company NF 7
Portland General Electric Northwestern Montana Bonneville Power Administration NF 8
Portland General Electric Northwestern Montana Portland General Electric NF 9
Iberdrola Renewables, LLC Bonneville Power Administration Idaho Power Company NF 10
Puget Sound Energy Bonneville Power Administration Northwestern Montana NF 11
Puget Sound Energy Northwestern Montana Bonneville Power Administration NF 12
Powerex Bonneville Power Administration Idaho Power Company NF 13
Powerex Northwestern Montana Bonneville Power Administration NF 14
Powerex Northwestern Montana Puget Sound Energy NF 15
Powerex Grant County PUD Idaho Power Company NF 16
Powerex Chelan County PUD Idaho Power Company NF 17
Transalta Energy Marketing Bonneville Power Administration Idaho Power Company NF 18
The Energy Authority Northwestern Montana Bonneville Power Adminstration NF 19
Pacificorp Pacificorp Bonneville Power Administration NF 20
Pacificorp Pacificorp Idaho Power Company NF 21
Pacificorp Idaho Power Company Bonneville Power Administration NF 22
Bonneville Power Administration Bonneville Power Administration Idaho Power Company NF 23
Idaho Power Company LSE Bonneville Power Administration Idaho Power Company NF 24
Idaho Power Company LSE Northwestern Montana Idaho Power Company NF 25
Idaho Power Company LSE Pacificorp Idaho Power Company NF 26
Seattle City Light Avista Corporation Grant County PUD NF 27
Tacoma Power Avista Corporation Grant County PUD NF 28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90)Page 328.2
TOTAL

ICNU_DR_118 Attachment A

Page 175 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt Hours
Received(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Trf No. 8 834 834 1
FERC Trf No. 8 148 148 2
FERC Trf No. 8 38 38 3
FERC Trf No. 8 484 484 4
FERC Trf No. 8 259 259 5
FERC Trf No. 8 404 404 6
FERC Trf No. 8 400 400 7
FERC Trf No. 8 2,460 2,460 8
FERC Trf No. 8 154 154 9
FERC Trf No. 8 1,802 1,802 10
FERC Trf No. 8 11
FERC Trf No. 8 12
FERC Trf No. 8 10,568 10,568 13
FERC Trf No. 8 76 76 14
FERC Trf No. 8 65 65 15
FERC Trf No. 8 354 354 16
FERC Trf No. 8 61 61 17
FERC Trf No. 8 50 50 18
FERC Trf No. 8 25 25 19
FERC Trf No. 8 2,027 2,027 20
FERC Trf No. 8 2,578 2,578 21
FERC Trf No. 8 1,637 1,637 22
FERC Trf No. 8 12,564 12,564 23
FERC Trf No. 8 32,068 32,068 24
FERC Trf No. 8 300 300 25
FERC Trf No. 8 1,291 1,291 26
FERC Trf No. 8 27
FERC Trf No. 8 28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90)Page 329.2
57 3,275,367 3,275,367

ICNU_DR_118 Attachment A

Page 176 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the
amount of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including
out of period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total
charge shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
5,057 5,057 1
952 952 2
266 266 3
3,120 3,120 4
1,639 1,639 5
3,075 3,075 6
2,308 2,308 7
14,194 14,194 8
889 889 9
10,911 10,911 10
6 6 11
2,020 2,020 12
66,527 66,527 13
461 461 14
381 381 15
3,011 3,011 16
511 511 17
289 289 18
144 144 19
17,068 17,068 20
16,963 16,963 21
12,481 12,481 22
79,447 79,447 23
205,105 205,105 24
1,731 1,731 25
7,785 7,785 26
1,408 1,408 27
1,408 1,408 28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90)Page 330.2
12,548,555 16,137,345 3,588,790 0

ICNU_DR_118 Attachment A

Page 177 of 235
Schedule Page: 328 Line No.: 2 Column: m
Use of facilities.
Schedule Page: 328 Line No.: 3 Column: m
Use of facilities.
Schedule Page: 328 Line No.: 4 Column: m
Use of facilities.
Schedule Page: 328 Line No.: 5 Column: m
Long term firm transmission and ancillary services.
Schedule Page: 328 Line No.: 9 Column: m
Use of facilities.
Schedule Page: 328 Line No.: 10 Column: m
Use of facilities.
Schedule Page: 328 Line No.: 11 Column: m
Use of facilities.
Schedule Page: 328 Line No.: 12 Column: m
Deferral fee for long term firm service agreement.
Schedule Page: 328 Line No.: 13 Column: m
Use of facilities.
Schedule Page: 328 Line No.: 14 Column: m
Parallel Capacity Support Agreement
Schedule Page: 328.1 Line No.: 14 Column: m
Ancillary services.
Schedule Page: 328.1 Line No.: 15 Column: m
Regulation frequency and response charge.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 178 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Name of Company or Public
(d)(c)(a)
Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)
(e)
EnergyCharges
(f)
($)
OtherCharges($)
(g)($)
Total Cost of
Transmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification
(b)
LFP 1,497,581 1,497,581Bonneville Power Admin 1
LFP 12,158,455 1,863,639 10,294,816Bonneville Power Admin 2
LFP 901,424 901,424Bonneville Power Admin 3
OS 24,360 24,360Bonneville Power Admin 4
FNS 1,353,746 203,827 1,149,919Bonneville Power Admin 5
NF 10,900 10,900 2,180 2,180Bonneville Power Admin 6
NF 30 30 30 30Benton County PUD No. 1 7
NF 20 20 20 20Grays Harbor County PUD 8
NF 44 44 35 35Klickitat PUD 9
LFP 45,222 45,222Kootenai Electric Coop 10
LFP 134,614 134,614Northern Lights 11
SFP 288,015 23,252 264,763NorthWestern Energy 12
NF 194,954 194,954 45,024 45,024NorthWestern Energy 13
LFP 642,989 14,989 628,000Portland General Elec 14
NF 2,685 2,685 1,887 1,887Portland General Elec 15
NF 19,301 19,301 16,791 16,791Seattle City Light 16
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332
116,630 116,630 14,916,339 343,485 2,130,067 17,389,891TOTAL

ICNU_DR_118 Attachment A

Page 179 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Name of Company or Public
(d)(c)(a)
Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)
(e)
EnergyCharges
(f)
($)
OtherCharges($)
(g)($)
Total Cost of
Transmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the
demand charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all
other charges on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all
components of the amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement,
including the amount and type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification
(b)
NF 8,930 8,930 6,376 6,376Snohomish County PUD 1
NF 106,621 106,621 44,287 44,287Talen Energy Marketing 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.1
116,630 116,630 14,916,339 343,485 2,130,067 17,389,891TOTAL

ICNU_DR_118 Attachment A

Page 180 of 235
Schedule Page: 332 Line No.: 2 Column: g
Ancillary Services
Schedule Page: 332 Line No.: 4 Column: g
Use of Facilities
Schedule Page: 332 Line No.: 5 Column: g
Ancillary Services
Schedule Page: 332 Line No.: 12 Column: g
Ancillary Services
Schedule Page: 332 Line No.: 14 Column: g
Ancillary Services
Schedule Page: 332.1 Line No.: 2 Column: a
Formerly PPL Energy Plus, LLC. Name changed 06/02/2015.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 181 of 235
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Avista Corporation X 04/15/2016 2015/Q4
Line Description Amount
(b)(a)No.
553,624Industry Association Dues 1
Nuclear Power Research Expenses 2
Other Experimental and General Research Expenses 3
359,013Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4
674,874Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5
115,432Community Relations 6
998,347Director Fees and expenses 7
22,744Educational & Informational expenses 8
173,144Rating agency fees 9
243,401Aircraft operations and fees 10
492,477Other Misc general expenses >5000 11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
3,633,056
FERC FORM NO. 1 (ED. 12-94)Page 335
46 TOTAL

ICNU_DR_118 Attachment A

Page 182 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Functional Classification Depreciation
(d)(b)(a)
Amortization of
Total
(Except amortization of aquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Expense
(Account 403)
Limited Term
Electric Plant Amortization ofOther Electric
Plant (Acc 405)
(e)(f)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant
included in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at
the bottom of section C the amounts and nature of the provisions and the plant items to which related.
(Account 404)
(c)
DepreciationExpense for Asset
Retirement Costs
(Account 403.1)
2,658,971 2,658,971 1 Intangible Plant
7,814,106 7,814,106 2 Steam Production Plant
3 Nuclear Production Plant
8,819,905 8,819,905 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
11,859,915 9,409,884 2,450,031 6 Other Production Plant
11,040,923 11,040,923 7 Transmission Plant
40,699,644 40,699,644 8 Distribution Plant
9 Regional Transmission and Market Operation
4,089,389 4,089,389 10 General Plant
25,432,274 14,021,279 11,410,995 11 Common Plant-Electric
112,415,127 95,895,130 16,519,997 12 TOTAL
FERC FORM NO. 1 (REV. 12-03)Page 336
B. Basis for Amortization Charges

ICNU_DR_118 Attachment A

Page 183 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base
(In Thousands)
Estimated
Avg. Service
Life
Net
Salvage
(Percent)
Applied
Depr. rates
Mortality
Curve
Type
Average
Remaining
Life(f)(g)(Percent)
STEAM PLANT 12
Colstrip No. 3 13
70.00 -10.00 1.56 22.10S1.5311 51,651 14
60.00 -10.00 1.93 21.50R1312 76,665 15
313 3 16
40.00 -5.00 2.79 19.40R0.5314 26,840 17
50.00 1.73 21.00R3315 9,541 18
53.00 1.46 20.90R2316 9,915 19
Subtotal 174,615 20
21
Colstrip No. 4 22
70.00 -10.00 1.68 23.90S1.5311 51,592 23
60.00 -10.00 2.20 23.30R1312 52,347 24
313 3 25
40.00 -5.00 2.88 20.90R0.5314 13,519 26
50.00 1.88 22.90R3315 6,673 27
53.00 1.62 22.70R2316 4,600 28
Subtotal 128,734 29
30
0Kettle Falls 31
1.45 18.00SQ310 148 32
70.00 -10.00 1.51 17.10S1.5311 28,064 33
60.00 -10.00 1.93 16.70R1312 44,807 34
40.00 -5.00 2.12 14.90R0.5314 14,085 35
50.00 1.56 16.40R3315 10,809 36
53.00 1.74 16.80R2316 2,601 37
Subtotal 100,514 38
39
HYDRO PLANT 40
Cabinet Gorge 41
100.00 2.00 43.20R4330 8,233 42
110.00 -20.00 1.50 51.50R2331 12,662 43
100.00 1.13 47.70R1332 46,720 44
65.00 -10.00 2.04 43.90R1.5333 37,880 45
38.00 -5.00 2.97 19.70R2.5334 6,020 46
65.00 0.38 49.90R1.5335 4,646 47
55.00 1.96 19.00S2336 1,269 48
Subtotal 117,430 49
50
FERC FORM NO. 1 (REV. 12-03)Page 337

