2013Annual Report.pdf

THIS FILING IS
Item 1: I An lnitial(Original) OR E Resubmission No. _
Submission
fryu,E Form l Approved
OMB No.1902-0021
(Expires 1213112014)
Form 1-F Approved
OMB No.1902-0029
(Expires 1213112014)
Form 3-Q Approved
OMB No.1902-0205
(Expires 0513112014)
. ",t"1
,:-iI
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory underthe Federal PowerAct, Sections 3,4(a),304 and 309, and
'18 CFR 141 .1 and 141 ,400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
Exact Lega! Name of Respondent (Company)
Avista Corporation
Year/Period of Report
End of 20131Q4
FERC FORM No.1/3-Q (REV.02-04)
FERC FORM No.1/3-Q (REV. 02-041
FERC FORM NO. 1/3.Q:
Page 1
01 Exact Legal Name of Respondent
Avista Corporation
02 YearlPeriod of Report
03 Previous Name and Date of Change (if name changed during year)
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
05 Name of Contact Person
Christy Burmeister-Smith
06 Title of Contact Person
VP, Controller, Prin. Acctg
07 Address of Contact Person (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
08 Telephone of Contacl Person,lncluding
Area Code
[phone]
09 This Report ls
(1)[ AnOriginal (2) ! AResubmission
10 Date of Report
(Mo, Da, Yr)
04t11t2014
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and otherfinancial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
.D 04 Date Signed
(Mo, Da, Yr)
M.t11t2014
Title 18, U.S.C. 'l 001 makes it a crime for any person to knowingly and willingly to make to any Agency or Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
Name of Respondenl
Avista Corporation
This Reoort ls:(1) 5]Rn Orlsinat(2) T-.1A Resubmission
Date of Report(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
End of 20131Q4
LIST OF SCHEDULES (Electric Utility)
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".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
1 General lnformation 10'1
2 Control Over Respondent 102 N/A
3 Corporations Controlled by Respondent '103
4 Officers 104
5 Directors 105
6 lnformation on Formula Rates 1 06(aXb)
7 lmportant Changes During the Year 1 08-1 09
8 Comparative Balance Sheet 110-113
o Statement of lncome for the Year '114-117
10 Statement of Retained Earnings for the Year 118-119
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 't22-123
13 Statement of Accum Comp lncome, Comp lncome, and Hedging Activities 122(a)(b)
14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 N/A
16 Electric Plant in Service 204-207
17 Electric Plant Leased to Others 213 N/A
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utility Plant 219
21 lnvestment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab)N/A
24 Extraordinary Property Losses 230 N/A
25 Unrecovered Plant and Regulatory Study Costs 230 N/A
26 Transmission Service and Generation lnterconnection Study Costs 231
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 Accumulated Deferred lncome Taxes 234
30 Capital Stock 250-251
31 Other Paid-in Capital 253
32 Capital Stock Expense 254
33 Long-Term Debt 256-257
34 Reconciliation of Reported Net lncome with Taxable lnc for Fed lnc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Defened lnvestment Tax Credits 266-267
FERC FORM NO.1 (ED.12-96)Page 2
Name of Respondent
Avista Corporation
This Reoort ls:(1) p!An originat(2) nA Resubmission
Date of Reporl(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
End of 20131Q4
LIST OF SCHEDULES (Electric Utility) (continued)
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 I'none," "not applicable," or "NA".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37 Other Deferred Credits 269
38 Accumulated Deferred lncome Taxes-Accelerated Amortization Property 272-273 N/A
39 Accumulated Deferred I ncome Taxes-Other Property 274-275
40 Accumulated Deferred lncome Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Electric Operating Revenues 300-301
43 Regional Transmission Service Revenues (Account 457.1)302 N/A
44 Sales of Electricity by Rate Schedules 304
45 Sales for Resale 31 0-31 1
46 Electric Operation and Maintenance Expenses 320-323
47 Purchased Power 326-327
48 Transmission of Electricity for Others 328-330
49 Transmission of Electricity by ISO/RTOs 331 N/A
50 Transmission of Electricity by Others 332
51 Miscellaneous General Expenses-Electric 335
52 Depreciation and Amortization of Electric Plant 336-337
53 Regulatory Commission Expenses 350-351
54 Research, Development and Demonstration Activities 352-353
55 Distribution of Salaries and Wages 354-355
56 Common Utility Plant and Expenses 356
57 Amounts included in ISO/RTO Settlement Statements 397 N/A
58 Purchase and Sale of Ancillary Services 398
59 Monthly Transmission System Peak Load 400
60 Monthly ISO/RTO Transmission System Peak Load 400a N/A
6't Electric Energy Account 401
62 Monthly Peaks and Output 401
63 Steam Electric Generating Plant Statistics 402403
64 Hydroelectric Generating Plant Statistics 406407
65 Pumped Storage Generating Plant Statistics 408409 N/A
66 Generating Plant Statistics Pages 41041'.!
FERC FORM NO. 1 (ED.12-96)Page 3
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An Orisinal(2) T-1A Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
YearPenoo oI Kepon
End of 20131Q4
LIST OF SCHEDULES (Eleclric Utility) (continued)
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".
Line
No.
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
67 Transmission Line Statistics Pages 422423
68 Transmission Lines Added During the Year 424425
69 Substations 426427
70 Transactions with Associated (Affiliated) Companies 429
71 Footnote Data 450
Stockholders' Reports Check appropriate box:
I Two copies will be submitted
E tto annual report to stockholders is prepared
FERC FORM NO.1 (ED.12-96)Page
Name of Respondent
Avista Corporation
This Report ls:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20'tstQ4
GENERAL INFORMATION
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.
C. Burmeist,er-SmLth, Vice Preeident, Controller, and Prlncipal Accountlng Offlcer
1411 E. Miesion Avenue
Spokaae, WA 99207
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
lf incorporated under a special law, give reference to such law. lf not incorporated, state that fact and give the type
of organization and the date organized.
SEate of Waehlngton, fncorporated March 15, 1889
3. lf 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.
Not Applicable
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
ElecE.ric eervlce in the BEaEes of waEhlngtoa, Idabo, and Montana
Natural gas eervlce ln the ataEea of Waalngtoa, Idaho, and Oregon
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) n Yes...Enter the date when such independent accountant was initially engaged:
(2) E No
FERC FORM No.'l (ED.12-87)PAGE 101
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An orisinal(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
ORPORATIONS CONTROLLED BY RESPONDENT
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, lf control ceased prior to end of year, give particulars (details) in a footnote.
2. lf 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. lf 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. lndirect 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.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
1 Avista Capital, lnc.Parent company to the 100
2 Company's subsidiaries.
3
4 Ecova, lnc.Provider of utility bill 80.2 Subsidiary of
5 processing, payment and Avista Capital
6 information services to multi
7 site customers in North Amer.
8
9
10 Avista Developmenl, lnc Maintains an investment 100 Subsidiary of
11 portfolio of real estate and Avista Capital
12 other investments.
13
14 Avista Energy, lnc lnactive 100 Subsidiary of
15 Avista Capital
16
17 Pentzer Corporation Parent company of Bay Area 100 Subsidiary of
18 Manufacturing and Pentzer Avista Capital
19 Venture Holdings.
20
21 Pentzer Venture Holdings lnactive 100 Subsidiary of
22 Pentzer Corporation
23
24 Bay Area Manufacturing Holding Company 100 Subsidiary of
25 Pentzer Corporation
26
27 Advanced Manufacturing and Development, lnc.Performs custom sheet metal 82.95 Subsidiary ol
FERC FORM NO. t (ED.12-96)Page 103
Name of Respondent
Avista Corporation
This ReDort ls:(1) 5]An orisinal(2| nA Resubmission
uale or Kepon(Mo, Da, Y0
0411112014
Year/Period of Report
2013to.4End of
CORPORATIONS CONTROLLED BY RESPONDENT
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. lf control ceased prior to end of year, give particulars (details) in a footnote.
2. lf 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. lf 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. lndirect 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.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
1 dba Metalfx manufacturing of electronic Bay Area
2 enclosures, parts and systems Manufacturing.
3 for the computer, telecom and
4 medical industries. AM&D
5 also has a wood products
b division.
7
I Spokane Energy, LLC Owns an electric capactiy 100 Affiliate of
9 contract.Avista Corp.
10
11 Avista Capital ll An affiliated business trust 100 Affliate of
12 formed by the Company.Avista Corp.
13 lssued Pref. Trust Securities
14
15 Avista Northwest Resources, LLC Formed in 2009 to own 100 Affiliate of
16 an interest in a venture Avista Capital
17 fund investment
18
19 Steam Plant Square, LLC Commercial office and retail 85 Affiliate of
20 leasing.Avista Development
21
22 Courtyard Ofiice Center, LLC Commercial office and retail 100 Affiliate of
23 leasing.Avista Development
24
25 Steam Plant Brew Pub, LLC Restaurant operations 85 Affiliate of Steam
26 Plant Square, LLC
27
FERC FORM NO.1 (ED.12-96)
Name oI Kesponoenl
Avista Corporation
This Reoort ls:(1) 5]nn orisinat(2) l-lA Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
CORPORATIONS CONTROLLED BY RESPONDENT
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. lf control ceased prior to end of year, give particulars (details) in a footnote.
2. lf 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. lf 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. lndirect 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 lhe
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.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
1 Alaska Merger Sub, lnc.Merger company formed to 100 Subsidiary of
2 effect the merger transaction Avista Corp.
3 with Alaska Energy and
4 Resources Company
5
5 Salix, lnc.Liquified natural gas 100 Subsidiary of
7 operations Avista Capital
8
o
10
11
12
13
14
15
16
't7
'18
19
20
21
22
23
24
25
26
27
FERC FORM NO.1 (ED.12-96)Page '|03.2
This Page Intentionally Left Blank
Name ol Hesponc,ent
Avista Corporation
tnrs
(1)
(2)
Keoon ts:
fiAn original
nA Resubmission
uate or Hepon(Mo, Da, Yr)
04t1112014
YearPenoq oI Kepon
End of 2013/Q4
OFFICERS
1. Report below the name, title and salary for each executive offlcer 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. lf 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.
Ltne
No.
Trtle
(a)
Name oI unrcer
(b)
oatatv
for Yedr(c)
1 Chairman of the Board, Presidenl S. L. Morris
2 and Chief Executive Officer
3
4 Senior Vice President, Chief Financial Officer,M. T. Thies
5 and Treasurer (effective 112013)
b
7 Senior Vice President, General Counsel M. M. Durkin
8 and Chief Compliance Officer
9
0 Senior Vice President and Corporate Secretary K. S. Feltes
1 responsible for Human Resources
2
3 Senior Vice President and Environmental D. P. Vermillion
14 Compliance Officer, President of Avista Utilities
15
16 Vice President, Controller, and C. M. Burmeister-Smith
17 Principal Accounting Officer
18
19 Vice President, Chief lnformation Officer, and J. M. Kensok
20 Chief Security Officer (effective 5/2013)
21
22 Vice President, responsible for Energy Delivery D. F. Kopczynski
23 and Customer Service
24
25 Vice President and Chief Counsel for Regulatory D. J. Meyer
26 and Governmental Affairs
27
28 Vice President, responsible for State and Federal K. O. Norwood
29 Regulations
30
31 Vice President and Chief Strategy Officer R. D. Woodworth
32
33 Vice President, responsible for Energy Resources J. R. Thackston
34 (effective 112013)
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (ED.12-96)Page 104
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]en Originat(2) 1-1A Resubmission
Date of Reoort(Mo, Da, Yi)
04t11t2014
Year/Period of Report
End of 2013tQ4
DIRECTORS
1. Report below the information called for concerning each director of the respondent who held office at any time during the year, lnclude in column (a), abbrevialed
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.
Lltte
No.Name (ano
)r
me) 0I urreclor Pnncroal tsusrness Aooress' (b)
1 Scott L. Morris**1411 E Mission Ave., Spokane, WA, 99202
2 (Chairman of the Board, President & CEO)
3
4 Erik J. Anderson 3720 Carillon Point, Kirkland, WA 98033
5
6 Kristianne Blake***P.O. Box 28338, Spokane, WA 99228
7
8 Donald C. Burke '16 lvy Court, Langhorne, PA 19047
I
10 Rick R. Holley 999 Third Ave., Suite 4300, Seattle, WA 98104
'11
12 John F. Kelly**'851 Georgia Ave., Winter Park, FL 33143
13
14 Michael L. Noel (retired from Board 512013)11960 W, Six Shooter Rd., Prescott, AZ 86305
15
16 Heidi B. Stanley P.O. Box 2884, Spokane, WA 99220
17
18 R. John Taylor*'.111 Main Street, Lewiston, lD 83501
19
20 Marc F. Racicot 28013 Swan Cove Dr., Big Fork, MT 5991 1
21
22 Rebecca A. Klein 61 1 S. Congress Ave., Suite 125, Austin, TX 78704
23
24
25
26
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28
29
30
31
32
33
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FERC FORM NO.1 (ED.12-9s)Page 105
Name of Respondent
Avista Corporation
This Rer(1)E(2)-
rort ls:
I An OriginalI A Resubmission
Date of Report(Mo, Da, Y0
04t't1t?014
Year/Period of Report
gp6 e1 2013/Q4
INFORMA I ION ON FORMULA RA I ES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent have formula rates?! Yes
ENo
'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.
Ltne
No.FERC Rate Schedule or Tariff Number FERC Proceeding
1
2
3
4
5
6
7
8
I
10
11
12
13
14
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FERC FORM NO.1 (NEW.12-08)Page 106
Name oI Kesponoenl
Avista Corporation
tnts Keoon ls:
(1) El An orisinal
(2) n A Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
INFORMATION ON FORMULA MTES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)
filings containing the inputs to the formula rate(s)?I Yes
ENo
2. lf yes, provide a listing of such filings as contained on the Commission's eLibrary website
Line
No,Accession No.
Document
Date
\ Filed Date Docket No.Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
1
2
3
4
5
6
7
8
I
10
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FERC FORM NO. 1 (NEW.12-08)Page 106a
Name or Kesponoenl
Avista Corporation
This Reoort ls:(1)E An Original
(2) - A Resubmission
Date of Report(Mo, Da, Yr)
o4t11t2014
Yea/Penoo ol Kepon
En6 e1 2013/Q4
INFORMATION ON FORMULA RATES
Formula Rate Variances
1. lf a respondent does not submit such filings then indicate in a footnote to the applicable Form I schedule where formula rate inputs differ.from
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 differfrom 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.