ICNU_DR_118 Attachment A

Page 184 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base
(In Thousands)
Estimated
Avg. Service
Life
Net
Salvage
(Percent)
Applied
Depr. rates
Mortality
Curve
Type
Average
Remaining
Life(f)(g)(Percent)
Noxon Rapids 12
100.00 1.80 48.80R4330 30,477 13
110.00 -20.00 1.48 58.40R2331 18,645 14
100.00 1.12 52.60R1332 34,461 15
65.00 -10.00 1.98 47.50R1.5333 88,377 16
38.00 -5.00 2.79 29.50R2.5334 14,907 17
65.00 0.80 53.60R1.5335 3,461 18
55.00 1.89 32.00S2336 247 19
Subtotal 190,575 20
21
Post Falls 22
75.00 2.81 25.20R3330 2,908 23
110.00 -20.00 2.09 45.60R2331 1,956 24
100.00 1.71 44.70R1332 12,788 25
65.00 -10.00 2.42 29.60R1.5333 2,234 26
38.00 -5.00 2.78 18.20R2.5334 718 27
65.00 1.15 42.10R1.5335 223 28
Subtotal 20,827 29
30
Long Lake 31
75.00 4.42 11.00R3330 418 32
110.00 -20.00 1.99 38.90R2331 5,268 33
100.00 1.65 40.00R1332 18,742 34
65.00 -10.00 2.46 33.30R1.5333 8,824 35
38.00 -5.00 2.63 22.50R2.5334 3,002 36
65.00 1.22 39.40R1.5335 542 37
Subtotal 36,796 38
39
Little Falls 40
100.00 3.35 24.40R4330 4,217 41
110.00 -20.00 1.94 42.30R2331 1,943 42
100.00 1.72 43.60R1332 5,065 43
65.00 -10.00 2.40 33.60R1.5333 3,881 44
38.00 -5.00 2.74 22.20R2.5334 8,648 45
65.00 0.69 40.60R1.5335 238 46
Subtotal 23,992 47
48
Upper Falls 49
100.00 3.66 22.20R4330 64 50
FERC FORM NO. 1 (REV. 12-03)Page 337.1

ICNU_DR_118 Attachment A

Page 185 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base
(In Thousands)
Estimated
Avg. Service
Life
Net
Salvage
(Percent)
Applied
Depr. rates
Mortality
Curve
Type
Average
Remaining
Life(f)(g)(Percent)
110.00 -20.00 1.77 41.40R2331 976 12
100.00 1.85 45.20R1332 7,678 13
65.00 -10.00 2.53 30.00R1.5333 1,186 14
38.00 -5.00 2.81 35.10R2.5334 4,269 15
65.00 1.05 41.20R1.5335 107 16
55.00 1.94 26.20S2336 490 17
Subtotal 14,770 18
19
Nine Mile 20
100.00 2.48 35.90R4330 11 21
110.00 -20.00 1.98 46.50R2331 8,276 22
100.00 1.83 45.10R1332 18,407 23
65.00 -10.00 2.17 40.30R1.5333 14,415 24
38.00 -5.00 2.80 22.50R2.5334 3,339 25
65.00 0.88 41.20R1.5335 276 26
55.00 1.93 36.20S2336 625 27
Subtotal 45,349 28
29
Monroe Street 30
110.00 -20.00 1.71 56.90R2331 11,979 31
100.00 1.39 53.20R1332 9,978 32
65.00 -10.00 1.95 45.50R1.5333 11,031 33
38.00 -5.00 2.82 23.40R2.5334 1,683 34
65.00 1.19 48.30R1.5335 34 35
55.00 1.86 36.60S2336 50 36
Subtotal 34,755 37
38
OTHER PRODUCTION 39
Northeast Turbine 40
55.00 1.64 8.00S4341 744 41
55.00 -10.00 2.93 8.00R3342 31 42
55.00 0.81 8.00S2.5343 9,059 43
45.00 2.50 7.40R1344 2,609 44
20.00 -5.00 12.49 7.90S2345 1,237 45
35.00 2.51 7.80R3346 406 46
Subtotal 14,086 47
48
Rathdrum Turbine 49
55.00 3.12 24.00S4341 3,442 50
FERC FORM NO. 1 (REV. 12-03)Page 337.2

ICNU_DR_118 Attachment A

Page 186 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base
(In Thousands)
Estimated
Avg. Service
Life
Net
Salvage
(Percent)
Applied
Depr. rates
Mortality
Curve
Type
Average
Remaining
Life(f)(g)(Percent)
55.00 -10.00 3.57 23.50R3342 1,696 12
55.00 2.77 23.50S2.5343 5,722 13
45.00 3.77 21.60R1344 48,853 14
20.00 -5.00 5.89 15.20S2345 2,995 15
35.00 2.51 7.80R3346 347 16
Subtotal 63,055 17
18
Kettle Falls CT 19
55.00 -10.00 3.66 17.70R3342 89 20
55.00 3.24 17.80S2.5343 9,071 21
45.00 4.09 16.60R1344 4 22
20.00 -5.00 6.68 11.40S2345 14 23
Subtotal 9,178 24
25
Boulder Park 26
55.00 2.54 31.90S4341 1,205 27
55.00 -10.00 2.62 30.40R3342 116 28
55.00 2.52 30.90S2.5343 57 29
45.00 2.94 26.90R1344 30,611 30
20.00 -5.00 6.03 14.30S2345 646 31
35.00 2.87 26.20R3346 48 32
Subtotal 32,683 33
34
Coyote Springs 2 35
55.00 2.34 32.80S4341 11,402 36
55.00 -10.00 2.72 31.40R3342 19,304 37
45.00 3.00 27.90R1344 125,800 38
20.00 -5.00 6.14 13.40S2345 15,855 39
35.00 2.95 27.40R3346 975 40
Subtotal 173,336 41
42
25.00 5.30 17.90S2.5Solar Power 1,128 43
Subtotal 1,128 44
45
Lancaster 46
55.00 -10.00 3.67 29.40R3342 141 47
45.00 3.70 26.60R1344 209 48
Subtotal 350 49
50
FERC FORM NO. 1 (REV. 12-03)Page 337.3

ICNU_DR_118 Attachment A

Page 187 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base
(In Thousands)
Estimated
Avg. Service
Life
Net
Salvage
(Percent)
Applied
Depr. rates
Mortality
Curve
Type
Average
Remaining
Life(f)(g)(Percent)
TRANSMISSION PLANT 12
75.00 1.30 56.80R4350 18,045 13
60.00 -5.00 1.65 48.00S2352 20,538 14
45.00 -10.00 2.33 33.10R2.5353 243,040 15
70.00 -15.00 1.80 41.00R4354 17,173 16
65.00 -15.00 1.38 54.70R2.5355 198,418 17
65.00 -10.00 1.59 50.20R2.5356 131,685 18
60.00 1.64 51.70R4357 2,987 19
50.00 2.02 35.40S2358 2,342 20
65.00 1.66 39.70R4359 1,967 21
362 22
Subtotal 636,195 23
24
DISTRIBUTION PLANT 25
75.00 1.34 74.40R4360 2,491 26
60.00 -10.00 1.62 47.30R2.5361 20,388 27
45.00 1.97 34.20R1.5362 124,857 28
363 2,354 29
55.00 -25.00 2.31 41.10R2.5364 338,515 30
50.00 -20.00 2.82 32.70R3365 213,577 31
50.00 -25.00 2.71 37.60S2366 98,828 32
28.00 -20.00 5.63 16.80S2367 173,963 33
44.00 -5.00 2.11 33.00R2368 234,114 34
55.00 -40.00 2.70 37.55R4369 151,462 35
15.00 7.65 12.50S2.5370 - AN 157 36
15.00 7.65 12.50S2.5370.2 - ID 22,278 37
35.00 3.39 23.60S0.5370.3 - WA 27,069 38
35.00 -25.00 1.91 26.45R2.5373 18,541 39
35.00 -25.00 3.48 26.80R2.5373.4 26,186 40
373.5 4,651 41
Subtotal 1,459,431 42
43
GENERAL PLANT 44
48.00 -5.00 1.67 39.00S2390.1 7,029 45
5.00 21.28 3.30SQ391.1 9,191 46
25.00 4.58 19.40SQ393 401 47
20.00 4.78 10.20SQ394 3,725 48
15.00 13.73 4.00SQ395 582 49
15.00 2.81 11.70SQ397 61,110 50
FERC FORM NO. 1 (REV. 12-03)Page 337.4

ICNU_DR_118 Attachment A

Page 188 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base
(In Thousands)
Estimated
Avg. Service
Life
Net
Salvage
(Percent)
Applied
Depr. rates
Mortality
Curve
Type
Average
Remaining
Life(f)(g)(Percent)
10.00 13.31 7.00SQ398 81 12
Subtotal 82,119 13
14
MISC POWER 15
15.00 20.00 1.83 13.70L2.5392 5,453 16
16.00 5.00 5.79 11.80S0.5396 2,992 17
Subtotal 8,445 18
19
20
21
22
23
24
25
26
27
28
TOTAL COMPANY 3,368,363 29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03)Page 337.5

ICNU_DR_118 Attachment A

Page 189 of 235

This Page Intentionally Left Blank

ICNU_DR_118 Attachment A

Page 190 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Description Assessed by
(c)(b)(a)
Total Expense forExpenses
of
(d)
(Furnish name of regulatory commission or body the Regulatory
docket or case number and a description of the case)Commission Utility Current Year(b) + (c)
Deferredin Account
182.3 at Beginning of Year
(e)
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Federal Energy Regulatory Commission 1
Charges include annual fee and license fees 2
for the Spokane River Project, the Cabinet 3
Gorge Project and the Noxon Rapids Project. 2,210,963 86,315 2,297,278 4
5
6
7
8
Washington Utilities and Transportation 9
Commission: includes annual fee and various 10
other electric dockets 1,025,044 1,182,202 2,207,246 11
12
Includes annual fee and various other natural 13
gas dockets 328,989 302,117 631,106 14
15
Idaho Public Utilities Commission 16
Includes annual fee and various other electric 17
dockets 619,966 259,840 879,806 18
19
Includes annual fee and various other natural 20
gas dockets 177,604 88,152 265,756 21
22
Public Utility Commission of Oregon 23
Includes annual fees and various other natural 24
gas dockets 598,978 684,324 1,283,302 25
26
Not directly assigned electric 754,166 754,166 27
Not directly assigned natural gas 301,317 301,317 28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96)Page 350
46 TOTAL 4,961,544 3,658,433 8,619,977
ICNU_DR_118 Attachment A

Page 191 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
(j)(i)(f)(k)(l)
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Department AccountNo.(g)
Amount
(h)
Deferred to
Account 182.3
Contra
Account Amount Deferred in Account 182.3
End of Year
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
1
2
3
Electric 4 2,297,278928
5
6
7
8
9
10
Electric 11 2,207,246928
12
13
Gas 14 631,106928
15
16
17
Electric 18 879,806928
19
20
Gas 21 265,756928
22
23
24
Gas 25 1,283,302928
26
Electric 27 754,166928
Gas 28 301,317928
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96)Page 351
46 8,619,977
ICNU_DR_118 Attachment A

Page 192 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Description
(b)(a)
Classification
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally:a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.)
c. Internal combustion or gas turbine (7) Total Cost Incurred
d. Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Power Research Institute
(2) Transmission
Smart Grid Demonstration Grant (Meters) and Battery StorageA 3 Electric - Distribution 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87)Page 352

ICNU_DR_118 Attachment A

Page 193 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
AMOUNTS CHARGED IN CURRENT YEAR
(e)(c)
Costs Incurred Internally
Current Year
Costs Incurred Externally
Current Year
(d)
Account Amount
(f)
Unamortized
Accumulation
(g)
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost Incurred
3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more,
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).
Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D &
D activity.
4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,
listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by
"Est."
7. Report separately research and related testing facilities operated by the respondent.
907,823 1 1,094,930 107 2,002,753
1,785 2108 1,785
3 -1,577 580 -1,577
902 4 10,240 584 11,142
5 1 585 1
-1,950 6 -21,565 587 -23,515
7 -78,937 588 -78,937
2,112 8 -10,248 920 -8,136
822 9 61,508 921 62,330
10 22,462 923 22,462
11 64,180 935 64,180
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87)Page 353

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Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
DISTRIBUTION OF SALARIES AND WAGES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Electric 1
Operation 2
10,679,266Production 3
2,940,353Transmission 4
Regional Market 5
8,288,339Distribution 6
7,465,204Customer Accounts 7
739,691Customer Service and Informational 8
Sales 9
17,886,460Administrative and General 10
47,999,313TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
3,327,489Production 13
1,267,086Transmission 14
Regional Market 15
5,715,670Distribution 16
Administrative and General 17
10,310,245TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
14,006,755Production (Enter Total of lines 3 and 13) 20
4,207,439Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
14,004,009Distribution (Enter Total of lines 6 and 16) 23
7,465,204Customer Accounts (Transcribe from line 7) 24
739,691Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
17,886,460Administrative and General (Enter Total of lines 10 and 17) 27
73,969,738 15,660,180 58,309,558TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28
Gas 29
Operation 30
Production-Manufactured Gas 31
Production-Nat. Gas (Including Expl. and Dev.) 32
798,995Other Gas Supply 33
6,496Storage, LNG Terminaling and Processing 34
Transmission 35
5,089,107Distribution 36
2,912,246Customer Accounts 37
334,840Customer Service and Informational 38
Sales 39
6,856,322Administrative and General 40
15,998,006TOTAL Operation (Enter Total of lines 31 thru 40) 41
Maintenance 42
Production-Manufactured Gas 43
Production-Natural Gas (Including Exploration and Development) 44
Other Gas Supply 45
Storage, LNG Terminaling and Processing 46
1,142,631Transmission 47
FERC FORM NO. 1 (ED. 12-88)Page 354

ICNU_DR_118 Attachment A

Page 195 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016
2015/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
DISTRIBUTION OF SALARIES AND WAGES (Continued)
3,333,267Distribution 48
Administrative and General 49
4,475,898TOTAL Maint. (Enter Total of lines 43 thru 49) 50
Total Operation and Maintenance 51
Production-Manufactured Gas (Enter Total of lines 31 and 43) 52
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53
798,995Other Gas Supply (Enter Total of lines 33 and 45) 54
6,496Storage, LNG Terminaling and Processing (Total of lines 31 thru 55
1,142,631Transmission (Lines 35 and 47) 56
8,422,374Distribution (Lines 36 and 48) 57
2,912,246Customer Accounts (Line 37) 58
334,840Customer Service and Informational (Line 38) 59
Sales (Line 39) 60
6,856,322Administrative and General (Lines 40 and 49) 61
26,000,566 5,526,662 20,473,904TOTAL Operation and Maint. (Total of lines 52 thru 61) 62
Other Utility Departments 63
Operation and Maintenance 64
99,970,304 21,186,842 78,783,462TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
56,730,278 15,544,342 41,185,936Electric Plant 68
13,110,539 4,768,956 8,341,583Gas Plant 69
Other (provide details in footnote): 70
69,840,817 20,313,298 49,527,519TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
2,495,856 520,972 1,974,884Electric Plant 73
147,973 30,887 117,086Gas Plant 74
Other (provide details in footnote): 75
2,643,829 551,859 2,091,970TOTAL Plant Removal (Total of lines 73 thru 75) 76
3,466,972 -42,052,019 45,518,991Other Accounts (Specify, provide details in footnote): 77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
3,466,972 -42,052,019 45,518,991TOTAL Other Accounts 95
175,921,922 -20 175,921,942TOTAL SALARIES AND WAGES 96
FERC FORM NO. 1 (ED. 12-88)Page 355

ICNU_DR_118 Attachment A

Page 196 of 235
Schedule Page: 354 Line No.: 78 Column: a
Other Accounts (Specify):
Stores Expense (163)2,195,926 (2,195,926)0
Preliminary Survey and Investigation (183)13,527 13,527
Small Tool Expense (184)5,455,934 (5,455,934)0
Miscellaneous Deferred Debits (186)-133,368 (133,368)
Non-operating Expenses (417)794,429 794,429
RetirementBonus/SERP/HRA Settlement 56,321 56,321
Activities (426)817,562 817,562
Employee Incentive Plan (232380)15,066,609 (15,066,609)0
DSM Tarrif Rider and Payroll Equalization Liability
(242600, 242700)
21,106,603 (19,333,550) 1,773,053
Incentive / Stock Compensation (238000)145,448 145,448
0
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

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Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMMON UTILITY PLANT AND EXPENSES
Avista Corporation X
04/15/2016 2015/Q4
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
1 & 2. Common Plant in service and accumulated provision for depreciation
Acct. No. Description
303 Intangible 161,922,479
389 Land and Land Rights 11,878,408
390 Structures and Improvements 114,103,780
391 Office Furniture and Equipment 64,856,937
392 Transportation Equipment 11,626,030
393 Stores Equipment 3,619,974
394 Tools, Shop & Garage Equipment 12,637,264
395 Laboratory Equipment 402,764
396 Power Operated Equipment 2,077,069
397 Communications Equipment 46,824,705
398 Miscellaneous Equipment 441,025
399 Asset Retirement Cost 0
Total Common Plant 430,390,435
Const. Work in Progress 24,517,878
Total Utility Plant 454,908,313
Acc. Prov. for Dep. & Amort. 98,281,050
Net Utility Plant 356,627,263
3. Common Expenses allocated to Electric and Gas departments:
Allocation to Allocated to Basis of
Acct. No. Description Total Electric Dept Gas Dept Allocation
901 Cust acct/collect 667,208 356,243 310,965 #of cust @ yr end
supervision
902 Meter reading expenses 4,992,196 3,071,299 1,920,897 #of cust @ yr end
903 Cust rec and 15,994,005 8,632,397 7,361,607 #of cust @ yr end
collection expenses
903.90-99A/R misc fees 0 0 0 net direct plant
904 Uncollectible accounts 5,749,995 3,041,287 2,708,708 #of cust @ yr end
905 Misc cust acct expenses 498,461 263,646 234,815 #of cust @ yr end
907 Cust svce & Info exp 0 0 0 #of cust @ yr end
supervision
908 Cust assistance expenses 1,112,613 684,502 428,111 #of cust @ yr end
909 Info & instruct expenses 1,403,010 863,160 539,850 #of cust @ yr end
FERC FORM NO. 1 (ED. 12-87)Page 356
ICNU_DR_118 Attachment A

Page 199 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMMON UTILITY PLANT AND EXPENSES
Avista Corporation X
04/15/2016 2015/Q4
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to
the respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including
explanation of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
910 Misc cust serv & info 202,517 107,115 95,402 #of cust @ yr end
expenses
911 Sales expense -supervision 0 0 0 #of cust @ yr end
912 Demo & selling expenses 0 0 0 #of cust @ yr end
913 Advertising expenses 0 0 0 #of cust @ yr end
916 Misc sales expenses 0 0 0 #of cust @ yr end
920 Admin & gen salaries 42,010,896 30,225,271 11,785,625 four factor
921 Office supplies expenses 5,637,189 4,039,061 1,598,129 four factor
922 Admin expenses tranf-credit 0 0 0 four factor
923 Outside services 12,755,249 9,134,772 3,620,477 four factor
employed
924 Property insurance 1,605,572 1,148,738 456,833 four factor
925 Injuries and damages 6,277,072 4,608,044 1,669,028 four factor
926 Employee pensions 67,803,755 48,535,786 19,267,969 four factor
& benefits
927 Franchise requirement 0 0 0 four factor
928 Regulatory commission 2,341,516 1,768,119 573,397 four factor
expenses
929 Duplicate charges-credit 0 0 0 four factor
930.1 General advertising expenses 3,084 2,207 878 four factor
930.2 Misc general expenses 3,962,261 2,871,244 1,091,017 four factor
931 Rents 1,285,637 939,160 346,477 four factor
935 Maint of general plant 12,542,544 9,104,645 3,437,899 four factor
403 Depreciation 19,475,518 14,021,279 5,454,239 four factor
404 Amort of LTD term plant 15,944,715 11,410,995 4,533,720 four factor
Note 1: The four factor allocator is made up of 25 percent each of customer counts, direct labor, direct
O&M & Net direct plant
4. Letters of approval received from staffs of State Regulatory Commissions in 1993
FERC FORM NO. 1 (ED. 12-87)Page 356.1
ICNU_DR_118 Attachment A

Page 200 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
PURCHASES AND SALES OF ANCILLARY SERVICES
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Type of Ancillary Service
(a)
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during
the year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Number of Units
Unit of
Measure Dollars
(b)(c)(d)
Number of Units
Unit of
Measure Dollars
(e)(f)(g)
Usage - Related Billing Determinant Usage - Related Billing Determinant
Amount Purchased for the Year Amount Sold for the Year
200,992MW 644Scheduling, System Control and Dispatch 1
Reactive Supply and Voltage 2
657,679MW 73,566 6,812MW/h 56,765Regulation and Frequency Response 3
2,282,284MW 572Energy Imbalance 4
1,287,759MW/h 84,473 29,206MW/h 1,388Operating Reserve - Spinning 5
764,902MW/h 37,161 29,656MW/h 1,433Operating Reserve - Supplement 6
11,732,252MW 1,312,332 11,732,252MW 1,312,332Other 7
16,724,876 1,508,104 11,998,918 1,372,562Total (Lines 1 thru 7) 8
FERC FORM NO. 1 (New 2-04) Page 398

ICNU_DR_118 Attachment A

Page 201 of 235
Schedule Page: 398 Line No.: 7 Column: b
Interdepartmental frequency and regulation and spinning and non-spinning reserve service
for Native Load.
Schedule Page: 398 Line No.: 7 Column: d
Interdepartmental frequency and regulation and spinning and non-spinning reserve service
for Native Load.
Schedule Page: 398 Line No.: 7 Column: e
Interdepartmental frequency and regulation and spinning and non-spinning reserve service
for Native Load.
Schedule Page: 398 Line No.: 7 Column: g
Interdepartmental frequency and regulation and spinning and non-spinning reserve service
for Native Load.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

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Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Monthly Peak
MW - Total
(c)(b)(a)
Month
NAME OF SYSTEM:
Day of
Monthly
Peak
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
(d)
Hour of
Monthly
Peak
(e)
Firm Network
Service for Self
(f)
Firm Network
Service for
Others
(g)
Long-Term Firm
Point-to-point
Reservations
(h)
Other Long-
Term Firm
Service
(i)
Short-Term Firm
Point-to-point
Reservation
(j)
Other
Service
21 311 3 162 293 1,367 80022 2,133January 1
22 420 258 162 273 1,413 80017 2,268February 2
19 430 208 162 288 1,282 800 3 2,162March 3
62 1,161 469 486 854 4,062Total for Quarter 1 4
14 484 25 176 237 1,158 800 1 2,054April 5
24 333 571 180 193 1,226160027 1,932May 6
37 404 62 180 297 1,585170030 2,466June 7
75 1,221 658 536 727 3,969Total for Quarter 2 8
33 339 26 176 303 1,5941700 2 2,411July 9
30 340 100 171 308 1,602170013 2,421August 10
21 427 217 171 208 1,114200021 1,920September 11
84 1,106 343 518 819 4,310Total for Quarter 3 12
21 339 64 171 227 1,226 90023 1,962October 13
17 88 162 316 1,528180030 2,094November 14
17 231 95 162 300 1,4711800 1 2,164December 15
55 658 159 495 843 4,225Total for Quarter 4 16
276 4,146 1,629 2,035 3,243 16,566
Total Year to
Date/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04)Page 400

ICNU_DR_118 Attachment A

Page 204 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
ELECTRIC ENERGY ACCOUNT
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
Item
(a)(b)(a)(b)
Line
No.MegaWatt Hours Item MegaWatt Hours
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
SOURCES OF ENERGY1
Generation (Excluding Station Use):2
2,010,503Steam3
Nuclear4
3,434,549Hydro-Conventional5
Hydro-Pumped Storage6
1,972,169Other7
Less Energy for Pumping8
7,417,221Net Generation (Enter Total of lines 3
through 8)
9
5,080,211Purchases10
Power Exchanges:11
523,891Received12
525,354Delivered13
-1,463Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
3,275,367Received16
3,275,367Delivered17
Net Transmission for Other (Line 16 minus
line 17)
18
Transmission By Others Losses19
12,495,969TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
8,615,654Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
Requirements Sales for Resale (See
instruction 4, page 311.)
23
3,326,381Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
10,844Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
543,090Total Energy Losses27
12,495,969TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
28
FERC FORM NO. 1 (ED. 12-90)Page 401a