Line
No.Page No(s).Schedule Column Line No
1
2
3
4
5
6
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FERC FORM NO. 1 (NEW.12-08)Page 106b
Name or F{espondent
Avista Corporation
lnrs Hepon ls:(1) E An Original
(2) [ A Resubmission
uare oT Kepon
04t11t2014
Yearrenoo oI Kepoft
End of 20131Q4
IMPORTANT CHANGES DURING THE OUARTER/YEAR
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. lf
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. lf 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. lmportant 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. lmportant 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. lf 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 lnstructions 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. ln 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
eltent 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.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED.12-96)Page
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
2013tQ4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
1. None
2. A merger transaction with Alaska Energy and Resources Company was entered into on November 4,2013;
however, the consummation of the transaction is subject to the satisfaction or waiver of specified closing
conditions. Refer to Note 3 of the Notes to Financial Statements for further details regarding this merger
transaction.
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 with an expiration date of February 2017. 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.
Balances outstanding under the Company's revolving committed line of credit were as follows as of December
31,2013 and December 31, 2012 (dollars in thousands):
December 31, December 31,
2013 2012
Balance outstanding at end of period
Letters of credit outstanding at end of period
$ 171 ,000 $52,000
$27,434 $35,885
In August 2013, Avista Corp.entered into a $90.0 million term loan agreement with an institutional investor
that bears an annual interest rate of 0.84 percent and matures in 2016. The term loan agreement is secured by
non-transferable First Mortgage Bonds of the Company issued to the agent bank that will only become due and
payable in the event, and then only to the extent, that the Company defaults on its obligations under the term
loan agreement. The net proceeds from the $90.0 million term loan agreement were used to repay a portion of
corporate indebtedness in anticipation of $50.0 million in First Mortgage Bonds that matured in December
2013. The debt issuance was approved by regulatory commissions as follows:WUTC (Docket No. U-l lll76
Order 02) IPUC (Case No. AVU-U-11-01 Order No. 32338) and the OPUC (Docket UF 4269 Order No.
1 1-334).
7. None
8. Average annual wage increases were 2.2o/o for non-exempt employees effective February 25,2013. Average
annual wage increases were 2.8Yofor exempt employees efFective February 25,2013. Officers received average
increases of 5.5Yo effective February 25,2013. Certain bargaining unit employees received increases of 3.0%
effective March 26, 2013.
9. Reference is made to Note 17 of the Notes to Financial Statements.
10. None
11. Reserved
12. See page 123 of this report.
13. Michael L. No€I, a director of Avista Corporation (Avista Corp. or the Company) whose term expired on
May 9, 2013, retired from Avista Corp.'s Board of Directors as he has reached the mandatory retirement age of
72 as outlined in the Company's Bylaws.
FERC FORM NO.1 1 Page 109.1
Name of Respondent
Avista Corporation
This Report is:
(1) XAn OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
20131Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
On February 11,2014, Rick R. Holley provided notification to the Company that he will not stand for reelection
to Avista Corp.'s Board of Directors and he resigned effective February 15,2014. This is due to the fact that the
time requirements for his board service conflicts with his other professional commitments. He has no
disagreements with the Company.
On February 13,2014, Avista Corp.'s Board of Directors took action to reduce the number of board members
from l0 to 9 effective February 15,2014.
Effective January 2014, Jason R. Thackston was promoted to Senior Vice President. He has been Vice President
of Energy Resources since December 2012.
14. Proprietary capital is not less than 30 percent.
FERC FORM NO.1 Paoe 109.2
Name of Respondent
Avista Corporation
This Report ls:
(1) X An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2013tQ4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balance
12t31
(d)
UTLIry PLANT
2 Utility Plant (101-1 06, 1 14)200-201 4,280,005,611 4,044,184,930
3 Construction Work in Progress ('107)200-201 157,258,69(139,513,892
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)4,437,264,301 4,183,698,822
5 (Less) Accum. Prov. for Depr. Amort. Depl. (1 08, 1 10, 1 1 1 , 1 15)200-201 1,491,212,83(1,408,153,972
6 Net Utility Plant (Enter Total of line 4 less 5)2,946,051.471 2,775,544,850
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)202-203 0
8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2)0
9 Nuclear Fuel Assemblies in Reactor (120.3)0
10 Spent Nuclear Fuel (120.4)0
11 Nuclear Fuel Under Capital Leases (120.6)0
12 (Less) Accum, Prov. for Amort. of Nucl. Fuel Assemblies (120.5)202-203 0
13 Net Nuclear Fuel (Enter Total of lines 7-1 1 less 12)0
14 Net Utility Plant (Enter Total of lines 6 and 13)2,946,051,471 2,775,544,850
15 Utility Plant Adjustments (1 16)0
16 Gas Stored Underground - Noncurrent (1 '17)6,992,07(6,992,076
17 OTHER PROPERry AND INVESTMENTS
18 Nonutility Property (1 21 )5,438,891 5,536,702
19 (Less) Accum. Prov. for Depr. and Amort. (122)920,90t 921,820
20 lnvestments in Associated Companies (123)12,047,00(12,047,000
21 lnvestment in Subsidiary Companies (123.1)224-225 112,232,101 118,7'.t4,423
22 (For Cost of Account 1 23.1 , See Footnote PaSe 224, line 42)
23 Noncurrent Portion of Allowances 228-229 0
24 Other lnvestments (1 24)13,980,63r 16,439,055
25 Sinking Funds (125)0
26 Depreciation Fund (1 26)0
27 Amortization Fund - Federal (127)0
28 Other Special Funds (128)10,897,90(9,154,874
29 Special Funds (Non Maior Only) (129)0
30 Long-Term Portion of Derivative Assets ( 1 75)853,75;1,092,593
31 Long-Term Portion of Derivative Assets - Hedges (176)19,574,85t 7,265,426
32 TOTAL Other Property and lnvestments (Lines 18-21 and 23-31)174,104,251 169,328,253
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-maior Only) (130)0
35 Cash (131)3,949,46!2,624,516
36 Special Deposits (1 32-1 34\19,283,08i 2,716,333
37 Working Fund (135)864.09i 799,065
38 Temporary Cash lnvestments (136)251,390
39 Notes Receivable (141)234,901
40 Customer Accounts Receivable (1 42)182,617,38t 159,703,153
41 Other Accounts Receivable (143)8,417,171 5,188,679
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144)4,830,03(4,653,167
43 Notes Receivable from Associated Companies (145)5,720,83t 314,682
44 Accounts Receivable from Assoc. Companies (146)286,69(700,835
45 Fuel Stock (151)227 3,170,05(4,120,767
46 Fuel Stock Expenses Undistributed (152)227 0
47 Residuals (Elec) and Extracted Products (153)227 0
48 Plant Materials and Operating Supplies (154)227 26,655,71C 23,875,397
49 Merchandise (155)227 0
50 Other Materials and Supplies ( 1 55)227 0
51 Nuclear Materials Held for Sale (157)202-203t227 0
52 Allowances (158.1 and 158.2)228-229 0
FERC FORM NO. 1 (REV. 12-03)Page 110
Name of Respondent
Avista Corporation
This Report Is:
(1) tr An Original
(2) n A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2013/Q4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBlTslcontinued)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balance
12t31
(d)
53 (Less) Noncurrent Portion of Allowances 0
54 Stores Exoense Undistributed (1 63)227 0
55 Gas Stored Underground - Current (164.1)1 3,028,71('t7.276.287
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.31 0
57 Prepayments (165)7.938.05(16.090,480
58 Advances for Gas (166-167)0
59 lnterest and Dividends Receivable (171)30,98'31,981
60 Rents Receivable (172\1,360,26'830,718
61 Accrued Utility Revenues (173)0
62 Miscellaneous Current and Accrued Assets (174)752,95:429,169
63 Derivative lnstrument Assets (1 75)3,875,26!5,231,375
64 (Less) Long-Term Portion of Derivative lnstrument Assets (175)853,75i 1,092,593
65 Derivative lnstrument Assets - Hedqes (176)33,544,58t 7,265.426
66 (Less) Long-Term Portion of Derivative lnstrument Assets - Hedges (176 19,574,85t 7,265,426
67 Total Current and Accrued Assets (Lines 34 through 66)286,236,661 234,673,968
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (18'l)1 2,505,1 3r 13,532,890
70 Extraordinary Property Losses (1 82. 1 )230a 0
71 Unrecovered Plant and Resulatory Study Costs ('182.2)230b 0
72 Other Regulatory Assets (182.3)232 381,581,93!559,831,454
73 Prelim. Survey and lnvestigation Charges (Electric) (183)875,1 5:3,894,551
74 Preliminary Natural Gas Survey and lnvestigation Charges 183.1 0
75 Other Preliminary Survey and lnvestigation Charges (183.2)0
76 Clearing Accounts (1 84)0
77 Temporary Facilities (1 85)0
78 Miscellaneous Deferred Debits ('l 86)233 13,312,292 15.701 ,369
79 Def. Losses from Disposition of Utility Plt. (187)0
80 Research, Devel. and Demonstration Expend. (188)3s2-353 o
81 Unamortized Loss on Reaquired Debt (189)19,417,10:21,635,414
82 Accumulated Deferred lncome Taxes (190)234 70,239,42i 148.425.469
83 Unrecovered Purchased Gas Costs (191)-12.074,78(-6,916,577
84 Total Deferred Debits (lines 69 through 83)485,856,26:756.104,570
85 TOTALASSETS (lines 14-16,32,67, and 84)3.899,240,724 3,942,il3,717
FERC FORM NO. 1 (REV. 12-03)Page 111
Name of Respondent
Avista Corporation
This Report is:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(mo, da, yr)
04t11t2014
Year/Period of Report
end of 2o13tQ4
coMPARAT|VE BALANCE SHEET (LtABrLtTlES AND OTHER CREDTTS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarterl/ear
Balance
(c)
Prior Year
End Balance
12t31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock lssued (201)250-251 869,342,82',863,316,222
3 Prefened Stock lssued (204)250-25',!0
4 Capital Stock Subscribed (202, 205]1 0
5 Stock Liability for Conversion (203, 206)0
6 Premium on Capital Stock (207)0
7 Other Paid-ln Capital (208-21 1)253 8,089.02a 10.942.942
8 lnstallments Received on Capital Stock (212)252 0
I (Less) Discount on Capital Stock (213)254 0
10 (Less) Capital Stock Expense (2'14)254b -19,561 ,52i -14,977,565
11 Retained Earnings (21 5, 21 5.1, 216)118-119 413,009,87:377,687,824
12 Unappropriated Undistributed Subsidiary Earnings (216.1 )1't8-1 19 -5,918,02r -747,337
13 (Less) Reaquired Capital Stock (217)250-251 0
14 Noncorporate Proprietorship (Non-major only) (21 8)0
15 Accumulated Other Comprehensive lncome (219)122(a)(b)-5,819,93(-6.700,160
16 Total Proprietary Capital (lines 2 through 15)1.298.265.29t 1,259,477,056
17 LONG.TERM DEBT
18 Bonds (221)256-257 1,376,700,00(1,336,700,000
19 (Less) Reaquired Bonds (222)256-257 83,700,00(83,700,000
20 Advances from Associated Companies (223)256-257 51,547,00(51.547.000
21 Other Long-Term Debt (224)256-257 0
22 Unamortized Premium on Long-Term Debt (225)195,43:204,316
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226)1.482.641 1,656,685
24 Total Long-Term Debt (lines 18 throuqh 23)1,343,259,78S 1,303,094,631
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncunent (227)4,193,85i 4,491,191
27 Accumulated Provision for Property lnsurance (228.1)0
28 Accumulated Provision for lnjuries and Damages (228.2)240.00(700,447
29 Accumulated Provision for Pensions and Benefits (228.3)122.512.892 283,984,764
30 Accumulated Miscellaneous Operating Provisions (228.4)0
31 Accumulated Provision for Rate Refunds (229)2,489,68€0
32 Lonq-Term Portion of Derivative lnstrument Liabilities 18,355,04C 26,310,290
33 Long-Term Portion of Derivative lnstrument Liabilities - Hedqes 0
34 Asset Retirement Obligations (230)2,847,20i 3,167,935
35 Total Other Noncurrent Liabilities (lines 26 through 34)150,638,67;318,654,628
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)171 ,000,00(52,000,00c
38 Accounts Payable (232)107,675,81 !116,147,642
39 Notes Payable to Associated Companies (233)598
40 Accounts Payable to Associated Companies (234)810,91 1 709,623
41 Customer Deposits (235)3,393,26!3,323,152
42 Taxes Accrued (236)262-263 22,103,801 22,309,642
43 Interest Accrued (237)13,444,06t 12,038,698
44 Dividends Declared (238)0
45 Matured Long-Term Debt (239)0
FERC FORM NO. 1 (rev.12-03)Page 112
Name of Respondent
Avista Corporation
This Report is:
(1) tr An Original
(2) l-l A Resubmission
Date of Report
(mo, da, yr)
04t1112014
Year/Period of Report
end of 20131Q4
COMPARATIVE BALANCE SHEET (LlABlLlTlES AND OTHER CRED|T@ntinued)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of QuarterfYear
Balance
(c)
Prior Year
End Balance
12t31
(d)
46 Matured lnterest (240)c
47 Tax Collections Payable (241)115.21a 120,427
48 Miscellaneous Current and Accrued Liabilities (242)55,243,46i 61,331,657
49 Obligations Under Capital Leases-Current (243)297.33(258,58€
50 Derivative lnstrument Liabilities (244)29,230,05!55,825,491
51 (Less) Lonq-Term Portion of Derivative lnstrument Liabilities 18,355,041 26,3'10,29C
52 Derivative Instrument Liabilities - Hedges (245)1 .433.1 6C
53 (Less) Lonq-Term Portion of Derivative lnstrument Liabilities-Hedses c
54 Total Current and Accrued Liabilities (lines 37 through 53)384,958,89t 299,1 88,386
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)1 ,459,1 1 947,342
57 Accumulated Deferred lnvestment Tax Credits (255)266-267 12,387,031 12,6'13,058
58 Deferred Gains from Disposition of Utility Plant (256)c
59 Other Deferred Credits (253)269 25,359,33:26,169,96€
60 Other Regulatory Liabilities (254)278 71,742,33(55,244,962
61 Unamortized Gain on Reaquired Debt (257)2,225,581 2,355,11
62 Accum. Deferred I ncome Taxes-Accel. Amort. (281 )272-277 c
63 Accum. Defened lncome Taxes-Other Property (282)447,'.t00,23!419,216,613
64 Accum. Defened lncome Taxes-Other (283)161 ,844,431 245,681,957
65 Total Defened Credits (lines 56 through 64)722,118,061 762,229,Ue
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65)3,899,240,724 3,942,643.717
FERC FORM NO. 1 (rev. 12-03)Page 113
Name of Respondent
Avista Corporation
This Reoort ls:(1) fiAn Original(2) 1-1A Resubmission
Date of Report(Mo, Da, Yr)
o4t'11t2014
Year/Period of Report
End of 20131Q4
STATEMENT OF INCOME
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 O 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. lf 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 4'1 3, 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 25 as appropriate. lnclude these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating lncome, in the same manner as accounts 4'12 and 413 above.