ICNU_DR_118 Attachment A

Page 205 of 235
(d)
Day of Month
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
MONTHLY PEAKS AND OUTPUT
Avista Corporation X
04/15/2016 2015/Q4
Line
No.Total Monthly Energy Megawatts
(c)(b)(a)
Hour
(e)
MONTHLY PEAK
Month
NAME OF SYSTEM:
Monthly Non-Requirments
Sales for Resale &
Associated Losses (See Instr. 4)
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2. Report in column (b) by month the system’s output in Megawatt hours for each month.
3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.
5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
(f)
January 29 2 1,492 332,741 1800 1,220,417
February 30 23 1,382 358,865 0800 1,085,868
March 31 4 1,374 443,742 0800 1,190,027
April 32 16 1,232 423,331 0800 1,122,928
May 33 29 1,200 392,660 1800 1,081,862
June 34 29 1,607 270,762 1800 1,048,538
July 35 9 1,588 146,468 1700 973,150
August 36 12 1,638 157,973 1700 957,667
September 37 11 1,228 134,372 1700 799,433
October 38 23 1,134 180,688 0900 870,390
November 39 30 1,529 239,713 1800 1,015,239
December 40 30 1,469 245,066 1900 1,130,450
FERC FORM NO. 1 (ED. 12-90)Page 401b
41 TOTAL 12,495,969 3,326,381

ICNU_DR_118 Attachment A

Page 206 of 235
Spokane N.E.Coyote Springs 2
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016 2015/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Gas TurbineGas Turbine 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Not ApplicableNot Applicable 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19782003 3 Year Originally Constructed
19782003 4 Year Last Unit was Installed
61.80287.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
62308 6 Net Peak Demand on Plant - MW (60 minutes)
237387 7 Plant Hours Connected to Load
65284 8 Net Continuous Plant Capability (Megawatts)
0284 9 When Not Limited by Condenser Water
0284 10 When Limited by Condenser Water
114 11 Average Number of Employees
10730001891969000 12 Net Generation, Exclusive of Plant Use - KWh
1572770 13 Cost of Plant: Land and Land Rights
74432011401817 14 Structures and Improvements
13350186161933881 15 Equipment Costs
0351682 16 Asset Retirement Costs
14251783173687380 17 Total Cost
230.6114605.1825 18 Cost per KW of Installed Capacity (line 17/5) Including
1961072221 19 Production Expenses: Oper, Supv, & Engr
4868348600116 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
28081579917 25 Electric Expenses
10938325020 26 Misc Steam (or Nuclear) Power Expenses
0507 27 Rents
00 28 Allowances
1071189060 29 Maintenance Supervision and Engineering
0103848 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
937441847019 32 Maintenance of Electric Plant
6384354135 33 Maintenance of Misc Steam (or Nuclear) Plant
16382454071843 34 Total Production Expenses
0.15270.0286 35 Expenses per Net KWh
GAS GAS 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
MCF MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
12834115 0 0 13834 0 0 38 Quantity (Units) of Fuel Burned
1020000 0 0 1020000 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
3.787 0.000 0.000 3.519 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
3.787 0.000 0.000 3.519 0.000 0.000 41 Average Cost of Fuel per Unit Burned
3.713 0.000 0.000 3.450 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.026 0.000 0.000 0.045 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
6919.000 0.000 0.000 13151.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03)Page 402

ICNU_DR_118 Attachment A

Page 207 of 235
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
RathdrumColstripKettle Falls
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
(e)(f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Gas TurbineSteamSteam 1
Not ApplicableConventionalConventional 2
199519831984 3
199519831985 4
166.5050.70 233.40 5
14651244 6
46476478395 7
16754222 8
054222 9
054222 10
130361 11
525580003205170001689986000 12
62168222890771289095 13
344235028063737103242039 14
5961216772296154200107318 15
045068712673768 16
63676199103099655317312220 17
382.43962033.5238 1359.5211 18
-6355123187158825 19
1994338780197822992450 20
000 21
07491844449966 22
000 23
000 24
2068621096986131920 25
171923569172436994 26
0033667 27
000 28
1582178715402137 29
101473935684412 30
014994693261220 31
92298243854357158 32
33940314544640438 33
23408711243876935549187 34
0.04450.0388 0.0210 35
WOOD GAS GASCOAL OIL 36
TON MCF MCFTONBBL 37
495602 4728 0 627068 0 01063105 1768 0 38
8600000 1020000 0 1020000 0 016970000 5880000 0 39
15.710 3.439 0.000 3.180 0.000 0.00021.443 110.859 0.000 40
15.710 3.439 0.000 3.180 0.000 0.00021.443 110.859 0.000 41
1.827 3.372 0.000 3.118 0.000 0.0001.264 18.854 0.000 42
0.024 0.051 0.000 0.038 0.000 0.0000.014 0.000 0.000 43
13311.000 0.000 0.000 12170.000 0.000 0.00010681.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03)Page 403

ICNU_DR_118 Attachment A

Page 208 of 235
Boulder Park
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016 2015/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Internal Comb 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Conventional 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
2002 3 Year Originally Constructed
2002 4 Year Last Unit was Installed
0.0024.60 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
025 6 Net Peak Demand on Plant - MW (60 minutes)
01145 7 Plant Hours Connected to Load
024 8 Net Continuous Plant Capability (Megawatts)
00 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
01 11 Average Number of Employees
022428000 12 Net Generation, Exclusive of Plant Use - KWh
0185629 13 Cost of Plant: Land and Land Rights
01204874 14 Structures and Improvements
031478099 15 Equipment Costs
00 16 Asset Retirement Costs
032868602 17 Total Cost
01336.1220 18 Cost per KW of Installed Capacity (line 17/5) Including
022941 19 Production Expenses: Oper, Supv, & Engr
0727228 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
0154249 25 Electric Expenses
023572 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
04166 29 Maintenance Supervision and Engineering
00 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
0261462 32 Maintenance of Electric Plant
048981 33 Maintenance of Misc Steam (or Nuclear) Plant
01242599 34 Total Production Expenses
0.00000.0554 35 Expenses per Net KWh
GAS 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
200973 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1020000 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
3.619 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
3.619 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
3.548 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.032 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
9140.000 0.000 0.000 0.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03)Page 402.1

ICNU_DR_118 Attachment A

Page 209 of 235
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
(e)(f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
1
2
3
4
0.000.00 0.00 5
000 6
000 7
000 8
000 9
000 10
000 11
000 12
000 13
000 14
000 15
000 16
000 17
000 18
000 19
000 20
000 21
000 22
000 23
000 24
000 25
000 26
000 27
000 28
000 29
000 30
000 31
000 32
000 33
000 34
0.00000.0000 0.0000 35
36
37
0 0 0 0 0 000 0 38
0 0 0 0 0 000 0 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03)Page 403.1

ICNU_DR_118 Attachment A

Page 210 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End ofAvista Corporation X
04/15/2016 2015/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
2 Type of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was Installed
0.000.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
00 6 Net Peak Demand on Plant - MW (60 minutes)
00 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
00 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
00 12 Net Generation, Exclusive of Plant Use - KWh
00 13 Cost of Plant: Land and Land Rights
00 14 Structures and Improvements
00 15 Equipment Costs
00 16 Asset Retirement Costs
00 17 Total Cost
00 18 Cost per KW of Installed Capacity (line 17/5) Including
00 19 Production Expenses: Oper, Supv, & Engr
00 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
00 25 Electric Expenses
00 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
00 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
00 32 Maintenance of Electric Plant
00 33 Maintenance of Misc Steam (or Nuclear) Plant
00 34 Total Production Expenses
0.00000.0000 35 Expenses per Net KWh
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
0 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
0 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
0.000 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
0.000 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.000 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
0.000 0.000 0.000 0.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03)Page 402.2

ICNU_DR_118 Attachment A

Page 211 of 235
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
(e)(f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
1
2
3
4
0.000.00 0.00 5
000 6
000 7
000 8
000 9
000 10
000 11
000 12
000 13
000 14
000 15
000 16
000 17
000 18
000 19
000 20
000 21
000 22
000 23
000 24
000 25
000 26
000 27
000 28
000 29
000 30
000 31
000 32
000 33
000 34
0.00000.0000 0.0000 35
36
37
0 0 0 0 0 000 0 38
0 0 0 0 0 000 0 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03)Page 403.2

ICNU_DR_118 Attachment A

Page 212 of 235
Schedule Page: 402 Line No.: -1 Column: b
Operated by Portland General Electric.
Schedule Page: 402 Line No.: -1 Column: c
designed for peak load service
Schedule Page: 403 Line No.: -1 Column: e
Joint project operated by PPL Montana LLC.
Schedule Page: 403 Line No.: -1 Column: f
designed for peak load service
Schedule Page: 402 Line No.: 1 Column: b
Operated by Portland General Electric
Schedule Page: 402 Line No.: 1 Column: c
Designed for peak load service
Schedule Page: 403 Line No.: 1 Column: e
Joint project operated by Talen Montana, LLC
Schedule Page: 403 Line No.: 1 Column: f
Designed for peak load service
Schedule Page: 402.1 Line No.: -1 Column: b
designed for peak load service
Schedule Page: 402.1 Line No.: 1 Column: b
Designed for peak load service
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2016
Year/Period of Report
2015/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1

ICNU_DR_118 Attachment A

Page 213 of 235

This Page Intentionally Left Blank

ICNU_DR_118 Attachment A

Page 214 of 235
2545
Upper Falls
2545
Monroe Street
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Run-of-River
Plant Construction type (Conventional or Outdoor) 2 Conventional Conventional
Year Originally Constructed 3 1890 1922
Year Last Unit was Installed 4 1992 1922
Total installed cap (Gen name plate Rating in MW) 5 14.80 10.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 19 11
Plant Hours Connect to Load 7 8,508 4,981
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 15 10
(b) Under the Most Adverse Oper Conditions 10 15 10
Average Number of Employees 11 4 4
Net Generation, Exclusive of Plant Use - Kwh 12 84,084,000 38,374,000
Cost of Plant 13
Land and Land Rights 14 0 1,081,854
Structures and Improvements 15 11,979,462 976,337
Reservoirs, Dams, and Waterways 16 9,977,635 7,678,005
Equipment Costs 17 12,747,288 5,561,630
Roads, Railroads, and Bridges 18 50,448 490,407
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 34,754,833 15,788,233
Cost per KW of Installed Capacity (line 20 / 5) 21 2,348.2995 1,578.8233
Production Expenses 22
Operation Supervision and Engineering 23 0 0
Water for Power 24 0 0
Hydraulic Expenses 25 82 133
Electric Expenses 26 599,411 559,104
Misc Hydraulic Power Generation Expenses 27 53,234 58,523
Rents 28 0 0
Maintenance Supervision and Engineering 29 0 2,911
Maintenance of Structures 30 7,759 4,633
Maintenance of Reservoirs, Dams, and Waterways 31 24,333 21,247
Maintenance of Electric Plant 32 37,234 149,217
Maintenance of Misc Hydraulic Plant 33 13,084 12,490
Total Production Expenses (total 23 thru 33) 34 735,137 808,258
Expenses per net KWh 35 0.0087 0.0211
FERC FORM NO. 1 (REV. 12-03)Page 406

ICNU_DR_118 Attachment A

Page 215 of 235
2545
Nine Mile Falls Cabinet Gorge
2058
Post Falls
2545
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Storage StorageRun-of-River 1
Conventional OutdoorConventional 2
1906 19521908 3
1980 19531994 4
14.80 265.0026.40 5
19 21022 6
7,240 8,5036,669 7
8
15 27320 9
15 27320 10
4 145 11
73,223,000 994,875,00066,890,000 12
13
3,570,115 13,026,63233,429 14
1,955,716 12,663,4697,890,935 15
12,789,109 46,719,66618,406,573 16
3,174,508 48,527,76818,029,852 17
0 1,268,753625,181 18
0 00 19
21,489,448 122,206,28844,985,970 20
1,451.9897 461.15581,704.0140 21
22
1,057 164,705373 23
0 00 24
4 00 25
638,512 1,346,764647,250 26
78,742 162,35851,938 27
0 00 28
94 68,969733 29
3,152 46,62219,003 30
81,544 5,461559,803 31
190,376 340,53474,984 32
39,978 83,31215,398 33
1,033,459 2,218,7251,369,482 34
0.0141 0.00220.0205 35
FERC FORM NO. 1 (REV. 12-03)Page 407

ICNU_DR_118 Attachment A

Page 216 of 235
2545
Long Lake
2058
Noxon Rapids
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in
a footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Storage Storage
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1959 1915
Year Last Unit was Installed 4 1977 1924
Total installed cap (Gen name plate Rating in MW) 5 487.80 70.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 499 89
Plant Hours Connect to Load 7 4,887 5,228
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 562 88
(b) Under the Most Adverse Oper Conditions 10 562 88
Average Number of Employees 11 12 6
Net Generation, Exclusive of Plant Use - Kwh 12 1,635,111,000 394,390,000
Cost of Plant 13
Land and Land Rights 14 35,772,759 2,126,493
Structures and Improvements 15 18,645,154 5,260,192
Reservoirs, Dams, and Waterways 16 34,460,517 18,742,367
Equipment Costs 17 106,747,610 12,230,673
Roads, Railroads, and Bridges 18 246,561 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 195,872,601 38,359,725
Cost per KW of Installed Capacity (line 20 / 5) 21 401.5428 547.9961
Production Expenses 22
Operation Supervision and Engineering 23 135,734 2,250
Water for Power 24 0 0
Hydraulic Expenses 25 98,760 9,935
Electric Expenses 26 1,285,533 785,331
Misc Hydraulic Power Generation Expenses 27 197,336 65,031
Rents 28 85 0
Maintenance Supervision and Engineering 29 78,552 734,121
Maintenance of Structures 30 118,731 62,816
Maintenance of Reservoirs, Dams, and Waterways 31 81,775 57,114
Maintenance of Electric Plant 32 932,580 379,483
Maintenance of Misc Hydraulic Plant 33 101,033 29,004
Total Production Expenses (total 23 thru 33) 34 3,030,119 2,125,085
Expenses per net KWh 35 0.0019 0.0054
FERC FORM NO. 1 (REV. 12-03)Page 406.1

ICNU_DR_118 Attachment A

Page 217 of 235
2545
Little Falls
0 0
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Run-of-River 1
Conventional 2
1910 3
1911 4
0.00 0.0032.00 5
0 029 6
0 05,981 7
8
0 036 9
0 036 10
0 05 11
0 0147,602,000 12
13
0 04,325,371 14
0 01,943,376 15
0 05,065,492 16
0 012,765,635 17
0 00 18
0 00 19
0 024,099,874 20
0.0000 0.0000753.1211 21
22
0 00 23
0 00 24
0 010,248 25
0 0652,719 26
0 022,363 27
0 0902,849 28
0 012,013 29
0 037,011 30
0 0461,038 31
0 096,974 32
0 012,194 33
0 02,207,409 34
0.0000 0.00000.0150 35
FERC FORM NO. 1 (REV. 12-03)Page 407.1

ICNU_DR_118 Attachment A

Page 218 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.
Name of Plant
Installed Capacity
(c)(b)(a)
Cost of Plant
Net PeakDemand
(d)
Year
Orig.Const.
Name Plate Rating
(In MW)MW(60 min.)
Net GenerationExcludingPlant Use
(e)(f)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project,
give project number in footnote.
7.20 8.0 4,141,000 9,178,2622002Kettle Falls CT 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03)Page 410

ICNU_DR_118 Attachment A

Page 219 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants) (Continued)
Avista Corporation X
04/15/2016 2015/Q4
Line
No.(i)(h)(g)(j)(k)(l)
Operation
Exc'l. Fuel
Production Expenses
Fuel Maintenance Kind of Fuel Fuel Costs (in cents
(per Million Btu)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset
Retire. Costs) Per MW
354 45,631 173,841 1,274,759 1Nat Gas 148,977
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03)Page 411

ICNU_DR_118 Attachment A

Page 220 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than
60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
60.00 60.00 1.00 1 Group Sum
2
115.00 115.00 1,544.00 3 Group Sum
4
Steel Tower 230.00 230.00 1.00 1 5 Beacon Sub #4 BPA Bell Sub
H Type 230.00 230.00 5.00 1 6 Beacon Sub BPA Bell Sub
Steel Pole 230.00 230.00 3.00 1 7 Beacon Sub #5 BPA Bell Sub
H Type 230.00 230.00 3.00 1 8 Beacon Sub #5 BPA Bell Sub
Steel Tower 230.00 230.00 1.00 1 9 Beacon Cabinet Gorge Plant
Steel Pole 230.00 230.00 27.00 2 10 Beacon Cabinet Gorge Plant
H Type 230.00 230.00 53.00 1 11 Beacon Cabinet Gorge Plant
Steel Tower 230.00 230.00 1.00 1 12 Beacon Sub Lolo Sub
H Type 230.00 230.00 102.00 1 13 Beacon Sub Lolo Sub
Steel Pole 230.00 230.00 1.00 1 14 Benewah Shawnee
Steel Pole 230.00 230.00 59.00 1 15 Benewah Shawnee
Steel Pole 230.00 230.00 29.00 1 16 Noxon Plant Pine Creek Sub
H Type 230.00 230.00 15.00 1 17 Noxon Plant Pine Creek Sub
H Type 230.00 230.00 1.00 1 18 Cabinet Gorge Plant Noxon
H Type 230.00 230.00 1.00 1 19 Cabinet Gorge Plant Noxon
H Type 230.00 230.00 17.00 1 20 Cabinet Gorge Plant Noxon
Steel Tower 230.00 230.00 1 21 Benewah Sw. Station Pine Creek Sub
H Type 230.00 230.00 43.00 1 22 Benewah Sw. Station Pine Creek Sub
Steel Tower 230.00 230.00 1 23 Divide Creek Lolo Sub
H Type 230.00 230.00 43.00 1 24 Divide Creek Lolo Sub
H Type 230.00 230.00 39.00 1 25 N. Lewiston Walla Walla
H Type 230.00 230.00 4.00 1 26 N. Lewiston Walla Walla
Steel Pole 230.00 230.00 4.00 1 27 N. Lewiston Walla Walla
Steel Pole 230.00 230.00 7.00 1 28 N. Lewiston Shawnee
H Type 230.00 230.00 27.00 1 29 N. Lewiston Shawnee
Alum. 230.00 230.00 30 Walla Walla Wanapum
H Type 230.00 230.00 15.00 1 31 Walla Walla Wanapum
H Type 230.00 230.00 63.00 1 32 Walla Walla Wanapum
Steel Tower 230.00 230.00 1.00 1 33 BPA (Libby)Noxon Plant
Steel Tower 230.00 230.00 1.00 1 34 BPA/Hot Springs #1 Noxon Plant
Steel Tower 230.00 230.00 2.00 1 35 BPA/Hot Springs #2 Noxon Plant (dead)
FERC FORM NO. 1 (ED. 12-87)Page 422
36 TOTAL 2,207.00 3.00 36
ICNU_DR_118 Attachment A

Page 221 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Operation
Expenses
Maintenance Rents TotalLand Construction and
Other Costs
Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
786,433 650,395 136,038 1
2
170,679,846 159,595,502 11,084,344 912,283 613,498 298,785 3
4
1272 ACSS 5
1,447,4721272 ACSS 1,429,560 17,912 1,194 1,194 6
1272 ACSS 7
3,305,6801272 ACSS 3,275,357 30,323 494 494 8
1272 ACSS 9
1590 ACSS 10
43,154,0971590 ACSR 41,997,901 1,156,196 55,775 55,775 11
1590 ACSS 12
15,553,0641272 McMAL 15,096,902 456,162 73,477 73,477 13
1622 ACSS 14
48,598,3101590 ACSS 48,028,103 570,207 2,835 2,835 15
1272 ACSR 16
19,504,107954 McMAL 18,406,428 1,097,679 283,370 252,319 31,051 17
1590 ACSS 18
795 ACSR 19
1,956,515954 McMAL 1,772,304 184,211 18,196 11,730 6,466 20
1622 ACSS 21
5,135,680954 McMAL 4,785,355 350,325 45,364 44,247 1,117 22
1272 McMAL 23
5,445,3791272 McMAL 5,359,151 86,228 11,103 10,834 269 24
1272 McMAL 25
1272 ACSR 26
8,399,0881272 ACSR 7,770,311 628,777 10,880 10,490 390 27
1272 ACSR 28
10,918,6721272 ACSR 10,046,522 872,150 741 741 29
30
1272 ACSR 31
6,984,8911272 McMAL 6,779,544 205,347 12,704 12,704 32
1272 ACSR 33
19,5211272 ACSR 19,521 4,086 4,086 34
1272 McMAL 35
FERC FORM NO. 1 (ED. 12-87)Page 423
36 18,163,567 366,616,452 384,780,019 428,472 1,323,077 89,809 1,841,358
ICNU_DR_118 Attachment A

Page 222 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than
60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower;
or (4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
by the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the
remainder of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
H Type 230.00 230.00 68.00 1 1 BPA/Hot Springs #2 Noxon Plant
Steel Pole 230.00 230.00 2.00 2 2 BPA Line West Side Sub
H Type 230.00 230.00 7.00 1 3 Hatwai N. Lewiston Sub
H Type 230.00 230.00 20.00 1 4 Divide Creek Imnaha
500.00 500.00 5 Colstrip Plant Broadview
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87)Page 422.1
36 TOTAL 2,207.00 3.00 36
ICNU_DR_118 Attachment A

Page 223 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Operation
Expenses
Maintenance Rents TotalLand Construction and
Other Costs
Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or
other party is an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
6,367,1311272 McMAL 6,039,253 327,878 97,484 96,206 1,278 1
639,5961272 ACSR 594,652 44,944 2,872 2,872 2
2,740,5401590 ACSR 2,626,745 113,795 2,113 679 1,434 3
1,530,7261272 McMAL 1,325,464 205,262 787 787 4
31,613,271 31,017,482 595,789 305,600 89,809 145,686 70,105 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87)Page 423.1
36 18,163,567 366,616,452 384,780,019 428,472 1,323,077 89,809 1,841,358
ICNU_DR_118 Attachment A

Page 224 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
(c)(b)(a)(d)(e)
LINE DESIGNATION
From To
LineLength
inMiles
SUPPORTING STRUCTURE
Type AverageNumber per
Miles
CIRCUITS PER STRUCTURE
Present Ultimate
(f)(g)
1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
1 No new transmission lines added in 2015
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
FERC FORM NO. 1 (REV. 12-03)Page 424
44 TOTAL
ICNU_DR_118 Attachment A

Page 225 of 235
Total
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR (Continued)
Avista Corporation X
04/15/2016
2015/Q4
Line
No.
(k)(j)(h)(l)(m)
CONDUCTORS
Size Configuration
Voltage
KV
LINE COST
Land and Poles, Towers
and Fixtures
Conductors
(n)(p)
Specification and Spacing (Operating)Land Rights and Devices(i)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase,
indicate such other characteristic.
Asset
(o)Retire. Costs
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
FERC FORM NO. 1 (REV. 12-03)Page 425
44