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
I olat
Cunent Year to
Date Balance for
Quarterffear
(c)
I OIat
Prior Year to
Date Balance for
Quarterffear
(d)
UUNCNI J MONINS
Ended
Quarterly Only
No 4th Quarter
(e)
PNOT J MONINS
Ended
Quarterly Only
No 4th Quarter
0
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 1,574,987,368 1,494,227,54C
3 Operating Expenses
4 Operation Expenses (401)320-323 1,0s4,508,447 1,051,630,004
5 Maintenance Expenses (402)320-323 60,947,443 61,377,56t
6 Depreciation Expense (403)336-337 105,822,752 102,188,31'
7 Depreciation Expense lor Asset Retirement Cosb (403.1 )336-337
8 Amort. & Depl. of Utility Plant (404405)336-337 't3,800,8s3 12,353,38i
I Amort, of Utility Plant Acq. Adj. (406)336-337 99,047 99,047
10 Amort. Propery Losses, Unremv Plant and Regulatory Study Cosb (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debib (407.3)12,986.972 s,612,331
13 (Less) Regulatory Credits (407.4)13,582,146 24,170,474
14 Taxes OtherThan lnmme Taxes (408.1)262-263 88,262,771 83,263,801
15 lncome Taxes - Federal (409.1)262-263 39,972,039 '14,435,55t
16 - CIher (409.1)262-263 2,066,338 379,91 1
17 Provision for Defened lncome Taxes (a10,1)234,272-277 3't,154,269 3s,782,46(
18 (Less) Provision for Defened lncome Taxes€r. (411.1)234,272-277 4,770,686 4,224,554
19 lnvestment Tax Credit Adj. - Net (411.4)266 -238,869 2,073Jle
20 (Less) Gains from Disp. of Utility Plant (4'11.6)
21 Losses from Disp. of Utility Plant (41 1.7)
22 (Less) Gains from Disposition of Allowances (4'l 1.8)
23 Losses from Disposition of Allowances (41 1.9)
24 Accretion Expense (41 1.1 0)
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)1,391 ,029,23(1,340,800,4s7
26 Net Util Oper lnc (Enter Tot line 2 less 25) Cany to P9117 ,line27 183,958,13t 153,427,083
FERC FORM NO. 1/3-Q (REV. 02-04)Page 114
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An Orisinat(2) J-1A Resubmission
Date of Report(Mo, Da, Yr)
o4111t2014
YeariPeriod of Report
End of 2O13lQ4
STATEMENT OF INCOME FOR THE YEAR (Continued)
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.
1'1 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. lf any notes appearing in the report to stokholders are applicable to the Statement of lncome, such notes may be included al 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. lf the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY
Line
No.Current Year to Date
(in dollars)
(s)
Previous Year to Date
(in dollars)
(h)
Current Year to Date
(in dollars)
(i)
Previous Year to Date
(in dollars)
0)
ourrent Year t0 uate
(in dollan)
(k)
Frevtous Y ear Io uale
(in dollars)
(t)
1,049,456,902 1 ,017,91 6,105 525,530,466 476,311,435 2
635,615,026 664,363,922 418,893,421 387,266,082 4
48,867,669 50,481,432 't2,079,774 1 0,896,1 36 E
84,631,445 83,017,204 21,191,307 '19,171,108 6
7
10,778,960 9,725,903 3,021,893 2,627,479 8
99,047 99,047 I
'10
1'.!
12,125,143 4,61 8,1 60 861,829 994,171 12
13,080,536 22,537,730 501,610 1.632.744 13
66,342,004 62,217,029 21.920.767 21,046,772 14
31,663,448 16,824,429 8.308,591 -2,388,871 15
'1,388,109 432,992 678,229 -53,081 16
25,700.222 24,012,637 5,454,047 11,769,829 17
4,871.648 4.120.508 -100,962 104,047 18
-1 99,1 1 3 2,1 1 5,1 66 -39,756 42,060 19
20
21
22
23
24
899,059,776 891,249,683 491,969,454 449,550,774 25
1 50,397, t 26 126,666,422 33,561 ,012 26,760,661 26
FERC FORM NO. 1 (ED.12-96)Page 1't5
Name of Respondent
Avista Corporation
This Reoort ls:(1) []An orisinal(2) l-lA Resubmission
Date of Report(Mo, Da, Y0
04t11t2014
Year/Period of Report
End of 20131Q4
STATEMENT OF INCOME FOR 'HE YEAR (continued)
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
TOTAL uurent J Monlns
Ended
Quarterly Only
No 4th Quarter
(e)
Hnor J Monms
Ended
Quarterly 0nly
No 4th Quarter
(0
Current Year
(c)
Previous Year
(d)
27 Net Utility Operating lncome (Canied forward from paqe 'l l4)1 83,958,1 38 153,427,08i
28 Other lncome and Deductions
29 Other lncome
30 Nonutilty Operatinq lncome
31 Revenues From Merchandisinq, Jobbing and Contract Work (415)
32 lLess) Costs and Exp. of Merchandisinq, Job, & Contract Work (416)
33 Revenues From Nonutility Operations (417)-13,172 -236 |
34 ILess) Expenses of Nonutility Operations (4'17.'l 10,644,78!8,415,8591
35 Nonoperating Rental lncome (418)-3,699 -2.749l,
36 Equity in Eaminqs of Subsidiary Companies (418.1)119 4,593,239 -1,206,861
37 lnterest and Dividend lnmme {419}2,432,397 1,864,293 |
38 Allowance for Other Funds Used During Construction (419.'l)6,065,62[4,054,9471
20 Miscellaneous Nonoperating lncome (421)
40 Gain on Disposilion of Property (42'1.1
4',!TOTAL Oher lncome (Enter Total of lines 31 thru 40)2,429,604 -3,706,4651
42 Other lncome Deductions
43 Loss on Disposition of Property (421.2)
44 Miscellaneous Amortization (425)
45 Donations (426,'l)3,320,437 2,272,123t
46 Lile lnsurance (426.2)2,599,89€2,s33,5521
47 Penalties (426.3)109,224 15,251
48 Exp. for Certain Civic, Political & Related Activities (426.4)1,605,67i 1,414,3381
49 Other Deductions (426.5)4,366,47i 1,815,3261
50 TOTAL Other Income Deduclions ffiotal of lines 43 thru 49)12,001,711 8,050,590 |
51 Taxes Applic. to Other lnmme and Deductions
52 Taxes Other Than lncome Taxes (408.2)262-263 172,447 145,2131
53 lncome Taxes-Federal (409.2)262-263 481,927 106.9651
54 lncome Taxes-Other (409.2)262-263 -'1,004,51!-1 ,231 ,4561
55 Provision for Defened lnc. Taxes (410.2)234,272-277 -1 ,731,43!-520.7181
56 (Less) Provision for Defened lncome Taxes-Cr. (41 1.2)234,272-277 5,632,031 5j90,7421
57 lnvestment Tax Credit Adj.-Net (411.5)
58 (Less) lnveslment Tax Credits (420)
59 TOTAL Taxes on Other lncome and Deductions (Total of lines 52-58){,677,46!-6,690,7381
60 Net Other lncome and Deduclions (Total of lines 41, 50, 59)-894.63t -5,066,317
6't lnterest Charges
62 lnterest on Lono-Term Debt {427)68,485,49a 65,281,624
bJ Amort. of Debt Disc. and Expense (428)448,32t 447,351
64 Amortization of Loss on Reaquired Debt (428.'l)3,373,538 3,364,150 |
65 (Less) Amort. of Premium on Debt-Credit (429)8,88:8,8831
66 (Less) Amortization of Gain on Reaquired DebtOredit (429.1)
67 lnterest on Debt to Assoc. Companies (430)750,51i 885,123 I
68 Other lnterest Expense (431)2,613,46:2.582.407
69 ILess) Allowance for Bonowed Funds Used Durino Construction-Cr. (432)3,675,78(2,401,0721
70 Net lnterest Charges (Total of lines 62 thru 69)71,986,667 70.1 50,7001
71 lncome Before Extraordinary ltems fTotal of lines 27, 60 and 70)11 1,076,833 78,210,0661
72 Extnordinary ltems
73 Extraordinarv lncome (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary ltems (Total of line 73 less line 74)
76 lncome Taxes-Federal and Other (409.3)262-263
77 Extraordinary ltems After Taxes (line 75 less line 76)
78 Net lncome (Total of line 71 aod77\1 1 1,076,833 78,210,0661
FERC FORM NO. 1/3-Q (REV. 02-04)Page
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
0411'U2014
YearHenoo ot Kepon
End of 2013/Q4
STATEMENT OF RETAINED EARNINGS
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. lf 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. lf any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
\ccount Affected
(b)
Current
QuarterfYear
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAI NED EARNI NGS (Account 2 1 6)
I Balance-Beqinning of Period 376,1 39,703 362,988,164
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
6
7
I
I TOTAL Credits to Retained Earnings (Acct. 439)
1C
1'.!
12
13
14
15 TOTAL Debits to Retained Earnings (Acct.439)
16 Balance Transferred from lncome (Account 433 less Account 4'18.'l)98,317,714 79,4'.t6,927
17 Appropriations of Retained Earnings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
2a
2G
2t
2t
2l TOTAL Dividends Declared-Preferred Stock (Acct. 437)
3(Dividends Declared-Common Stock (Account 438)
31 -73,276,102 ( 68,552,375)
5t
aa
3t
2a
3(TOTAL Dividends Declared-Common Stock (Acct. 438)-73,276,102 ( 68,552,375)
3i Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 2,114,557 2,286,987
3t Balance - End of Period Ootal 1,9,15,16,22,29,36,37)403,295,872 376,139,703
APPROPRIATED RETAINED EARNINGS (Account 215)
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent
Avista Corporation
This Reoort Is:(1) 5]Rn originat(2) nA Resubmission
uale ot Hepon(Mo, Da, Yr)
04t11t2014
YealYeloo ot Kepon
End of 2013tQ4
STATEMENT OF RETAINED EARNINGS
't. D(
2.R
undir
3.E
- 43S
4.S
5. Li
by cr
6.S
7.S
8.E
recul
9. rf
r not report Lines 49-53 on the quarterly version.
eport all changes in appropriated retained earnings, unappropriated retained eamings, year to date, and unappropriated
;tributed subsidiary earnings for the year.
ach credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
I inclusive). Show the contra primary account affected in column (b)
tate the purpose and amount of each reservation or appropriation of retained earnings.
st first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
edit, then debit items in that order.
how dividends for each class and series of capital stock.
how separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
xplain in a footnote the basis for determining the amount reserved or appropriated. lf such reservation or appropriation is to be
'rent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Line
No.
Item
(a)
Contra Primary
\ccount Affected
(b)
Current
Quarter/Year
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
tc 9.714,001 1,548,121
4C
41
42
43
44
4a TOTAL Appropriated Retained Earninqs (Account 215)9,714,00'l 1,548,121
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
4e TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 21 5. 1 )
47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) Ctotal 45,46)9.7'14.001 1,548,121
48 TOTAL Retained Earninqs (Acct. 215, 215.1,216\ (Total 38, 47) (216.1)413,009,873 377,687,824
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)-747,337 28,386,302)
5C Equity in Earnings for Year (Credit) (Account 418.1)4,593,239 ( 1 ,206,861)
51 (Less) Dividends Received (Debit)
52 Equity Transactions of subsidiaries -9,763,926 28,84s,826
53 Balance-End of Year (Total lines 49 thru 52)-5,918,024 ( 747,337\
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t't1t2014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
P : 118 Line No.: 16 Column: c
The balance transferred from income to unapprorpriated retained earnings does not equal net income less subsidiary
earnings in the current year because a portion of net income for the current year was recorded to 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 hydro projects. The rate of return on investment is specified in the
various hydroelectric licensing agreements for the Clark Fork River and Spokane River. 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.
FERC FORM NO.1 .12-87 450.1
This Page Intentionatly Left Blank
Name of Respondent
Avista Corporation
This Reoort ls:(1) E]An original(2) nA Resubmission
Date of Report(Mo, Da, Y0
04t11t2014
Year/Period of Report
End of 20131Q4
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt: (c) lnclude commercial paper; and (d) ldentify separately such items as
investments, fixed assets, intangibles, etc.
Equivalents at End of Period'' with related amounts on the Balance Sheet.
in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
UUTTENI YEAT IO UAIE
QuarterfYear
(b)
Previous Year to Date
QuarterfYear
(c)
1 Net Cash Flow from Operating Activities:
2 Net lncome (Line 78(c) on page 117)111,076.833 78,210,066
3 Noncash Charges (Credits) to lncome:
4 Depreciation and Depletion 117,173,574 1 't2,091 ,663
5 Amortization of deferred power and natural gas costs -9,407,533 6,702,266
6 Amortization of debt expense 3,812,982 3,802,618
7 Amortization of investment in exchange power 2,450,031 2,450,031
8 Deferred lncome Taxes (Net)20,846,650 19,589,845
I lnvestment Tax Credit Adjustment (Net)-226,027 2,212,172
10 Net (lncrease) Decrease in Receivables -30,523,370 12,838,942
11 Net (lncrease) Decrease in lnventory 2,417,981 4,331,613
12 Net (lncrease) Decrease in Allowances lnventory
13 Net lncrease (Decrease) in Payables and Accrued Expenses -4,903,140 31,767,362
14 Net (lncrease) Decrease in Other Regulatory Assets -899,982 -4,674,400
15 Net lncrease (Decrease) in Other Regulatory Liabilities 7,774.282 -4,241 ,041
'16 (Less) Allowance for Other Funds Used During Construction 6,065,628 4,054,947
17 (Less) Undistributed Earnings from Subsidiary Companies 4,593,239 -1,206,861
18 Other (provide details in footnote):4,736,292 17,162,806
19 Allowance for doubtful accounts 4,792,409 3,973,772
20 Changes in other non-current assets and liabilities -7,470,522 -7,388,676
21 Write-off of Reardan wind generation assets 2,533,578
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)204,052,587 275,980,953
23
24 Cash Flows from lnvestment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)-294,363,192 -268,743,1 38
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Planl
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
34 Cash Outflows for Plant Cl-otal of lines 26 thru 33)-294,363,1 92 -268,743,138
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38 Federal grant payments received 3,409,479 8.277.036
39 lnvestments in and Advances to Assoc. and Subsidiary Companies -4,89 t,325 -1 9,1 38,51 0
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of lnvestments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of lnvestment Securities (a)
45 Proceeds from Sales of lnvestment Securities (a)
FERC FORM NO.1 (ED.12-95)Page 120
Name of Respondent
Avista Corporation
lnts Keoon ls:(1) 5]An original(2) nA Resubmission
uale oI Hepon(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long{erm debt; (c) lnclude commercial paper; and (d) ldentify separately such items as
investments, fixed assets, intangibles, etc.
Equivalents at End of Period" with related amounts on the Balance Sheet.
in those activities. Show in the Notes to the Financials the amounts of interesl paid (net of amount capitalized) and income taxes paid.
dollar amount of leases capitalized with the plant cost.
Line
No.
Description (See lnstruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
/b)
Previous Year to Date
QuarterfYear
(c)
46 Loans Made or Purchased
47 Collections on Loans
48 Restricted Cash 481 ,170
49 Net (lncrease) Decrease in Receivables
50 Net (lncrease ) Decrease in lnventory
51 Net (lncrease) Decrease in Allowances Held for Speculation
52 Net lncrease (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote):
54 Changes in other property and investments 6.1 67 4,540,'t98
55
56 Net Cash Provided by (Used in) lnvesting Activities
57 Total of lines 34 thru 55)-295,357,701 -275,064,414
58
59 Cash Flows from Financing Activities:
60 Proceeds from lssuance of:
61 Long-Term Debt (b)90,000,000 80,000,000
62 Prefened Stock
63 Common Stock 4,609,006 29,078,745
64 Other (provide details in footnote):
65
66 Net lncrease in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69)94,609,006 109,078,745
71
72 Payments for Retirement of:
73 Long-term Debt (b)-50,258,586 -l',t,324,884
74 Preferred Stock
75 Common Stock
76 Cther (provide details in footnote):
77 Debt issuance costs -531 ,294 -763,603
78 Net Decrease in Short-Term Debt (c)1 19,000,000 -9,000,000
79 ash received (paid) for settlement of interest rate swap 2,900,680 -18,546,870
80 )ividends on Preferred Stock
8'1 )ividends on Common Stock -73,276,102 -68,552,375
82 tlet Cash Provided by (Used in) Financing Activities
83 lTotal of lines 70 thru 81)92,443,704 891,013
84
85 let lncrease (Decrease) in Cash and Cash Equivalents
86 llotal of lines 22,57 and 83)1 ,1 38,590 1,807,552
87
88 lash and Cash Equivalents at Beginning of Period 3,674,971 1,867,419
89
90 Cash and Cash Equivalents at End of period 4,813,561 3,674,971
FERC FORM NO.1 (ED.12-96)Page
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't1t2014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
chedule : 120 Line No.: 18 Column: b
Power and
Change in
Change in
Non-cash
Cash paid
Change in
natural gas deferralsspecial deposiEsother current assetsstock compensationfor foreign currency
Coyote Springs 2 O&M
hedges
LTSA
1,284 , 946
(1-6,072,800)
7, 300, l_01_
5 ,036 ,659(30 ,27 0)
(1,37 6 ,5L4),(878 ,414)Prelimi and investi tion costs
Power natural gas
Change in special deposj-ts
Change in other current assets
Non-cash stock compensation
Cash received for foreign currency hedges
L,7 04 ,997
g ,7 92 ,264l, ogo ,222
4 ,549 ,448
35, 881
: 120 Line No.:18 Column: c
FERC FORM NO.1 .'12-8 450.1
This Page Intentionally Left Blank
Name ol Respondent
Avista Corporation
rnrs Kepon rs:(1) E An Original
(2) ! A Resubmission
uale oI Kepon
04t1112014
YearHenoo or Kepon
End of 2013/Q4
NOTES TO FINANCIAL STATEMENTS
1. Use the space below for important notes regarding the Balance Sheet, Statement of lncome 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 lnternal 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, and257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General lnstruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restriclions and state the amount of retained earnings affected by such
restrictions.
6. lf 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 sufflcient 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 occuned
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 fumish the data required by the above instructions, such notes may be included herein.
PAGE l22INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO.1 (ED.12-96)Page '|22
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't1t2014
Year/Period of Report
20't3lQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO FINANCIAL STATEMENTS
NOTE I. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, transmission and distribution of
electricity and the distribution of natural gas, as well as other energy-related businesses. Avista Corp. provides electric distribution and
transmission, as well as natural gas distribution, services in parts of eastern Washington and northem Idaho. Avista Corp. also provides
natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Corp. has generating facilities in Washington,
Idaho, Oregon and Montana. The Company also supplies electricity to a small number of customers in Montana, most of whom are
employees who operate one of the Montana generating facilities. Avista Capital, Inc. (Avista Capital), a wholly owned subsidiary of
Avista Corp., is the parent company of all of the subsidiary companies, except Spokane Enerry, LLC (Spokane Enerry). Avista
Capital's subsidiaries include Ecova, Inc. (Ecova), a 80.2 percent owned subsidiary as of December 31,2013. Ecova is a provider of
energy efficiency and other facility information and cost management programs and services for multi-site customers and utilities
throughout North America.
Bash of Reporting
The financial statements include the assets, liabilities, revenues and expenses ofthe Company and have been prepared in accordance
with the accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forttr 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 tlan 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 (l) 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) defened income taxes and (6) comprehensive
income.
Use of Estimates
The preparation of the fu:ancial statements in conformity with accounting principles generally accepted in the United States of
America (U.S. GAAP) requires management to make estimates and assumptions that affect amounts reported in the financial
statements. Significant estimates include:
o determining the market value of enerry commodity derivative assets and liabilities,
o penSion and other postretirement benefit plan obligations,
. contingent liabilities,
. recoverability ofregulatory assets, and
o 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
FERC FORM NO. {1 Page 123.'l
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
o4t1112014
Year/Period of Report
2013to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
prescribed by the Federal Energy Regulatory Commission (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.
Operoting Revenues
Revenues related to the sale of energy are recorded when service is rendered or enerry is delivered to customers. The determination of
the enerry 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.
Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
20t3 2012
Unbilled accounts receivable $ 8 1,059 $ 77 ,298
Advertising Expenses
The Company expenses advertising costs as incurred. Advertising expenses were not a material portion of the Company's operating
expenses in 2013 and2012.
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 3l:
2013 2012
Ratio of depreciation to average depreciable propefty 2.90% 2.92%
The average service lives for the following broad categories of utility plant in service are:
o electric thermal production - 4l years,
. hydroelectric production - 79 years,
o electric hansmission - 56 years,
o electric distribution - 36 years, and
. natural gas distribution property - 48 years.
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 ofproperty. 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 3l (dollars in thousands):
FERC FORM NO.1 .12 123.2
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
20't3tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
2013 2012
Utility taxes $ 55,565 $ 53,716
Allowancefor Funds Used During Constraction
The Allowance for Funds Used During Construction (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 autlorities, AFUDC is capitalized as a part of the
cost of utility plant and the debt related portion is credited against total interest expense in the Statements of Income. The Company is
permitted, rurder 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 3l:
201 3 20t2
Effective AFUDC rate 7.640/o 7.62%
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 defened income tax expense for the period is equal to the net change in the defered 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 as prescribed by the respective regulatory commissions.
Stoc k-B ased Compensation
Compensation cost relating to share-based payment transactions is recognized in the Company's financial statements based on the fair
value of the equiry or liability instruments issued and recorded over the requisite service period. See Note 16 for further information.
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.
Allow ance fo r D o u btfu I A cco unts
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
properly and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is
charged to accumulated depreciation.
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 desigrrated as a hedge for a particular exposure. The accounting for derivatives depends on
the intended use ofthe derivatives and the resulting designation.
FERC FORM NO. 1 (ED. 12.88 123.3
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't112014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The Washington Utilities and Transportation Commission (UTC) and the Idaho Public Utilities Commission (IPUC) issued accounting
orders authorizing Avista Corp. to offset 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 instnrments
in the Statements of Income. Realized gains or losses are recognized in the period of delivery, subject to approval for recovery through
retail rates. Realized gains and Iosses, subject to regulatory approval, result in adjustments to retail rates through purchased gas cost
adjustments, the Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (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. Contacts 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.
Fair Value Measurements
Fair value represents the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly
transaction between market participants at the measurement date. Enerry commodity derivative assets and liabilities, deferred
compensation assets, as well as derivatives related to interest rate swap agreements and foreiga culrency 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 Credi*
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 ofproviding the regulated services, and
o 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. 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 poftion of its regulated operations, the Company could be:
o reQuired to write offits regulatory assets, and
o precluded from the future deferral of costs not recovered through rates at the time such costs are incurred, even if the
Company expected to recover such costs in the future.
See Note l9 for fuither details of regulatory assets and liabilities.
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 a32.5-yex period, related to its investrnent in WNP-3.
Through a settlement agreement with the UTC in the Washington jurisdiction, Avista Corp. is amortizing the recoverable portion of its
FERC FORM NO. 1 12-88 123.4
Name of Respondent
Avista Corooration
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't1t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 in2007 in alljurisdictions, 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
component of interest expense.
App rop r iated Retained Eurnings
In accordance with the hydroelectric licensing requirements of section I 0(d) of the Federal Power Act (FPA), the Company maintains
an appropriated retained earnings account for any eamings in excess of the specified rate of return on the Company's investment in the
licenses for its various hydro projects. The rate ofreturn on investment is specified in the various hydroelectric licensing agreements
for the Clark Fork River and Spokane River. 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 investrnent in
the licenses of the hydroelectric projects at the discretion of the FERC. The appropriated retained earnings amounts included in
retained eamings were as follows as of December 31 (dollars in thousands):
2013 20t2
Appropriated retained eamings 9,714 $
Contingencies
The Company has unresolved regulatory, legal and tax issues which have inherently unceftain 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 loss may be
incurred.
Voluntary Severance Incentive Program
At December 31,2012, the Company accrued total severance costs of $7.3 million (pre-tax) related to the voluntary termination of 55
employees. The total severance costs were made up of the severance payments and the related payroll taxes and employee benefit
costs. All terminations under the voluntary severance incentive progmm were completed by December 31,2012. The cost of the
program was recogrized as expense during the fourth quarter of 2012 and severance pay was distributed in a single lump sum cash
payment to each participant during January 2013. As of December 31,2013, there was no remaining liability accrued.
NOTE 2. NEW ACCOUNTING STANDARDS
ln February 2013, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update (ASU) No. 2013-02,
"Comprehensive lncome (Topic 220): Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Income." This
ASU does not change current requirements for reporting net income or other comprehensive income in financial statements; however,
it requires entities to disclose the effect on the line items of net income for reclassifications out of accumulated other comprehensive
income if the item being reclassified is required to be reclassified in its entirety to net income under U.S. GAAP. For other items that
FERC FORM NO. 1 .12 123.5
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
are not required to be reclassified in their entirety to net income under U.S. GAAP, an entity is required to cross-reference other
disclosures required under U.S. GAAP to provide additional detail about those items. The Company adopted this ASU effective
January 1,2013. The adoption of this ASU required additional disclosures in the Company's financial statements; however, it did not
have any impact on the Company's financial condition, results of operations and cash flows.
In December 2011, the FASB issued ASU No. 201 l-l l, "Balance Sheet (Topic 210): Disclosures about Offsetting Assets and
Liabilities." This ASU enhances disclosure requirements about the nature of an entity's right to offset and related arrangements
associated with its financial instruments and derivative instruments. ASU No. 2011-l I requires the disclosure of the gross amounts
subject to rights ofset off, amounts offset in accordance with the accounting standards followed, and the related net exposure. The
Company adopted this ASU effective January 1,2013. The adoption of this ASU required additional disclosures in the Company's
financial statements; however, it did not have any impact on the Company's financial condition, results of operations and cash flows.
In January 2013, the FASB issued ASU No. 2013-01, "Balance Sheet (Topic 210): Clariling the Scope of Disclosures about
Offsetting Assets and Liabilities." This ASU clarifies which instruments and transactions are subject to the enhanced disclosure
requirements of ASU 201 l-l I regarding the offsetting of financial assets and liabilities. ASU No. 2013-01 limits the scope of ASU
No. 201 I - I I to only recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and borrowing and
lending securities transactions that are offset in accordance with either Accounting Standards Codification (ASC) 2l 0-20-45 or ASC
815-10-45. The Company adopted this ASU effective January 7,2013. The adoption of this ASU did not have any impact on the
Company's financial condition, results of operations and cash flows.