ICNU_DR_118 Attachment A

Page 226 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X
04/15/2016 2015/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
STATE OF WASHINGTON 1
2
Airway Heights 13.80 115.00Distr. Unattended 3
Barker Road 13.80 115.00Distr. Unattended 4
Beacon 115.00 230.00 13.80Trnsm. & Distr Unatt 5
Boulder 115.00 230.00 13.80Trnsm. Unattended 6
Chester 13.80 115.00Distr. Unattended 7
Chewelah 115Kv 13.80 115.00Distr. Unattended 8
Colbert 13.80 115.00Distr. Unattended 9
College & Walnut 13.80 115.00Distr. Unattended 10
Colville 115Kv 13.80 115.00Distr. Unattended 11
Critchfield 13.80 115.00Distr. Unattended 12
Deer Park 13.80 115.00Dist. Unattended 13
Dry Creek 115.00 230.00 13.80Transm. Unattended 14
Dry Gulch 13.80 115.00Distr. Unattended 15
East Colfax 13.80 115.00Distr. Unattended 16
East Farms 13.80 115.00Distr. Unattended 17
Fort Wright 13.80 115.00Distr. Unattended 18
Francis and Cedar 13.80 115.00Distr. Unattended 19
Gifford 34.00 115.00Distr. Unattended 20
Glenrose 13.80 115.00Distr. Unattended 21
Greenwood 13.80 115.00Distr. Unattended 22
Hallett & White 13.80 115.00Distr. Unattended 23
Indian Trail 13.80 115.00Dist. Unattended 24
Industrial Park 13.80 115.00Dist. Unattended 25
Kettle Falls 13.80 115.00Distr. Unattended 26
Lee & Reynolds 13.80 115.00Distr. Unattended 27
Liberty Lake 13.80 115.00Distr. Unattended 28
Little Falls 115/34Kv 34.00 115.00Distr. Unattended 29
Lyons & Standard 13.80 115.00Distr. Unattended 30
Mead 13.80 115.00Distr. Unattended 31
Metro 13.80 115.00Distr. Unattended 32
Milan 13.80 115.00Distr. Unattended 33
Millwood 13.80 115.00Dist. Unattended 34
Ninth & Central 13.80 115.00Distr. Unattended 35
Northeast 13.80 115.00Distr. Unattended 36
Northwest 13.80 115.00Distr. Unattended 37
Opportunity 13.80 115.00Dist. Unattended 38
Othello 13.80 115.00Distr. Unattended 39
Post Street 13.80 115.00Distr. Unattended 40
FERC FORM NO. 1 (ED. 12-96)Page 426

ICNU_DR_118 Attachment A

Page 227 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X
04/15/2016 2015/Q4
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
1
2
24 2 40 39Frcd Oil&Air Fan&Cap 3
12 1 20 1Two Stage Fan 4
536 4 560 2Two Stage Fan 5
300 2 500 2Two Stage Fan 6
24 2 40 2Frcd Oil & Air Fan 7
12 1 20 1Two Stage Fan 8
12 1 20 16Frcd Oil & Air Fan 9
36 2 60 2Two Stage Fan 10
32 3 45 3Frcd Oil & Air Fan 11
12 1 20 1Two Stage Fan 12
12 1 20 1Two Stage Fan 13
150 1 250 223Two Stage Fan & Caps 14
24 2 40 2Frcd Oil & Air Fan 15
12 1 20 1FrOil/Air Fan 16
12 1 20 1Two Stage Fan 17
24 2 1 40 2Fr Oil/Air/2StgFan 18
36 2 60 2Two Stage Fan 19
12 1 20
12 1 20 1Frcd Oil & Air Fan 21
12 1 20 1Two Stage Fan 22
12 1 20 1Two Stg Fan 23
12 1 20 1Two Stage Fan 24
24 2 40 14Two Stg/Pt/Frcd Oil 25
12 1 20 1Frcd Oil & Air Fan 26
12 1 20 1Two Stage Fan 27
24 2 40 2Two Stage Fan 28
12 1 29
36 2 60 2Two Stage Fan 30
18 1 30 1Two Stage Fan 31
24 2 40 2Two Stage Fan 32
24 2 40 2Frcd Oil & Air Fan 33
24 2 2 40 2Two Stage Fan 34
24 2 1 40 2Frcd & Two Stage Fan 35
24 2 40 2Two Stage Fan 36
24 2 40 2Two Stage Fan 37
12 1 20 1Two Stage Fan 38
24 2 40 2FrOil/AirFan 39
36 2 60 2Frcd Oil & Wt Fan 40
FERC FORM NO. 1 (ED. 12-96)Page 427

ICNU_DR_118 Attachment A

Page 228 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X
04/15/2016 2015/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Pound Lane 13.80 115.00Distr. Unattended 1
Ross Park 13.80 115.00Distr. Unattended 2
Roxboro 24.00 115.00Distr. Unattended 3
Shawnee 115.00 230.00 13.80Trans. Unattended 4
Silver Lake 13.80 115.00Distr. Unattended 5
Southeast 13.80 115.00Distr. Unattended 6
South Othello 13.80 115.00Distr. Unattended 7
South Pullman 13.80 115.00Distr. Unattended 8
Sunset 13.80 115.00Distr. Unattended 9
Terre View 13.80 115.00Dist. Unattended 10
Third & Hatch 13.80 115.00Distr. Unattended 11
Turner 13.80 115.00Dist. Unattended 12
Waikiki 13.80 115.00Distr. Unattended 13
West Side 115.00 230.00 13.80Trans. Unattended 14
Other: 28 substa less than 10MVA Distr. Unattended 15
16
STATE OF IDAHO 17
Appleway 13.80 115.00Dist. Unattended 18
Avondale 13.80 115.00Dist. Unattended 19
Benewah 115.00 230.00 13.80Trans. Unattended 20
Big Creek 13.80 115.00Distr. Unattended 21
Blue Creek 13.80 115.00Distr. Unattended 22
Bunker Hill Limited 13.80 115.00Distr. Unattended 23
Cabinet Gorge (Switchyard) 115.00 230.00 13.80Trans. Unattended 24
Clark Fork 21.80 115.00Distr. Unattended 25
Coeur d'Alene 15th Ave 13.80 115.00Distr. Unattended 26
Cottonwood 24.90 115.00Distr. Unattended 27
Dalton 13.80 115.00Distr. Unattended 28
Grangeville 13.80 115.00Distr. Unattended 29
Holbrook 13.80 115.00Distr. Unattended 30
Huetter 13.80 115.00Distr. Unattended 31
Idaho Road 13.80 115.00Distr Unattended 32
Juliaetta 13.80 115.00Distr. Unattended 33
Kamiah 13.80 115.00Dist. Unattended 34
Kooskia 13.80 115.00Distr. Unattended 35
Lewiston Mill Rd 13.20 115.00Distr. Unattended 36
Lolo 115.00 230.00 13.80Tran & Dist Unattnd 37
Moscow 13.80 115.00Distr. Unattended 38
Moscow 230Kv 115.00 230.00 13.80Tran & Dist Unattnd 39
North Moscow 13.80 115.00Distr. Unattended 40
FERC FORM NO. 1 (ED. 12-96)Page 426.1

ICNU_DR_118 Attachment A

Page 229 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X
04/15/2016 2015/Q4
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
24 2 40 2Two Stage Fan 1
30 2 54 2Two Stage Fan 2
24 2 40 2Two Stage Fan 3
150 1 250 1Two Stage Fan 4
12 1 20 1Frcd Oil & Air Fan 5
30 2 50 2Two Stage Fan 6
12 1 20 1Two Stage Fan 7
30 2 50 2Two Stage Fan 8
33 2 55 50Two Stage Fan & Caps 9
12 1 20 1Two Stage Fan 10
54 3 90 103Two Stg Fan & Cap 11
36 2 60 2Two Stg Fan 12
24 2 40 2Two Stage Fan 13
250 2 14
166 34 3 15
16
17
36 2 60 2Two Stage Fan 18
12 1 20 1Two Stage Fan 19
75 1 125 223Two Stage Fan & Caps 20
18 2 22 2Portable Fan 21
12 1 20 1Two Stage Fan 22
12 1 16 1Frcd Air Fan 23
75 1 125 1Two Stage Fan 24
10 1 13 1Frcd Air Fan 25
36 2 60 2Two Stage Fan 26
12 1 20 1Two Stage Fan 27
24 2 40 2FrcOil/Air2StgFan 28
25 4 34 17FrcdOil/Air/Pt Fan&C 29
12 1 20 1Two Stage Fan 30
12 1 20 1Two Stage Fan 31
12 1 20 1Two Stage Fan 32
12 1 20 1Frcd Oil & Air Fan 33
12 1 20 1Two Stage Fan 34
15 3 20 3Frcd Air Fan 35
18 1 30 1Two Stage Fan 36
262 3 270 1Frcd Oil/Air/Two Stg 37
24 2 40 2FrOil/Air/2Stg Fan 38
162 2 270 76Frcd Air Fan & Caps 39
12 1 20 1Two Stage Fan 40
FERC FORM NO. 1 (ED. 12-96)Page 427.1

ICNU_DR_118 Attachment A

Page 230 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X
04/15/2016 2015/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
North Lewiston 230kV 115.00 230.00 13.80Tran & Dist Unattnd 1
Oden 21.80 115.00Distr. Unattended 2
Oldtown 21.80 115.00Distr. Unattended 3
Orofino 13.80 115.00Distr. Unattended 4
Osburn 13.80 115.00Distr. Unattended 5
Pine Creek 115.00 230.00 13.80Tran & Dist Unattnd 6
Pleasant View 13.80 115.00Distr. Unattended 7
Plummer 13.80 115.00Dist Unattended 8
Post Falls 13.80 115.00Distr. Unattended 9
Potlatch 13.80 115.00Distr. Unattended 10
Prarie 13.80 115.00Distr. Unattended 11
Priest River 20.80 115.00Distr. Unattended 12
Rathdrum 115.00 230.00 13.80Trans & Distr Unattd 13
Sagle 20.80 115.00Dist. Unattended 14
Sandpoint 20.80 115.00Distr. Unattended 15
South Lewiston 13.80 115.00Distr. Unattended 16
Sweetwater 24.90 115.00Distr. Unattended 17
St. Maries 23.90 115.00Distr. Unattended 18
Tenth & Stewart 13.80 115.00Distr. Unattended 19
Wallace 13.80 115.00Distr. Unattended 20
Other: 13 substa less than 10 MVA Distr. Unattended 21
22
STATE OF MONTANA 23
1 substation less than 10 MVA Distr. Unattended 24
25
SUBSTA. @ GENERATING PLANTS 26
STATE OF WASHINGTON 27
Boulder Park 13.80 115.00Trans. Attended 28
Kettle Falls 13.80 115.00Trans. Attended 29
Long Lake 4.00 115.00Trans. Attended 30
Nine Mile 13.80 115.00Trans. Attended 31
Little Falls 4.00 115.00Trans. Attended 32
Northeast 13.80 115.00Trans. Attended 33
Post Street 4.00 13.80Trans. Attended 34
35
STATE OF IDAHO 36
Cabinet Gorge (HED) 13.80 230.00Trans. Attended 37
Post Falls 2.30 115.00Trans. Attended 38
Rathdrum 13.80 115.00Trans. Attended 39
STATE OF MONTANA 40
FERC FORM NO. 1 (ED. 12-96)Page 426.2

ICNU_DR_118 Attachment A

Page 231 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X
04/15/2016 2015/Q4
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
258 2 260 48Frcd Air Fan & Caps 1
10 1 13 1Frcd Air Fan 2
18 2 22 2Frcd Air Fan 3
20 2 28 1Frcd Oil & Air Fan 4
12 1 15 1Portable Fan 5
137 2 145 45Two Stg Fan/Capacito 6
12 1 20 1Two Stage Fan 7
12 1 20 1Two Stage Fan 8
18 1 30 1Two Stage Fan 9
15 2 19 2Portable Fan 10
12 1 20 1Frcd Oil & Air Fan 11
10 1 13 1Frcd Air Fan 12
474 4 490 50Frcd Oil & Air Fan 13
12 1 20 1Two Stage Fan 14
30 3 38 3Frcd Air Fan 15
27 4 39 4Port Fan/FrcdOil/Air 16
12 1 20 1Frcd Oil & Air Fan 17
24 2 40 2Two Stage Fan 18
30 2 50 2Frcd Oil/Air/Two Stg 19
10 3 20
70 13 21
22
23
5 1 24
25
26
27
36 1 60 1Two Stage Fan 28
34 1 1 62 1Two Stage Fan 29
80 4 1 30
12 1 31
24 2 40 2Frcd Oil & Air Fan 32
36 1 60 1Two Stage Fan 33
35 2 34
35
36
300 6 1 Frcd Oil and Air Fan 37
16 2 21 2Frcd Air/Oil/Air Fan 38
114 2 1 190 2Two Stage Fan 39
40
FERC FORM NO. 1 (ED. 12-96)Page 427.2