On February 20,2014, the Federal Energy Regulatory Commission (FERC) issued a Final Rule with a retroactive effective date of
January 1,2013, which revised certain aspects of its accounting and reporting requirements under its Uniform System of Accounts for
public utilities. The accounting and reporting revisions in the Final Rule adopted new, and revised existing, electric plant accounts and
associated Operation and Maintenance expense accounts, including a purchased power account, to separately identi$ equipment and
costs related to new electric storage technologies. In addition, FERC adopted new schedules in the Form Nos. I and l-F and revised
existing schedules in the FERC Forms to separately identifu the electric storage activities. The Final Rule also included additional
footnote disclosure requirements. The Company evaluated the FERC's Final Rule and concluded that within its regulated operations
which are subject to FERC reporting requirements, the Company is not performing any activities associated with electric storage and
the Final Rule has no impact on the Company for 20 13. The Company will continue to evaluate the Final Rule on an annual basis to
determine whether it becomes applicable.
NOTE 3. BUSINESS ACQUISITIONS
Alaska Energy and Resources Company - Avista Corporation
On November 4,2013, the Company entered into an agreement and plan of merger (Merger Agreement) with AERC, a privately-held
company based in Juneau, Alaska. When the transaction is completed, AERC will become a wholly-owned subsidiary of Avista Corp.
The primary subsidiary of AERC is AEL&P, the sole provider of electric services to approximately 16,000 customers in the City and
Borough of Juneau, Alaska. ln2012, AEL&P had annual revenues of $42 million, a total rate base of $11I million and had 60
full+ime employees. The utility has a firm retail peak load of approximately 80 MW. AEL&P owns four hydroelectric generating
facilities, having a total present capacity of 24.7 MW, and has a power purchase commitment for the output of the Snettisham
hydroelectric project, having a present capacity of 78 MW, for a total hydroelectric capacity of 102.7 MW. AEL&P is not
interconnected to any other electric system; therefore, the utility has 93.9 MW of diesel generating present capacity to provide back-up
service to firm customers when necessary.
ln addition to the regulated utility, AERC owns the AJT Mining subsidiary, which is an inactive mining company holding certain
mining properties.
FERC FORM NO.I (ED.12 123.6
Name of Respondent
Avista Comoration
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The merger consideration at closing will be $ 170 million, less AERC's indebtedness and is subject to other customary closing
adjustments (Merger Consideration). The transaction will be funded primarily through the issuance of Avista Corp. common stock to
the shareholders of AERC. The transaction is expected to close by July 7,2014, following the receipt of necessary regulatory
approvals, the approval of the merger transaction by the requisite number of AERC shareholders and the satisfaction of other closing
conditions. Avista Corp. shareholder approval is not required.
Pursuant to the Merger Agreement, among other things, each of the issued and outstanding shares of AERC common stock (other than
Dissenting Shares) will be converted into the right to receive consideration as follows:
i. the number of shares of Avista Corp. common stock equal to one share of AERC common stock multiplied by the Exchange
Ratio; and
ii. a portion of the Representative Reimbursement Amount.
For purposes ofthe foregoing:
The Exchange Ratio is the ratio obtained by dividing the Per Share Amount by (i) $21 .48 if the Avista Corp. Closing Price is less
than or equal to S2 I .48, (ii) the Avista Corp. Closing Price, if the Avista Corp. Closing Price is greater than $2 L48 and less than
$34.30 or (iii) S34.30 if the Avista Corp. Closing Price is greater than or equal to S34.30.
The Per Share Amount is the amount determined by dividing (a) the Merger Consideration (as adjusted) by (b) the aggregate
number of shares of AERC cornmon stock outstanding immediately prior to the closing of the transaction.
The Representative Reimbursement Amount is a $500,000 cash payment to be made by Avista Corp. at the Closing to the
Shareholders' Representative account. The purpose of the Representative Reimbwsement Amount is to reimburse the
Shareholders' Representative for expenses incurred by the Shareholders' Representative in acting for the curent shareholders of
AERC in connection with the Merger. The total Merger Consideration will be reduced by the Representative Reimbursement
Amount.
Dissenting Shares will not be converted into, or represent the right to receive, the Merger Consideration or any portion of the
Representative Reimbursement Amount. Such shareholders will be entitled to receive payment of the fair value of Dissenting Shares
held by them in accordance with the provisions of AS 10.06.580 of the Alaska Corporations Code. Any amounts paid to Dissenting
Shares over the amounts otherwise payable in the form of Merger Consideration are indemnified expenses owed by AERC to Avista
Corp.
The Merger Agreement has been approved by Avista Corp.'s and AERC's Boards of Directors, the UTC, the U.S. Federal Trade
Commission and the Antitrust Division of the U.S. Department of Justice, but the consummation of the transaction is subject to the
satisfaction or waiver of specified closing conditions, including:
r the registration under the Securities Act of I 93 3 of the shares of common stock that will be issued to AERC shareholders;
. the approval of such shares for listing on the New York Stock Exchange;
r the approval of the merger transaction by the requisite number of AERC shareholders;
r the receipt of regulatory approvals and other consents required to consummate the merger transaction, including, among
others, approvals from the RCA, the IPUC, the OPUC and any other applicable regulatory bodies on the terms and conditions
specified in the defuritive purchase agreement;
o the absence of the occurrence of a material adverse effect (as defined in the Merger Agreement) relating to either AERC or
Avista Corp. after the date of the sigrred agreement; and
o other customary closing conditions.
FERC FORM NO. 1 (ED.1 P 123.7
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
2013to,4
NOTES TO FINANCIAL STATEMENTS (Continued)
The Merger Agreement also provides for customary termination rights for each of the Company and AERC, including the right for
either parfy to terminate if the Merger has not been consummated by December 31,2014 provided, however, that the failure of the
Merger to have been consummated on or before December 3l , 2014 was not caused by the failure of such parqy or any affiliate of such
parfy to perform any of its obligations under the Merger Agreement. Upon termination of the Merger Agreement in accordance with its
terms, there will be no further liability under the agreement except that nothing shall relieve any party thereto from liability for any
breach of the agreement.
There may be certain commitments and contingencies that will be assumed when the merger transaction is consummated; however,
Avista Corp. has not fully completed its evaluation of all the potential commitrnents and contingencies.
For the year ended December 31,2013, Avista Corp. incurred $1.6 million (pre-tax) of transaction related fees which have been
expensed and presented in the Statements of Income in other operating expenses within utilify operating expenses. Avista Corp.
expects to incur additional transaction related fees upon consummation of the transaction.
NOTE 4. DERIVATIVES AND RISK MANAGEMENT
E nergy 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 commodiry being traded and is influenced primarily by
supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodiry 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. The
Company's Risk Management Committee establishes the Company's enerry resources risk policy and monitors compliance. The Risk
Management Committee is comprised of certain Company officers and other members of management. The Audit Committee of the
Company's Board of Directors periodically reviews and discusses enterprise risk management processes, and it focuses on the
Company's material financial and accounting risk exposures and the steps management has undertaken to control them.
As part of its 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 electic generation, and 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.
Avista Corp. makes continuing projections of:
. electric Ioads at various points in time (ranging from intra-hour to multiple years) based on, among other things,
estimates of customer usage and weather, historical data and contract terms, and
. resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of
streamflows, availability of generating units, historic and forward market information, contract terms, and
experience.
On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related
derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or
fuel) market price changes. Resource optimization involves generating plant dispatch and scheduling available resources and also
includes transactions such as:
. purchasing fuel for generation,
FERC FORM NO.1 12 P 123.8
Name of Respondent
Avista Corooration
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
o when economical, selling fuel and substituting wholesale electric purchases, and
. other wholesale transactions to capture the value of generation and transmission resources and fuel delivery capacity
contracts.
Avista Corp.'s optimization process includes entering into hedging transactions to manage risks. Transactions include both physical
energy contracts and related derivative financial instruments.
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 ofthese projections, Avista Corp. plans and executes a series oftransactions to hedge a significant
portion of its projected natural gas requirements though 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 nanral gas supply requirements unhedged for purchase in short-term and spot markets.
Natural gas resource optimization activities include:
. wholesale market sales of surplus natural gas supplies,
o optimization of interstate pipeline transportation capacity not needed to serve daily load, and
r purchases and sales of nafural gas to optimize use of storage capaciry.
The following table presents the underlying energy commodity derivative volumes as of December 3 I , 201 3 that are expected to be
delivered in each respective year (in thousands of MWhs and mmBTUs):
Purchases
Electric Derivatives Gas Derivatives Electric Derivatives Cas Derivatives
Year
2014
2015
2016
20t7
2018
Thereafter
Physical (l) Financial (l)
MWH MWH
2,156
1,043
Physical (l) Financial (l)
mmBTUs mmBTUs
Physical (l) Financial (l)MWH MWH
3,116
2,542
1,634
Physical (l) Financial (l)mmBTUs mmBTUs
3,504 105,433
46,840
21,320
769
397
39',7
397
397
235
509
222
287
286
286
158
29,642
4,973
2,505
675
145,719
73,580
46, I 50
( I ) Physical transactions represent commodity transactions where Avista Corp. will take delivery of either electricity or natural gas
and financial transactions represent derivative instruments with no physical delivery, such as futures, swaps or options.
The above electric and natural gas derivative contracts will be included in eitherpower supply costs or natural gas supply costs during
the period they are delivered 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.
Fo reig n C urr ency Exchon g e C ontracts
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
FERC FORM NO.1 .12 123.9
Name of Respondent
Avista Corooration
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0/.|11t2014
Year/Period of Report
20't3tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian curency prices and settled
within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency 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 3l
(dollars in thousands):
2013 2012
Number of contracts
Notional amount (in United States dollars)
Notional amount (in Canadian dollars)
Interesl Rate Swap Agreements
Balance Sheet Date Number of Contracts Notional Amounl
Mandatory Cash Settlement
Date
23
$ 8,631 $
9,191
20
12,621
12,502
Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. The
Finance Commiftee of the Board of Directors periodically reviews and discusses interest rate risk management processes, and it
focuses on the steps management has undertaken to control it. The Risk Management Committee also reviews the interest risk
management plan. Avista Corp. manages interest rate exposure by limiting the variable rate exposures to a percentage of total
capitalization. Additionally, interest rate risk is managed by monitoring market conditions when timing the issuance of long-term debt
and optional debt redemptions and through the use of fixed rate long-term debt with varying mahrities. The Company also hedges a
portion of its interest rate risk with furancial 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 entered into as of December 3l (dollars in thousands):
December 31,2013 2
2
2
I
4
50,000
45,000
40,000
15,000
95,000
2014
2015
2016
2017
2018
December 31,2012
In June 2013, the Company cash settled two interest rate swap contracts (notional amount of $85.0 million) and received a total of $2.9
million. The interest rate swap contracts were settled in connection with the pricing of $90.0 million of First Mortgage Bonds that were
issued in August 2013 (see Note I I ). 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.
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2013 (in thousands):
FERC FORM NO.1 (ED. 12.88 123.10
2
)
I
85,000
50,000
25,000
2013
2014
2015
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
Mt1112014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Fair Value
Net Asset GrossGross Gross Collateral (Liability) in Gross Assets Liabilities Not Net AssetDerivative Balance Sheet Location Balance Sheet Offset
Foreign Derivative S 7 $ (6)$ - $ 1 $ - $ - $ Icurrency instrument assetsconfacts -Hedges
Interest rate Derivative 13,968 13,968 13,968contracts instrument assets
-Hedges
Interest rate Long-term portion 19,575 19,575 19,575
contracts ofderivative
instrument assets
-Hedges
Commodity Derivative
contracts (l ) instrument assets
current
Commodity Long-term portion 7,610 (6,756) 854 854
contracts (l) ofderivative assets
Commodity Derivative 23,455 (37,306) 2,976 (10,875) (10,875)
contracts (1) instrument
liabilities current
Commodity Long-term portion l7,l0l (41,213) 5,756 (18,356) (18,356)
contracts (l) ofderivative
liabilities
Total derivative instruments
recordedonthebalancesheet $ 89,132 $ (89,675)S 8,732 $ 8,189 S - $ - S 8,189
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 3 l,
2012 (in thousands):
Fair Value
Net Assot CrossGross Gross Collateral (Liability) in Gross Assets Liabilities Not Net Asset
Derivative Balance Sheet Location Balance Shect Offset
Foreign Derivative $ 7 $ (34)$ - $ (27)$ - $ - $ (27)currency instrument
contracts liabilities -Hedges
Interest rate Derivative (1,406) (1,406) (1,406)
contracts instrument
liabilities -Hedges
Interest rate Long-term portion 7,265 7,265 7,265
contracts ofderivative
instrument assets
-Hedges
Commodity Derivative 10,772 (6,633) 4,139 (9,678) 6,572 1,033
contracts (l) instrument assets
current
Commodity Long-term portion 18,779 (17,686) 1,093 1,093
contracts (l) ofderivative assets
Commodity Derivative 50,227 (89,449) 9,707 (29,515) 9,678 (6,572) (26,409)
contracts(l) instrument
FERC FORM NO.1 .1 123.11
7,416 (4,394) 3,022 3,022
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2U3tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
liabilities current
Commodity Long-termportion
contracts(l) ofderivative
liabilities
2,247 (28,558)(26,311)(26,311)
Total derivative insfuments
recorded on the balance sheet $ 89,297 $ (143,766) $ 9,707 S (44,762) $-$ -$ (44,762)
(l)Avistacorp.hasamastern.n**Iffiffi nTrI*.*rt.ffi rmm"m
master netting agreement. This master netting agreement allows for cross-corrrmodity netting (i.e. nefting physical power, physical
natural gas, and financial transactions) and cross-affrliate netting for the parties to the agreement. Avista Corp. performs
cross-commodity netting for each legal entity that is a parfy to the master netting agreement for presentation in the Balance Sheets;
however, Avista Corp. does not perform cross-affiliate netting because the Company believes that cross-affiliate netting may not
be enforceable. Therefore, the requirements for cross-affiliate netting under ASC 210-20-45 are not applicable for Avista Corp. As
of December 31,2013, all derivatives for each affiliated entity under this master netting agreement were in a net liability position.
As such, there is no additional netting which requires disclosure.
Exposure to Demandsfor 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. As of December 31,2013, the Company had cash deposited as
collateral of $26. I million and letters of credit of $20.3 million outstanding related to its energy derivative contracts. The Balance
Sheet at December 3 I , 20 l3 reflects the offsetting of $8.7 million of cash collateral against net derivative positions where a legal right
of offset exists. As of December 31,2012, the Company had cash deposited as collateral of $10.1 million and letters of credit of $28.1
million outstanding related to its energy derivative contracts. The Balance Sheet at December 31,2012 reflects the offsetting of $9.7
million of cash collateral against net derivative positions where a legal right of offset exists.