ICNU_DR_118 Attachment A

Page 232 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X
04/15/2016 2015/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Noxon 13.80 230.00Trans. Attended 1
2
STATE OF OREGON 3
Coyote Springs II 13.80 500.00 18.00Trans. Attended 4
5
SUMMARY: 6
Washington: 7
4 subs Trans. Unattended 8
75 subs Distr. Unattended 9
1 subs Tran & Dist Unattnd 10
7 subs Trans. Attended 11
Idaho: 12
2 subs Trans. Unattended 13
48 subs Distr. Unattended 14
5 subs Tran & Dist Unattnd 15
3 subs Trans. Attended 16
Montana: 1 sub Trans. Attended 17
1 sub Distr. Unattended 18
Oregon: 1 sub Trans. Unattended 19
System: 148 subs 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 426.3

ICNU_DR_118 Attachment A

Page 233 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X
04/15/2016 2015/Q4
Line
No.Number of Units
(g)(f)(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number of
Transformers
In Service
Spare Type of Equipment
Number of
Transformers (In MVa)
(i)(j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
435 9 1 635 2Two Stage Fan 1
2
3
213 1 1 355 1Two Stage fan 4
5
6
7
850 8
1184 9
536 10
257 11
12
150 13
668 14
1293 15
430 16
435 17
5 18
213 19
6020 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 427.3

ICNU_DR_118 Attachment A

Page 234 of 235
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Avista Corporation X
04/15/2016
2015/Q4
Line
No. Description of the Non-Power Good or Service
Name of
(c)(b)(a)(d)
Associated/Affiliated
Company
Account
Charged or
Credited
Amount
Credited
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Charged or
1 Non-power Goods or Services Provided by Affiliated
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21 737,375Salix Inc.146000
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (New)Page 429
FERC FORM NO. 1-F (New)

ICNU_DR_118 Attachment A

Page 235 of 235

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/06/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Mark Thies
REQUESTER: ICNU RESPONDER: Wendy Manskey
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 118 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please provide a copy of the Company’s FERC Form 1 for calendar year 2015. RESPONSE:

Please see ICNU_DR_118 Attachment A for the Company’s FERC Form 1 for calendar year 2015 in electronic form.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 04/28/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 119 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s response to ICNU DR 040. Does the Company’s response apply in all circumstances—e.g., if one rate schedule consistently provided all DSM funding through Schedule 91,
would Avista still not agree that this would present an inequitable circumstance related to all other non-
contributing rate schedules, based on the Company’s stated rationale that “all customers receive
benefits through the DSM programs whether they are directly participating at their specific level of
contribution or not”? If the Company’s response to ICNU DR 040 does not apply in all circumstances, please provide a narrative response explaining any equitable standards that would apply, based on
relative Schedule 91 contribution levels between rate schedules.

RESPONSE:
Among the objectives of the Company in designing programs such as the DSM program, including
funding for the program, is for the program to be fair and reasonable. There can be a range of designs
and outcomes that could be considered to meet those objectives based on specific circumstances.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/02/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 120 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

From 2005 to the present, please quantify the annual share of energy savings achieved by residential DSM programs relative to all other DSM programs. Please provide a response in a format comparable
to the Company’s response to ICNU DR 047.

RESPONSE:
The table below shows the gross unverified Washington & Idaho residential savings and those savings as a
percentage of the portfolio.

Annual Savings Residential %
2005 46,182,976 4,589,371 9.9%
2006 49,154,518 7,646,721 15.6%
2007 58,759,769 14,690,018 25.0%
2008 74,861,160 30,389,515 40.6%
2009 80,340,472 22,336,885 27.8%
2010 72,900,711 17,974,957 24.7%
2011 119,281,122 62,847,129 52.7%
2012 80,179,716 17,793,846 22.2%
2013 65,123,082 18,988,607 29.2%
2014 67,873,456 40,867,797 60.2%
2015 52,025,516 27,194,936 52.3%

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/02/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 121 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

From 2005 to the present, please quantify the annual share of energy savings achieved by non-residential DSM programs relative to all other DSM programs. Please provide a response in a format
comparable to the Company’s response to ICNU DR 047.

RESPONSE:
The table below shows the gross unverified Washington & Idaho non-residential savings and those savings as
a percentage of the portfolio.

Annual Savings Non-Residential %
2005 46,182,976 41,554,363 90.0%
2006 49,154,518 39,932,501 81.2%
2007 58,759,769 42,539,553 72.4%
2008 74,861,160 42,616,253 56.9%
2009 80,340,472 54,867,510 68.3%
2010 72,900,711 52,442,578 71.9%
2011 119,281,122 49,200,814 41.2%
2012 80,179,716 61,500,125 76.7%
2013 65,123,082 45,215,857 69.4%
2014 67,873,456 22,643,592 33.4%
2015 52,025,516 24,749,881 47.6%

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/05/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 122 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s response to ICNU DR 047. From 2005 to the present, please quantify the annual site-specific energy savings attributable to each rate schedule, using the same class
schedule differentiation provided in response to ICNU DR 036 (i.e., 001; 011/012; 021/022;
025; 031/032; 41-48).

RESPONSE:
Please see Avista’s CONFIDENTIAL response to data request no. ICNU – 122C. Please note that
Avista’s response to ICNU – 122C is Confidential per Protective Order in UTC Dockets 160228
& UG-160229.
Attached as ICNU_DR_122C Confidential Attachment A is the data requested (in electronic
format), by rate schedule for Schedules 1, 11/12, 21/22, 31/32, 41-48, for those projects that
were tracked in SalesLogix as being site-specific for the State of Washington.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/05/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 123 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s responses to ICNU DRs 010, 036 and 037. Please provide a response to ICNU DR 037 that provides a quantification of benefits for each customer class schedule, similar to
the isolation of Schedule 25 quantified benefits in the response to ICNU DR 010, using the
same class schedule differentiation provided in response to ICNU DR 036 (i.e., 001; 011/012;
021/022; 025; 031/032; 41-48). If the Company cannot, please explain why the Company was
able to isolate direct incentives paid to Schedule 25, yet cannot isolate direct incentives paid to other schedules.

RESPONSE:
Please see the Company’s response to ICNU_DR_095.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/02/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Mike Dillon
TYPE: Data Request DEPT: Energy Efficiency
REQUEST NO.: ICNU – 124 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

From 2005 to the present, please quantify the annual non-residential (as distinct from “residential and “site-specific” programs) energy savings attributable to each rate schedule,
using the same class schedule differentiation provided in response to ICNU DR 036 (i.e., 001;
011/012; 021/022; 025; 031/032; 41-48).

RESPONSE:
As the Company provided in its response to ICNU_DR_095, the Company cannot provide the
benefits or the energy savings, on a rate schedule basis, as requested because the Company uses
several different systems to track its energy efficiency programs. As a result, Avista cannot report on a rate schedule basis because it cannot query the distinct programs or spreadsheets for
reporting in the requested format. The Company tracks savings, from all of the sources, based
on Residential, Nonresidential, and Limited Income segments, and not by rate schedules. The
Company is currently in the contracting phase to purchase a new energy efficiency tracking and
reporting system, as discussed with its External Advisory Group. Please also see the Company’s response to ICNU_DR_121.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/05/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Patrick Ehrbar
REQUESTER: ICNU RESPONDER: Patrick Ehrbar
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 125 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Refer to Avista’s response to ICNU DR 048. From 2005 to the present, please provide comparable tables—including columns for annual “DSM Revenue,” DSM Direct Incentives,”
and “Ratio”—for each other rate schedule, using the same class schedule differentiation provided
in response to ICNU DR 036 (i.e., 001; 011/012; 021/022; 025; 031/032; 41-48).

RESPONSE:
Please see the Company’s response to ICNU_DR_095 and 124.
ICNU_DR_126 Attachment A Page 1 of 10
ICNU_DR_126 Attachment A Page 2 of 10
ICNU_DR_126 Attachment A Page 3 of 10
ICNU_DR_126 Attachment A Page 4 of 10
ICNU_DR_126 Attachment A Page 5 of 10
ICNU_DR_126 Attachment A Page 6 of 10
ICNU_DR_126 Attachment A Page 7 of 10
ICNU_DR_126 Attachment A Page 8 of 10
ICNU_DR_126 Attachment A Page 9 of 10
ICNU_DR_126 Attachment A Page 10 of 10

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 126 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference “I. UE_AVA Dir Evidence-(Feb16)\3. UE_AVA WP's (Feb16)\G. UE__Johnson WP (AVA-Feb16)\Account 555\ Wells Avista Share.xlsx.” Please provide all workpapers necessary to
calculate the hard coded value of $1,833,428 included in the formula of cells “C10:N10” in tab
“Proforma.”

RESPONSE:
ICNI_DR_126 Attachment A is the fiscal year September 2015 through August 2016 Wells Project
pro forma.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 127 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference “I. UE_AVA Dir Evidence-(Feb16)\3. UE_AVA WP's (Feb16)\G. UE__Johnson WP (AVA-Feb16)\Account 555\ Wells Avista Share.xlsx.” Please indicate why the $1,833,428 hard
coded amount appears to be increased by 1% when prorating to the respective months. See the
formula in cells “C10:N10” in tab “Proforma.”

RESPONSE:
The average rate of escalation in Wells project costs from 2011 to 2015 was 3.0%. On May 3, 2016
Douglas provided the purchasers with a preliminary pro forma for fiscal year September 2016
through August 2017. Avista’s expense is projected to be $1,862,562, which is higher than the $1,857,874 included in the filed power supply pro forma. The final Wells project pro forma for
September 2016 through August 2017 will be available in August 2016 and can be incorporated in
the November 1 power supply expense update.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 128 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference “I. UE_AVA Dir Evidence-(Feb16)\3. UE_AVA WP's (Feb16)\G. UE__Johnson WP (AVA-Feb16)\Re 2017 Workpaper Index.xlsx.” Please provide the Company’s basis for assuming
that the Priest Rapids auction price will be $5.00 greater than the modelled HLH and LLH prices.
See cells “D26:O26” in tab “Index.”

RESPONSE:
The annual auction for the Priest Rapids Project is for a slice of the project. A slice of the project
means the auction winner gets all the products of the project, including energy, capacity, pondage
and other attributes such as being a carbon free specified resource for import into California. The
total project output is worth more than just the energy.
The Company’s experience in participating in Mid Columbia slice auctions is that the winning
bidders (including Avista) have priced their offers at more than the forward energy prices.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 129 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference “I. UE_AVA Dir Evidence-(Feb16)\3. UE_AVA WP's (Feb16)\G. UE__Johnson WP (AVA-Feb16)\Re 2017 Workpaper Index.xlsx.” Please provide an explanation for why the Priest
Rapids project cost is expected to increase by approximately 14% in the pro forma study, relative to
the test period.

RESPONSE:
The Priest Rapids Project cost is based on three factors: 1) actual project costs, 2) the winning
auction price, and 3) the amount of Reasonable Portion revenue that is applied to meeting Grant
PUD’s unmet district load and thus not available to lower the auction price.
The biggest factor driving up Priest Rapid’s cost is the rapid growth in Grant’s loads and therefore
the increasing amount of Reasonable Portion revenue that is applied to meeting Grant’s unmet
district load. Grant’s unmet district load was 3.1 aMW in 2014, 56.4 aMW in 2015, and 114.6
aMW in 2016. The 2017 pro forma is based on 150 aMW for Grant’s unmet district load.
A preliminary Priest Rapid’s pro forma will be available before the November 1 power supply
expense update. That pro forma will have new project costs and a new estimate of Grant’s unmet
district load. The only factor not available will be the auction price, but overall a better projection
of Priest Rapid’s cost can be made at that time.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 130 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Exh. No. WRJ-2, line 26, Natural Gas Purchases. Please generally describe the Company’s methodology for determining the cost of non-consumed gas purchases. Please also
provide all workpapers and source transaction data from the test period used to support the expense
associated with natural gas purchased but not consumed in the test period.