Certain of the Company's derivative insffuments contain provisions that require the Company to maintain an investrnent 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 aggregate fair value of all derivative
instruments with credit-risk-related contingent features that were in a liability position as of December 31,2073 was $13.3 million. If
the credit-risk-related contingent features underlying these agreements had been triggered on December 3 1 , 20 I 3, the Company could
have been required to post $ 12.6 million of additional collateral to its counterparties. The aggregate fair value of all derivative
instruments with credit-risk-related contingent features that are in a liability position as of December 31,2012 was $35.9 million. If the
credit-risk-related contingent features underlying these agreements had been triggered on December 31,2012, the Company could
have been required to post $25.8 million of additionalcollateralto its counterparties.
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 enerry 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:
o relating directly to it,
. caused by market price changes, and
o relating to other market participants that have a direct or indirect relationship with such counterparty.
FERC FORM NO.1 . 12-88 123.12
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
20131o.4
NOTES TO FINANCIAL STATEMENTS (Continued)
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.
We enter into bilateral transactions between Avista Corp. and various counterparties. We also trade energy and related derivative
instruments through clearinghouse exchanges.
The Company seeks to mitigate bilateral credit risk by:
. entering into bilateral contracts that specify credit terms and protections against default,
. applying credit limits and duration criteria to existing and prospective counterparties,
o actively monitoring current credit exposures,
. asserting our collateral rights with counterparties,
. carrying out transaction sefilements timely and effectively, and
o conducting transactions on exchanges with fully collateralized clearing arrangements that significantly reduce
counterparty default risk.
The Company's credit policy includes an evaluation of the financial condition of counterparties. Credit risk management includes
collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. The Company enters into
various agreements that address credit risks including standardized agreements that allow for the netting or offsetting of positive and
negative exposures.
The Company has concentrations of suppliers and customers in the electric and natural gas industries including:
o electric and natural gas utilities,
o electric generators and transmission providers,
. natural gas producers and pipelines,
. financial institutions including commodity clearing exchanges and related parties, and
. energy marketing and trading companies.
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 5. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a l5 percent ownership interest in a twin-unit coal-fired generating facility, the Colstrip Generating Project
(Colsrip) 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
FERC FORM NO. I .1 123.13
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Income. The Company's share of utility plant in service for Colstrip and accumulated depreciation were as follows as of December 3l
(dol lars in thousands) :
20t3 20t2
Utility plant in service S 349,781 $ 344,958
Accumulated depreciation (239,538) (234,126)
NOTE 6. ASSET RETIREMENT OBLIGATIONS
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incuned. When the
liability is initially recorded, the associated costs of the asset retirement obligation 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 the related asset. Upon retirement of the asset, the Company either settles the retirement obligation 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 asset retirement obligations recorded since asset retirement costs are recovered through rates charged
to customers. The regulatory assets do not earn a return.
Specifically, the Company has recorded liabilities for future asset retirement obligations to:
. restore 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 Iand lease,
. remove asbestos at the corporate ofiice building, and
. dispose of PCBs in certain fansformers.
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
o abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.
The following table documents the changes in the Company's asset retirement obligation during the years ended December 3l (dollars
in thousands):
20t3 2012
s 3,168 S 3,513(263) (sse)
(4O 214
$ 2,859 S 3,168
NOTE 7. PENSION PLANS AN'D OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering substantially all regular full+ime employees at Avista Corp.. 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.
The Company's frrnding 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 $44.3 million in cash to the pension plan in 2013 and $44.0 million in2012. The Company expects to contribute
$32.0 million in cash to the pension plan in 2014.
FERC FORM NO.1 (ED.1 123.14
Asset retirement obligation at beginning of year
Liability settled
Accretion expense (income)
Asset retirement obligation at end of year
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In October 2013, the Company revised its defined benefit pension plan such that as of January 1, 2014lhe plan is closed to all
non-union employees hired or rehired by the Company on or after January 1,2014. All actively employed non-union employees that
were hired prior to January 1,2014 and are currently covered under the defined benefit pension plan will continue accruing benefits as
originally specified in the plan. A new and separate defined contribution 40 I (k) plan replaced the defined benefit pension plan for all
non-union employees hired or rehired on or after January I , 2014. Under the new defined contribution plan, the Company provides a
non-elective contribution as a percentage of each employee's pay based on his or her age. This new defined contribution plan is in
addition to the existing a0l(k) plan in which the Company matches a portion of the pay deferred by each participant. In addition to the
above changes, the Company has also revised its lump sum calculation from its previous lump sum calculation for non-union
participants who retire under the defined benefit pension plan to provide non-union retirees on or after January 1,2014 with a lump
sum amount equivalent to the present value ofthe annuity based upon applicable discount rates.
The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive
officers of the Company. The SERP is intended to provide benefits to executive officers whose benefits under the pension plan are
reduced due to the application ofSection 415 ofthe Internal Revenue Code of 1986 and the deferral ofsalary 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):
2018 Total20l9-2023
Expected benefit payments 26,735 28,880 $30,379 $t72,887
The expected long-term rate ofreturn on plan assets is based on past performance and economic forecasts for the rypes ofinvesfrnents
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 substantially all of its retired employees. The Company
accrues the estimated cost of postretirement benefit obligations during the years that employees provide services. The Company
elected to amortize the transition obligation of $34.5 million over a period of 20 years, beginning in 1993. In October 2013, the
Company revised the health care benefit plan such that beginning on January 1,2020, the method for calculating health insurance
premiums for non-union retirees under age 65 and active Company employees was revised. The revisions resulted in separate health
insurance premium calculations for each group. In addition, for non-union employees hired or rehired on or after January 1,2014,
upon retirement the Company no longer provides a contribution towards his or her medical premiums. The Company will provide
access to its retiree medical plan, but the non-union employees hired or rehired on or after January I , 2014 will pay the full cost of
premiums upon retirement.
The Company has a Health Reimbursement Arrangement 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 this plan are included as other postetirement 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.
The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):
2014 2015 2016 20t7 2018 Total20l9-2023
2014
$ ,5,n6
2016
$ ,?n
2015 2017
Expected benefi t payments 6,969 $6,707 $7,056 $7,120 s 7,247 s 35,121
FERC FORM NO.1 .12 123.15
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
20'13/Q4
NOTES TO FIMNCIAL STATEMENTS (Continued)
The Company expects to contibute $7.0 million to other postretirement benefit plans in 2014, representing expected benefit payments
to be paid during the year. The Company uses a December 3l measurement date for its pension and other postetirement benefit plans.
The following table sets forth the pension and other postretirement benefit plan disclosures as of December 3 I , 20 I 3 and 20 12 and the
components of net periodic benefit costs for the years ended December 31, 2013 and 2012 (dollars in thousands):
Pension Benefits
Other Post-
retirement Benefits
2013 20t2 2013 20t2
Change in benefit obligation:
Benefit obligation as of beginning of year
Service cost
Interest cost
Actuarial (gain)/loss
Plan change
Transfer of accrued vacation
Benefits paid
Benefit obligation as of end of year
Change in plan assets:
Fair value ofplan assets as ofbeginning ofyear
Actual return on plan assets
Employer contributions
Benefits paid
Fair value ofplan assets as ofend ofyear
Funded status
Unrecognized net actuarial loss
Unrecognized prior service cost
Prepaid (accrued) benefit cost
Additional liability
Accrued benefit liability
Accumulated pension benefit obligation
Accumulated postretirement benefit obligation:
527,004 S 584,619 $108,249
107,043 223,308 56,885 94,202
584,619
19,045
23,896
(78,234)
277
(22.s99)
494,192 $
15,551
24,349
72,170
(21,643)
132,541
4,144
5,216
(18,017)
(10,788)
1,189
(6,036)
104,730
2,804
5,056
24,543
336
(4,928)
s 132.541
406,061 $
s2,502
44,263
(21,324)
328,150 $
54,3 l8
44,000
(20,407)
25,288
4,444
22,455
2,933
$ 481,502 $ 406,061 $ 29,732 $ 25,288
s (45,502) S (178,558) $ (78,517) $ (107,253)
278 3r9 (707) (8s6)
61,819
(107,321)
45,069
(223,627)
(22,339)
(56,178)
(13,907)
(93,346)
$ (45,502) $ (178,558) $ (78,517) $ (107,253)
s 464,432 $ 505,695 _
For retirees
For fully eligible employees
For other participants
Included in accumulated other comprehensive loss (income) (net of tax):
207
1 45,1 50
52,384
24,320
31,545
(7,472)
43,988
49,232
35,570
47,739
(ss6)
61,231
$
$
$
$
$
s
Unrecognized prior service cost
Unrecognized net actuarial loss
Total
Less regulatory asset
Accumulated other comprehensive loss (income)
$ r80$
69,5'.18
69,758 145,357
(64,925) (138,184)
Pension Benefits
2013 2012
36,516
(37,1t6)
60,67 5
(60,981)
4,833 $7,173 $(600) $
Other Post-
retirement Benefits
2013 2012
Weighted average assumptions as of December 3l:
(306)
FERC FORM NO.1 1 1 23.16
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENfS (Continued)
Discount rate for benefit obligation
Discount rate for annual expense
Expected long-term return on plan assets
Rate of compensation increase
Medical cost trend pre-age 65 - initial
Medical cost trend pre-age 65 - ultimate
Ultimate medical cost trend year pre-age 65
Medical cost trend post-age 65 - initial
Medical cost trend post-age 65 - ultimate
Ultimate medical cost trend year post-age 65
5.10%
4.15%
6.60%
4.96%
4.15%
5.04%
6.9s%
4.89%
5.02%
4.15%
6.35%
7.000/o
5.00%
2020
7.50%
5.00%
202t
4.15%
4.98%
6.55%
7.00%
5.00%
2019
7.50%
5.00%
2021
Pension Benefits Other Post-retirement Benefi ts
2013 20t2 2013 2012
Components of net periodic benefit
cost:
Service cost $
Interest cost
Expected retum on plan assets
Transition obligation recognition
Amortization of prior service cost
Net loss recognition
Equity securities
Debt securities
Real estate
Absolute return
Other
19,045
23,896
(27,671)
319
1 3,1 99
$ 28,788
15,551 $
24,349
(23,810)
346
11,637
4,144 $
5,216
( 1,606)
(14e)
5,674
2,804
5,056
(1,471)
505
(l4e)
5,020
$ 13,279 $ 11,765Net periodic benefit cost 28,073
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 investnent
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, fusts and partnerships that hold marketable debt and equity securities, real estate,
absolute return and commodiry funds. In seeking to obtain the desired return to fund the pension plan, the investrnent 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:
2013 2012
47%
3lo/o
60/o
12%
4%
5t%
3t%
5%
t0%
3%
FERC FORM NO. 1 12 123.17
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The market-related 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. lnvestment 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). 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 fair value of the closely held investments and partnership interests is 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.
The market-related value of pension plan assets invested in real estate was determined by the investment manager based on three basic
approaches:
. properties are extemally appraised on an annual basis by independent appraisers, additional appraisals may be
performed as warranted by specific asset or market conditions,
. properly valuations are reviewed quarterly and adjusted as necessary, and
. loans are reflected at fair value.
The market-related value of pension plan assets was determined as of December 3 I , 2013 and 2012.
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 3 1 , 201 3 at fair value (dollars in thousands):
Level I kvel 2 Level 3 Total
Mutual funds:
Fixed income securities
U.S. equity securities
Intemational equity securities
Absolute return (l)
Commor/collective trusts :
Fixed income securities
Real estate
Partnership/cl osely held investments :
Absolute return (l)
Private equity funds (3)
Commodities (2)
Real estate
Total 348,853 $74,513 $58,136 $481,502
86,481 $
152,83 I
85,942
23,599
310 $
55,872
18,331
-s
D,7;
34,1 5 1
377
3,873
86,791
I 52,83 I
85,942
23,599
55,872
19,735
34,1 5 I
377
18,331
3,873
FERC FORM NO. 1 (ED.12.88 P 't23.18
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013144
NOTES TO FINANCIAL STATEMENTS (Continued)
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 31,2012 at fair value (dollars in thousands):
Level I l*vel2 Level 3
Mutual funds:
Fixed income securities
U.S. equity securities
International equity securities
Absolute return (l)
Commodities (2)
Common/collective trusts:
Fixed income securities
Real estate
Partnership/closely held investments :
Absolute return (l)
Private equity tunds (3)
Total
Balance, as ofJanuary 1,2013
Realized gains
Unrealized gains (losses)
Purchases (sales), net
Balance, as of Decemb er 3l , 2013
Balance, as ofJanuary 1,2012
Realized gains (losses)
Unrealized gains (losses)
Purchases (sales), net
Balance, as of December 31,2012
83,037 $
135,436
79,448
20,764
8,258
-$
43,107
-$83,037
135,436
79,448
20,764
8,258
43,107
17,596
17,755
660
17,596
17,755
660
326,943 $43,107 $36,01l $406,061
(l) 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 investrnent is in derivatives linked to commodity indices to gain exposure to the commodity markets. These positions are
fully collateralized with debt securities.
(3) This category includes private equity funds that invest primarily in U.S. companies.
The table below discloses the summary of changes in the fah value of the pension plan's Level 3 assets for the year ended
December 31,2013 (dollars in thousands):
Common/collectivc trusts Partnership/closely held investments
Private equity Real
estate
17,596 $
2,139
17,755 $
2,396
14,000
660 $
(323)
345
(3os)
113
3,760
19,735 $ 34,151 $377 $ 3,873
The table below discloses the summary of changes in the fair value of the pension plan's Level 3 assets for the year ended
December 31,2012 (dollars in thousands):
Common/collectivetrusts Partnership/closelyheld investments
Private equity
funds
Real
estate
Absolute
return
8,598
4tl
1,087
7,500
16,587
1,1 6g
808
108
80
(336)
17,596 $ 17,755 S 660
FERC FORM NO. 1 1 123.19
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1112014
Year/Period of Report
2013to.4
NOTES TO FINANCIAL STATEMENTS (Continued)
The market-related value of other postretirement plan assets invested in debt and equity securities was based primarily on fair value
(market prices). The fair value of investment securities faded 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. Invesfrnent securities for
which market prices are not readily available or for which market prices do not represent tle 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 20 l3 and 62
percent equity securities and 38 percent debt securities in 2012.
The market-related value of other postretirement plan assets was determined as of December 3 1,2073 and 2012.
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of other
posketirement plan assets measured and reported as of December 3 1 , 2013 at fair value (dollars in thousands):
Level I Level 2 Level 3
Cash equivalents
Mutual funds:
Fixed income securities
U.S. equity securities
Intemational equity securities
Total
Cash equivalents
Mutual funds:
Fixed income securities
U.S. equity securities
International equity securities
Total
-$
11,645
I 1,83 I
6,252
4$-$4
11,645
I 1,831
6,252
29,728 $4$-$29,732
The following table discloses by level within the fair value hierarchy (see Note l4 for a description of the fair value hierarchy) of other
postretirement plan assets measured and reported as of December 31,2012 at fair value (dollars in thousands):
trvel I Level 2 Level 3 Total
-s
9,314
10,266
5,702
6s -s 6
9,314
10,266
5,702
25,282 $25,288
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 3 I , 201 3 by $3.8 million and the service and interest cost by $0.8 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 3 I , 20 I 3 by
$3.I million and the service and interest cost by $0.6 million.
The Company has a salary deferral 401(k) plans that is a defined contribution plan and cover substantially all employees. Employees
can make contributions to their respective accounts in the plan 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 plan.
Employer matching contributions were as follows for the years ended December 3l (dollars in thousands):
2013 2012
Employer 40 1 (k) matching contibutions 6,157 $5,813
The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer
until the earlier oftheir retirement, termination, disability or death, up to 75 percent oftheir base salary and/or up to 100 percent of
their incentive Deferred nsation funds are held bv the
6$-$
FERC FORM NO.1 12-88) Page 123.20
in a Rabbi Trust. There were deferred
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
assets and corresponding deferred compensation liabilities on the Balance Sheets of the following amounts as of December 3l (dollars
in thousands):
2013 2012
Deferred compensation assets and liabilities $ 9,170 $ 8,806
NOTE 8. ACCOUNTING FOR TNCOME 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.
As of December 3 l, 2013, the Company had $5.9 million of state tax credit carryforwards. State tax credits expire from 2016 to 2027 .
The Company recognizes the effect of state tax credits generated from utility plant as they are utilized.
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.
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 2009 and
all issues were resolved related to these years. The IRS has not completed an examination of the Company's 20 l0 through 2012 federal
income tax returns. The Company does not believe that any open tax years for federal or state income taxes could result in any
adjustments that would be sigrificant to the financial statements.
The Company did not incur any penalties on income tax positions in 2013 or 2012.
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 3l (dollars in thousands):
2013 20t2
Regulatory assets for deferred income taxes
NOTE 9. ENERGY PURCHASE CONTRACTS
$ 7l,4rr $ ?9/06
Avista Corp. has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for ttre
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 utiliry
resource costs in the Statements of Income, were as follows for the years ended December 3 I (dollars in thousands):
20t3 2012
Utility power resources $ 524,810 $ 523,416
The following table details Avista Corp.'s future contractual commiunents for power resources (including transmission contracts) and
natural gas resources (including transportation contracts) (dollars in thousands):
2014 2015 2016 2017 2018 Thereafter Total
Powerresources $ ,01593 $ l.i'5,0n $ |UJ?O $ ttq405 $ 106200 $ 8?4990 S 1J30,930
Natural gas resources 102,651 64,860 46,665 43,011 37,570 482,986 777,743
s 304344 $ t8%93' $ 159235 $ ts33t6 $ t$Jn $ $57,n6 $ 2308^6?3Total
FERC FORM NO. 1 (ED. 1 123.21
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0/.t11t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
These energy purchase contracts were entered into as part ofAvista 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 ofthe power and natural gas cost deferral and recovery mechanisms.
The above future contractual commitments for power resources include fxed contractual amounts related to the Company's contracts
with certain Public Utility Districts (PUD) 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 (based in
part on the debt service requirements of the PUD) 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.
In addition, Avista Corp. has operating agreements, settlements and other contractual obligations to see the ouput of its generating
facilities and transmission and distribution services. The following table details future contractual commifinents under these
agreements (dollars in thousands):
2014 2015 2016 2017 2018 Thereafter Total
Contractual obligations S 30J9? $ 27236 S 29,199 $ 23J34 S 21Bn $ 35L tOt
NOTE IO. NOTES PAYABLE
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration
date of February 2017.
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 3 I , 20 13, 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):
2013 2012
Balance outstanding at end of period 6 lffi'60- f-.r^000-
Letters of credit outstanding at end of period S 27,434 $ 35,885
Average interest rate at end of period 1.02% I .12%
As of December 31, 2013 the borrowings outstanding under Avista Corp.'s committed line of credit were classified as short-term
borrowings on the Balance Sheet.
NOTE II. BONDS
The following details bonds outstanding as of December 31 (dollars in tbousands):
Maturity
Ye ar Description
InterestRate 2013 2012
2013 First Mortgage Bonds t.68% $ - S 50,000
FERC FORM NO. 1 (ED. 1 123.22
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t't112014
Year/Period of Report
20131c.4
NOTES TO FINANCIAL STATEMENTS (Continued)
20t6
2018
201 8
2019
2020
2022
2023
2028
2032
2034
2035
2037
2040
2041
2047
First Mortgage Bonds
First Mortgage Bonds
Secured Medium-Term Notes
First Mortgage Bonds
First Mortgage Bonds
First Mortgage Bonds
Secured Medium-Term Notes
Secured Medium-Term Notes
Secured Pollution Control Bonds (l)
Secured Pollution Control Bonds (2)
First Mortgage Bonds
First Mortgage Bonds
First Mortgage Bonds
First Mortgage Bonds
Fkst Mortgage Bonds
Total secured bonds
Settled interest rate swaps (3)
Secured Pollution Control Bonds held by Avista
Corporation (1) (2)
Total bonds
0.84Vo
59s%
7.39%-7As%
5.45%
3.89%
5.13%
7.18%-7.54%
6.37%
(l)
(2)
6.25%
5.70%
5.55Yo
4A5%
423%
90,000
250,000
22,500
90,000
52,000
250,000
13,500
25,000
66,700
17,000
150,000
150,000
35,000
85,000
80,000
250,0;
22,500
90,000
52,000
250,000
13,500
25,000
66,700
17,000
150,000
150,000
35,000
85,000
80,000
1,376,700 1,336,700
(23,560) (27,900)
(83,700) (83,700)
$ 1,269,440 S 1,225,100
(1)In December 2010, S66.7 million of the City of Forsyh, Montana Pollution Control Revenue Refunding Bonds (Avista
Corporation Colstrip Project) due2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue
(Series 2010A). The new bonds were not 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, tlese 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) ln December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista
Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue
(Series 2010B). The new bonds were not 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, the 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 Sheet.
(3) Upon settlement of interest rate swaps, these are recorded as a regulatory asset or liability and included as part of long-term
debt above. They are amortized as a component of interest expense over the life of the associated debt and included as a part
of the Company's cost of debt calculation for ratemaking purposes.
In August 201 3, Avista Corp. entered into a $90.0 million term loan agreement with an institutional investor that bears an annual
interest rate of 0.84 percent and matures in 2016. The term loan agreement is secured by non-transferable First Mortgage Bonds of the
Company issued to the agent bank that will only become due and payable in the event, and then only to the extent, that the Company
defaults on its obligations under the term loan agreement. The net proceeds from the $90.0 million term loan agreement were used to
repay a portion of corporate indebtedness in anticipation of $50.0 million in First Mortgage Bonds that matured in December 2013.
The following table details future long-term debt maturities including advances from associated companies (see Note l2) (dollars in
thousands):
FERC FORM NO.1 ,1 Page 123.23
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
2014 2015 2016 2017 2018 Thereafter Total
Debtmaturities $ -$ -$ 90,000S -$ r7r,5OO$ 982J/i-$1344,547
Substantiatlyaltutitityo."ffiotrrtr-*"*r*r*rffin"--r"-"*"--t*"r-*..r-*l-r*
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: l) 66-213 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 cenain 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 l2 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 3 I , 20 I 3, property additions and retired bonds would have allowed, and the net earnings
test would not have prohibited, the issuance of $916.3 million in aggregate principal amount of additional First Mortgage Bonds.
See Note l0 for information regarding First Mortgage Bonds issued to secure the Company's obligations under its committed line of
credit agreement.
NOTE 12. ADVANCES FROM ASSOCIATED COMPANIES
ln 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 3l:
2013 2012
Low distribution rate L1]f% Ll%
High distribution rate l.l9% 1.40o/o
Distribution rate at the end of the year l.llyo 1.19%
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 on or after June 1,2007 and mature on June 1,
2037 . ln December 2000, the Company purchased $ I 0.0 million of these Preferred Trust Securities.
The Company owns I 00 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 Prefened Trust
Securities will be mandatorily redeemed.
NOTE 13. LEASES
The Company has multiple lease arrangements involving various assets, with minimum terms ranging from I to forty-five years. Rental
expense under operating leases was as follows for the years ended December 3l (dollars in thousands):
2013 2012
Rental expense $ 2,797 S 3,274
Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one
year as of December 3l were as follows (dollars in thousands):
2014 2015 2016 2017 2018 Thereafter Total
Minimumpaymentsrequired $ 1J73 $ 5e2 $ m $ l?9 $ t68 $ 2.651 $ 5J?6
FERC FORM NO.1 (ED. 1 Page 123.24
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 14. FAIR VALUE
The carrying values ofcash 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 I 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.
Level2 - Pricing inputs are other than quoted prices in active markets included in Level I , which are either directly or indirectly
observable as of the reporting date. Level 2 includes those furancial 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
ofthe 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 intemally developed methodologies that result in management's besl estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is sigrrificant to the fair value
measurement. The Company's assessment of the sigrrificance of a particular input to the fah value measurement requires judgmeng 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):
20t3 20t2
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
Bonds (Level 2)
Bonds (Level 3)
Advances from associated companies (Level 3)
$ 951,000 $ 1,054,512 s
342,000 329,581
51,547 37,114
951,000 $ 1,164,639
302,000 320,892
51,54'1 43,686
These estimates of fair value were primarily based on available market information.
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 31,2013 and 2012 at fair value on a recurring basis (dollars in thousands):
Counterparfy
and Cash
Collateral
FERC FORM NO. 1 1 123.25
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Level I Level2 Level 3 Netting (l)Total
December 31, 2013
Assets:
Enerry commodity derivatives
Level 3 energy commodity derivatives:
Power exchange agreement
Foreign currency derivatives
Interest rate swaps
Defened compensation assets :
Fixed income securities
Equity securities
Total
Liabilities:
Energy commodity derivatives
Level 3 energy commodity derivatives:
Natural gas exchange agreement
Power exchange agreement
Power option agreement
Foreign crJrrency derivatives
Total
December 31,2012
Assets:
Enerry commodity derivatives
Level 3 energy commodity derivatives:
Power exchange agreement
Foreign currency derivatives
Interest rate swaps
Deferred compensation assets:
Fixed income securities
Equity securities
Total
Liabilities:
Enerry commodity derivatives
Level 3 energy commodity derivatives:
Natural gas exchange agreement
Power exchange agreement
Power option agreement
Foreign curency derivatives
Interest rate swaps
Total
-$55,243 $
7
33,543
- $ (51,367)$ 3,876
339 (33e)
(6)I
33,543
1,960
6,470
1,960
6,470
8,430 $88,793 S 339 s (51,712) $ 45,850
-$72,895 $-$
1,219
14,780
775
-$72,901 $16,774
Level 1 Level2 Level 3
(60,099) $ 12,796
(33e)
(6)
s (60,444) $29,231
1,219
14,441
775
Counterparty
and Cash
Collateral
Netting (1)Total
2,010
5,955
-s 81,640 S
7
7,265
-$(76,408) S
(38s)
(7)
5,232
7,2;
2,010
5,955
385
7,965 $88,912 S 385 $(76,800) $20,462
-$I19,390 $
34
1,406
-$
2,379
19,077
1,480
(86,115) S, 33,275
2,379
(385) t8,692
1,480
(7) 27
1,406
-s 120,830 $22,936 $(86,507) $ 57,259
FERC FORM NO.1 1 123.26
Name of Respondent
Avista Corooration
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't1t2014
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
l. 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 pwchase 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 broker quotes, adjusted
for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange
CNYMEX) pricing for similar instruments, adjusted for basin differences, using broker quotes. Where observable inputs are available
for substantially the full term of the contract, the derivative asset or liability is included in Level 2.
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 $0.7 million as of December 31, 2013 and $0.8 million as of December 31,2012.
Level3 Fair Value
For the power exchange agreement, the Company compares the Level 2 brokered quotes and forward price curves described above to
an intemally developed forward price which is based on the average operating and maintenance (O&M) charges from four sulrogate
nuclear power plants around the country 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 I ) the strike price (which
is an internally derived price based on a combination ofgeneration plant heat rate factors, natural gas market pricing, delivery and
other O&M charges, 2) estimated delivery volumes for years beyond 2014, and 3) volatility rates for periods beyond October 2016.
Significant increases or decreases in any of these inputs in isolation would result in a sig:rificantly higher or lower fair value
measurement. Generally, changes in overall commodity market prices and volatilify 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 contactual 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 conelated with
market prices and market volatility. As of December 31, 2013, all contractual purchases have been made by Avista Corp. under the
natural gas commodity exchange agreement; therefore, the Company no longer estimates forward purchase volumes and forward
FERC FORM NO. 1 .1 123.27
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1'U2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
purchase prices as these are not significant inputs to the calculation.