RESPONSE:
The cost of non-consumed gas purchases is determined at the transaction level. It is not based on
an average cost methodology.

Detailed workpapers showing the costs and revenues associated with non-consumed gas purchases on a monthly basis over the period 2011 and 2015 (inclusive) is provided in the Company’s
response to ICNU_DR_132.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 131 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Exh. No. WRJ-2, line 70, Gas Not Consumed Sales Revenue. Please generally describe the Company’s methodology for determining the revenue associated with non-consumed gas
purchases. Please also provide all workpapers and source trade data from the test period used to
determine the revenue associated with natural gas purchased but not consumed in the test period.

RESPONSE:
The revenue of non-consumed gas purchases is determined at the transaction level. It is not based
on an average cost methodology.
Detailed workpapers showing the costs and revenues associated with non-consumed gas purchases
on a monthly basis over the period 2011 and 2015 (inclusive) is provided in the Company’s
response to ICNU_DR_132.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 132 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please detail the costs and revenues associated with non-consumed gas purchases on a monthly basis over the period 2011 and 2015 (inclusive).
RESPONSE:

ICNU_DR_132 Attachments A - E are workpapers showing the costs and revenues associated with non-consumed gas purchases on a monthly basis over the period 2011 and 2015 (inclusive).

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 133 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Exh. No. WRJ-2, line 66, Intracompany Generation. Please generally describe the Company’s methodology for determining the revenue and cost included in rates associated with
intracompany generation. Please also provide all workpapers and source trade data from the test
period used to determine the revenue associated with intracompany generation in the test period.

RESPONSE:
Intracompany Generation revenue in Account 447 is revenue that the Company’s transmission
function receives from third-party transmission customers for products that are supplied by the
Company’s power supply function. These products are frequency regulation, spinning, and
supplemental reserves. The Company books a matching expense in Account 555 called Ancillary Services.

These revenues and expenses will always match and are both zeroed out in the rate case power
supply pro forma.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 134 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Exh. No. WRJ-2, Intracompany Generation. ICNU believes that the Company may be removing the revenue, but not the cost associated with intracompany generation. Please explain
why there is no corresponding adjustment under FERC account 555, or other related expense
account, to remove the cost associated with intracompany generation.

RESPONSE:
Both revenue and expense was removed from the pro forma. The corresponding expense to
Intracompany Generation in Account 447 is line 18, Ancillary Services, in Account 555 of Exhibit
WGJ-2.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 135 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Exh. No. WRJ-2. Please generally describe the WNP-3 settlement and the accounting of that settlement for ratemaking purposes.

RESPONSE:
The Settlement Agreement approved in the Second Supplemental Order in Cause No. U-86-99
specifies that the midpoint (average) shall be used for ratemaking purposes. Section II, Paragraph
(1) of the Settlement Agreement states:

For ratemaking purposes, the O&M costs per kwh associated with Settlement Power will be the average of the “O&M costs (Nuclear) floor” and “O&M costs (Nuclear) ceiling” determined pursuant to the Settlement Exchange Agreement for the applicable rate period. Regardless of the actual O&M costs, for ratemaking purposes
the method described above for determining O&M costs shall be applicable each year for the life of the Settlement Exchange Agreement.
The Settlement Agreement further states in Section II, Paragraph (7):
Nothing herein shall be deemed to waive any party’s right to contest any of WWP’s
operating results adjustments in any future rate proceeding before the WUTC. However, no party will challenge this Settlement Agreement in any future WUTC proceeding in respect to recovery of WWP’s investment in WNP-3, or the level of O&M costs specified in (1) above.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: William Johnson
REQUESTER: ICNU RESPONDER: William Johnson
TYPE: Data Request DEPT: Power Supply
REQUEST NO.: ICNU – 136 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Exh. No. WRJ-2. Please provide an explanation for why the cost of the WNP-3 settlement increased by approximately 34% in the pro forma period.
RESPONSE:

The amount of energy purchased under the contract for contract year November 2014 through April 2015 (test year) was only 310,060 MWh, the lowest amount since the 1995-96 contract year. The rate
case assumes a WNP-3 energy amount of 397,431 MWh. The test year contract rate was
$42.90/MWh, which was the actual contract rate. The rate case average purchase rate is $44.93/MWh,
which is the midpoint rate.
The actual energy amount and midpoint rate will be made available to Avista in August for the 2016-
17 contract year. Those values plus an estimate of the November and December 2017 midpoint rate
can be incorporated in the November 1 power supply expense update.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/10/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Clint Kalich
REQUESTER: ICNU RESPONDER: James Gall
TYPE: Data Request DEPT: Energy Resources
REQUEST NO.: ICNU – 137 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Exh. No. WRJ-2. Please provide a workpaper that calculates the pricing for the WNP-3 Settlement included in the AURORA model.
RESPONSE:

The pricing for the WNP-3 Contract is based on the settlement agreement previously approved by the WUTC. See Avista’s response to ICNU_DR_135 and 135. Also see power supply work
papers pages 19, 20, and 57-60 provided with Avista’s initial rate case filing in this Docket.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/16/2016
CASE NO: UE-160228 & UG-160229 WITNESS: L. Andrews/W. Johnson
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 138 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Reference Andrews Workpaper “9.2015 CBR WA Electric Model,” tab “ROO Input,” Cell “F108.” Please reconcile the $19.6 million Washington-allocated amount booked in FERC
account 501 with the $28.6 million Total Company (approx. $18.5 million Washington-
allocated) amount detailed on row 32 of Exh. No. WGJ-2.

RESPONSE:
The Johnson analysis does not include fuel handling costs (FERC sub account 501200) which are
included in the Andrews Total Account 501.

FERC Account FERC Account Description System Total Washington
Allocation
501110
501120
501140
501160
501200
Total 501
Excludes 501200

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 139 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Does the Millwood 115 kV Substation serve any customers other than Inland Empire Paper Company (“Inland”)? If yes, please identify the other customers connected to this substation, and
specify the load ratio share of substation capacity used to serve each customer.

RESPONSE:
Technically, the Millwood 115 kV distribution substation does not serve Inland Empire Paper
Company as they take power at transmission voltage through a dedicated transformer. There are four
feeders from the Millwood substation that provide power to the City of Millwood and surrounding
areas. No Millwood substation costs other than the dedicated transformer are included in the direct
assignment of distribution costs to Schedule 25 customers. Knox work paper page TLK-E-85 substation engineering memo describes the Inland Empire Paper connection points as follows:

INLAND EMPIRE PAPER – Acct. No. 2500004 – This load is fed from three
points: a connection to an Avista’s 115 kV transmission line, Avista’s Millwood
115 kV Substation and Avista’s Inland Empire Paper Co. Substation. The 115 kV transmission line connection feeds a substation owned by IEP, so there are no
associated 361 and 362 costs. At Avista’s Millwood Sub (which was recently
rebuilt), a dedicated 25 MVA transformer is used, however, since the connection to
IEPCo. is at 60 kV, there would not be any associated costs in Accounts 361 and
362. At Avista’s Inland Empire Paper Co. Sub, use 100% of the book value of the 361 and 362 accounts, as this Avista substation serves only IEPCo.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 140 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify the delivery voltage associated with each Avista account serving Inland.
RESPONSE:
The Inland Empire Paper Account consists of a combination of 3 meter points. One meter point is
measured at 115 kV, the second meter point is measured at 60 kV, and the third meter point is measured at 4.16 kV. Inland receives a primary voltage discount of $1.40 per kVa of demand from
the 115 kV meter point and a primary voltage discount of $1.10 per kVa of demand from the 60 kV
meter point.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 141 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

For each account serving Inland, please identify the delivery voltage to the substation serving the account, and the voltage at the Inland meter.
RESPONSE:

The Inland Empire Paper Account consists of a combination of 3 meter points. One meter point is measured at 115 kV, the second meter point is measured at 60 kV, and the third meter point is
measured at 4.16 kV. Knox work paper page TLK-E-85 substation engineering memo describes the
Inland Empire Paper connection points as follows:

INLAND EMPIRE PAPER – Acct. No. 2500004 – This load is fed from three points: a connection to an Avista’s 115 kV transmission line, Avista’s Millwood
115 kV Substation and Avista’s Inland Empire Paper Co. Substation. The 115 kV
transmission line connection feeds a substation owned by IEP, so there are no
associated 361 and 362 costs. At Avista’s Millwood Sub (which was recently
rebuilt), a dedicated 25 MVA transformer is used, however, since the connection to IEPCo. is at 60 kV, there would not be any associated costs in Accounts 361 and
362. At Avista’s Inland Empire Paper Co. Sub, use 100% of the book value of the
361 and 362 accounts, as this Avista substation serves only IEPCo.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 142 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

With respect to the Millwood Substation, please separately provide the following cost information for the test year:
a. Gross plant investment
b. Accumulated Depreciation
c. Accumulated Deferred Income Taxes
d. Working Capital Balances e. O&M Expenses
f. Depreciation Expense
g. Taxes Other than Income Taxes
h. Income Tax Expense

RESPONSE:
Please see ICNU_DR_142 Attachment A.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 143 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify the date on which the Millwood Substation was placed in service, and the expected end of its economic life.

RESPONSE:
The current Millwood Substation was placed in service December 2012, replacing the Millwood
Substation that had been providing service to the Millwood area since 1957. While the components
of the substation have certain depreciable lives, it is the Company’s expectation that it will continue
to invest in the substation such that there is no expected end to its economic life. As long as there is a need for the substation in the community, it will continue to exist.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 144 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please specify the amount of capital expenditures included in the test year for the Millwood Substation.

RESPONSE:
There were no capital expenditures associated with the Millwood Substation during the test year.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 145 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify the delivery service voltage that Avista identifies as transmission.
RESPONSE:

Greater than 34 kV delivery voltage is considered transmission level service.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 146 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify the delivery service voltage that Avista identifies as sub-transmission.
RESPONSE:

The Company does not differentiate sub-transmission from transmission.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 147 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify the delivery service voltage that Avista identifies as primary.
RESPONSE:

Greater than 11 kV up to 34 kV delivery voltage is considered primary level service.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 148 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please identify the service voltage that Avista identifies as secondary.
RESPONSE:

Less than 11 kV delivery voltage is considered secondary level service.

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 149 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Please list the demand and energy loss factors from generation to the delivery meter for each of the delivery service voltages listed in Data Requests 0145-0148 above.

RESPONSE:
Loss factors by voltage category:
Transmission 3.0%
Primary 4.6%
Secondary 6.2%
Source: Knox work paper page TLK-E-141

Page 1 of 1
AVISTA CORP.
RESPONSE TO REQUEST FOR INFORMATION
JURISDICTION: WASHINGTON DATE PREPARED: 05/25/2016
CASE NO: UE-160228 & UG-160229 WITNESS: Tara L. Knox
REQUESTER: ICNU RESPONDER: Tara Knox
TYPE: Data Request DEPT: State & Federal Regulation
REQUEST NO.: ICNU – 150 TELEPHONE: [phone] EMAIL: [e-mail]

REQUEST:

Referring to Avista’s workpaper TLK – E – 91, on an electronic spreadsheet with all formulas intact, please provide the calculations of the portion of primary distribution costs associated with FERC
Accounts 364 – 367, and 369, that have been directly assigned to Schedule 25.

RESPONSE:
The electronic files were included with the Company’s initial filing and a duplicate copy was provided
as a courtesy with ICNU Data Request No. 52. Please see the electronic file named Misc Assign
WA.xlsx. Workpaper page TLK-E-91 is on the tab within that file named “Primary-Secondary”.
Workpaper page TLK-E-93 is on the tab within that file named “DA Sch 25”. The schedule 25 proportionate share of primary line miles for each plant account (calculated on “DA Sch 25”) is
multiplied by the Washington primary proportion of each account (calculated on “Primary-
Secondary”) to determine the proportion of the total account directly assigned to Schedule 25.