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 31,2013 (dollars in thousands):
Fair Value (Net)
at
December 31, Valuation2013 Technique Unobservable Input Range
Power exchange agreement S (14,441) Surrogate facility O&M charges $30.18-$53.90/MWh (l)
pncmg
Escalation factor 3yo - 2014 to 2019
Transaction volumes 234,064 - 397,116 MWhs
Power option agreement (775) Black-Scholes- Strike price $55.62lMWh - 2016
Merton
$65.3I/MWh - 2019
Delivery volumes 157,517 - 287,147 MWhs
Volatility rates 0.20 (2)
Natural gas exchange
agreement
(1,219) Internally derived Forward purchase
weighted average prices
cost of gas (3)
Fonvard sales prices $3.98 - $4.57lmmBTU
Purchase volumes (3)
Sales volumes 150,000 - 310,000 mmBTUs
(l ) The average O&M charges for the delivery year beginning in November 2013 were $40.93 per MWh. For rate-making purposes
the average O&M calculations vary slightly between regulatory jurisdictions. For Washington, the average O&M charges were
$42.44 and the average O&M charges for Idaho were $40.93 for the delivery year beginning in 2013.
(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.31 for 2014 to 0.20 in October 2016.
(3) As of December 3 I , 20 I 3, all contractual purchases have been made by Avista Corp. under the original natural gas exchange
agreement; therefore, the Company did not estimate forward purchase volumes. and forward purchase prices as these are not
significant inputs to the calculation at December 31, 2013. On January 31,2074, the Company executed an extension to this
agreement; therefore, during the first quarter of 2014, forward purchase volumes and forward purchase prices will again be a
significant input to the calculation and the Company will resume estimating these amounts.
Avista Corp.'s risk management team and accounting team are responsible for developing the valuation methods described above and
both groups report to the Chief Financial Officer. The valuation methods, the significant inputs, and the resulting fair values described
above are reviewed on at least a quarterly basis by the risk management team and the accounting team 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):
FERC FORM NO.1 12-88 Page 123.28
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411't2014
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Natural Gas Power
Exchange Exchange PowerOption
Agreement Agreement
Year ended December 31, 2013:
Balance as ofJanuary 1,2013
Total gains or losses (realized/unrealized):
Included in net income
Included in other comprehensive income
Included in regulatory assets/liabilities (l)
Purchases
Issuance
Settlements
Transfers to/from other categories
Ending balance as of Decemb er 3l , 2013
Year ended December 31,2012:
Balance as ofJanuary 1,2072
Total gains or losses (realized/unrealized):
Included in net income
Included in other comprehensive income
Included in regulatory assets/liabilities (l)
Purchases
Issuance
Settlements
Transfers from other categories
Ending balance as of December 31,2012
s (14,441) $(77 s)
(2,379) $
2,2;
(1,138)
(18,692) $
1,017
3,234
(r,480) s
705
Total
(22,551
4,020
2,0;
-
$ ( 16,435_-
5,420
(1,688) $
3;
(1,0;
(9,910) $
(15,236)
6,454
(1,260) s (12,858)
(2? (rs,lr,
$ (2,379) $ (18,692) $ (1,480) $ (22,551)
(l) The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset commodity derivative assets or Iiabilities
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 utiliry derivative commodity instruments in the Statements of Income. Realized gains or losses are
recognized in the period ofdelivery, subject to approval for recovery through retail rates. Realized gains and losses, subject to
regulatory approval, result in adjustnents to retail rates though purchased gas cost adjustments, the ERM in Washington, the
PCA mechanism in Idaho, and periodic general rates cases.
NOTE 15. COMMON STOCK
The Company has a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company's shareholders may
automatically reinvest their dividends and make optional cash payments for the purchase of the Company's common stock at culrent
market value.
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),
. ceftain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements,
and
FERC FORM NO. 1 (ED. 12.88 123.29
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411112014
Year/Period of Report
2013tQ4
NOTES TO FIMNCIAL STATEMENTS (Continued)
o the hydroelecric licensing requirements of section 10(d) of the FPA (see Note l).
The Company declared the following dividends for the year ended December 3l:
20t3 2012
Dividends paid per common share $ r.22 $ l.16
ln August 2012, the Company entered into two sales agency agreements under which the Company may sell up to 2,726,390 shares of
its common stock from time to time. There were no shares issued under these agreements during 2013 and as of December 31,2013,
the Company had 1,795,199 shares available to be issued under these agreements.
Shares issued under sales agency agreements were as follows in the year ended December 3l :
2013 2012
Shares issued under sales agency agreement 93l,l9l
The Company has I 0 million authorized shares of preferred stock. The Company did not have any prefened stock outstanding as of
December 3 l, 2013 and2012.
NOTE 16. STOCK COMPENSATION PLANS
Avisto Corp.
1998 Plan
In 1998, the Company adopted, and shareholders approved, the Long-Term Incentive Plan (1998 Plan). Underthe 1998 Plan, certain
key employees, officers and non-employee directors of the Company and its subsidiaries may be granted stock options, stock
appreciation rights, stock awards (including resticted stock) and other stock-based awards and dividend equivalent rights. The
Company has available a maximum of 4.5 million shares of its corunon stock for grant under the 1998 Plan. As of December 31,2013,
0.9 million shares were remaining for grant under this plan.
2000 Plan
In 2000, the Company adopted a Non-Oflicer Employee Long-Term Incentive Plan (2000 Plan), which was not required to be
approved by shareholders. The provisions ofthe 2000 Plan are essentially the same as those under tle 1998 Plan, except for the
exclusion of non-employee directors and executive officers of the Company. The Company has available a maximum of 2.5 million
shares of its common stock for grant under the 2000 Plan. However, the Company currently does not plan to issue any further options
or securities under the 2000 Plan. As of December 31, 2013, 1.9 million shares were remaining for grant under this plan.
Stock Compensation
The Company records compensation cost relating to share-based payment transactions in the financial statements based on the fair
value of the equity or liability instruments issued. 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 3l
(dollars in thousands):
20t3 2012
Stock-based compensation expense
Income tax benefits
Stoch Options
$ 6,218 $
2,176
5,792
2,027
The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 3 I :
FERC FORM NO.1 .12 Page 123.30
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
20t3 2012
Number of shares under stock options:
Options outstanding at beginning of year
Options granted
Options exercised
Options canceled
Options outstanding and exercisable at end ofyear
Weighted average exercise price:
Options exercised
Options canceled
Options outstanding and exercisable at end ofyear
Cash received from options exercised (in thousands)
Intrinsic value ofoptions exercised (in thousands)
Intrinsic value ofoptions outstanding (in thousands)
Unvested shares at beginning ofyear
Shares granted
Shares canceled
Shares vested
Unvested shares at end ofyear
Weighted average fair value at grant date
Unrecognized compensation expense at end ofyear (in thousands)
Intrinsic value, unvested shares at end ofyear (in thousands)
Intrinsic value, shares vested during the year (in thousands)
3,000
(3,000)
92,499
(89,499)
3,000
$
s
$
$
$
$
12.41 s 10.63
-$
- s 12,41
37 S 9s1
40 $ t "349
-$ 3s
There are no longer any stock options outstanding as of December 3 I , 2013 and the Company does not have any plans to issue
additional stock options in the near future.
Restricted Shares
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. During the vesting period, employees are entitled to dividend equivalents which are
paid when dividends on the Company's common stock are declared. Restricted stock is valued at the close of market of the Company's
common stock on the grant date. The weighted average remaining vesting period for the Company's restricted shares outstanding as of
December 31, 2013 was 0.7 years.
The following table summarizes restricted stock activity for the years ended December 3l:
2013 20t2
I l7,l l8
44,556
(1,802)
(55,456)
93,482
70,281
(7e0)
(45,855)
104,416
$ 26.04 $
$ l,lgg $
$ 2,943 $
$ 1,363 $
2s.83
1,428
2,824
1,173
Performance Shares
Performance share 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. Performance share awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain
circumstances, and are subject to meeting a specific performance criterion. Based on the attainment of the performance criterion, the
amount of cash paid or cornmon stock issued will range from 0 to 200 percent of the performance shares ganted depending on the
change in the value of the Company's common stock relative to an external benchmark. Dividend equivalent rights are accumulated
and paid out only on shares that eventually vest.
FERC FORM NO. 1 .1 123.31
I 17,1 l8
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Performance share awards entitle the grantee to shares of common stock or cash payable once the service condition is satisfied. Based
on attainment of the performance criteria, grantees may receive 0 to 200 percent of the original shares granted. The performance
criterion used is the Company's Total Shareholder Return performance over a three-year period as compared against other utilities; this
is considered a market-based condition. Performance shares may be settled in common stock or cash at the discretion of the Company.
Historically, the Company has senled these awards through issuance of stock and intends to continue this practice. These awards vest
at the end of the three-year period. Performance shares are equity awards with a market-based condition, which results in the
compensation cost for these awards being recognized over the requisite service period, provided that the requisite service period is
rendered, regardless of when, if ever, the market condition is satisfied.
The Company measures (at the grant date) the estimated fair value of performance shares awarded. The fair value of each performance
share award was estimated on the date of grant using a statistical model that incorporates the probability of meeting performance
targets based on historical returns relative to a peer group. Expected volatility was based on the historical volatility of Avista Corp.
colrunon stock over a three-year period. The expected term ofthe performance shares is three years based on the performance cycle.
The risk-free interest rate was based on the U.S. Treasury yield at the time of grant. The compensation expense on these awards will
only be adjusted for changes in forfeitures.
The following summarizes the weighted average assumptions used to determine the fair value of performance shares and related
compensation expense as well as the resulting estimated fair value of performance shares granted:
2013 2012
Risk-free interest rate
Expected life, in years
Expected volatility
Dividend yield
Weighted average grant date fair value (per share) $
The fair value includes both performance shares and dividend equivalent rights.
The following summarizes performance share activity:
Opening balance of unvested performance shares
Performance shares granted
Performance shares canceled
Performance shares vested
Ending balance ofunvested performance shares
Intrinsic value ofunvested performance shares (in thousands)
Unrecognized compensation expense (in thousands)
0.4%
3
19.l%
4.6%
23.30 $
0.3%
J
22.7%
4.s%
26.06
The weighted average remaining vesting period for the Company's performance shares outstanding as of December 31,2013 was I .5
years. Unrecognized compensation expense as of Decemb er 31 , 2013 includes only the amount attributable to the equity portion of the
performance share awards and will be recognized during 2014 and2015.
The following summarizes the impact of the market condition on the vested performance shares:
2013 20t2
Performance shares vested
Impact of market condition on shares vested
20t3 2012
359,700 351,345
175,000 I 81,000
(13,298) (4,544)
(t7 6,718) (168,101)
344,684 359,700
$ 9,717 $ 8,672
s 3,651 $ 3,800
t7 6,718 168,10l
(17 6,718) ( l68,l o 1)
FERC FORM NO. 1 (ED.12.88 P 123.32
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t20't4
Year/Period of Report
2013/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Shares of common stock earned
Intrinsic value of common stock earned (in thousands) $ - $
Shares earned under this plan are distributed to participants in the quarter following vesting.
Outstanding performance share awards include a dividend component that is paid in cash. This component of the performance 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, and the change in the value of the Company's common stock relative to an external
benchmark. Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid.
As of December 3 I , 20 l3 and 2012, the Company had recogrized cumulative compensation expense and a liability of $0.9 million and
$0.7 million related to the dividend component on the outstanding and unvested performance share grants.
NOTE 17. 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 mafiers that affect Avista Corp.'s operations, the Company intends to
seek, to the extent appropriate, recovery ofincurred costs through the ratemaking process.
Federal Energt Regulatory Commission Inquiry
In April 2004, the Federal Enerry Regulatory Commission (FERC) approved the contested Agreement in Resolution of Section 206
Proceeding (Agreement in Resolution) between Avista Corp., Avista Enerry and the FERC's Trial Staffwhich stated that there was: (l)
no evidence that any executives or employees of Avista Corp. or Avista Energy knowingly engaged in or facilitated any improper
trading strategy during 2000 and 2001; (2) no evidence that Avista Corp. or Avista Energy engaged in any efforts to manipulate the
westem energy markets during 2000 and 2001; and (3) no finding that Avisa Corp. or Avista Energy withheld relevant information
from the FERC's inquiry into the western energy markets for 2000 and 2001 (Trading Investigation). The FERC's decisions approving
the Agreement in Resolution are pending before the United States Court of Appeals for the Ninth Circuit (Ninth Circuit). In May 2004,
the FERC provided notice that Avista Energy was no longer subject to an investigation reviewing certain bids above $250 per MW in
the short-term energy markets operated by the California Independent System Operator (CalISO) and the California Power Exchange
(CalPX) from May l, 2000 to October 2,2000 (Bidding Investigation). That matter is also pending before the Ninth Circuit.
As discussed in "California Refund Proceeding" below, in November 2013, Avista Corp. and Avista Energy arrived at a settlement in
principle with Pacific Gas & Electric (PG&E), Southern California Edison, San Diego Gas & Electric, the California Attorney General
(AG), the California Department of Water Resources (CERS), and the California Public Utilities Commission that would resolve these
matters and obviate the need for further litigation. The Company filed the settlement at the FERC for its approval on March 7,2014.
The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or
cash flows.
Califo rnia Refund Proceeding
In July 200 I , the FERC ordered an evidentiary hearing to determine the amount of refunds due to California enerry buyers for
purchases made in the spot markets operated by the CaIISO and the CaIPX during the period from October 2,2000 to June 20,2001
(Refund Period). Proposed refunds are based on the calculation of mitigated market clearing prices for each hour. The FERC ruled that
if the refunds required by the formula would cause a seller to recover less than its actual costs for the Refund Period, sellers may
document these costs and limit their refund liability commensurately. In 201l, the FERC approved Avista Energy's cost filing, a
decision that is now before the Ninth Circuit.
FERC FORM NO.1 .12 123.33
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In August 2006, the Ninth Circuit remanded to the FERC its decision not to consider an FPA section 309 remedy for tariffviolations
prior to October 2,2000. tn May 201 I , the FERC clarified the issues set for hearing for the period May I , 2000 - October l, 2000
(Summer Period): (l ) which market practices and behaviors constitute a violation of the then-cunent CallSO, CalPX, and individual
seller's tariffs and FERC orders; (2) whether any of the sellers named as respondents in this proceeding engaged in those tariff
violations; and (3) whether any such tariff violations affected the market clearing price. The FERC also gave the California parties an
opportunity to show that exchange transactions with the CaIISO during the Refund Period were not just and reasonable. During a
FERC hearingin2012, the Presiding Administrative Law Judge (ALJ) issued a partial initial decision granting Avista Corp.'s motion
for summary disposition, based on the stipulation by the California Parties that there are no allegations of tariff violations made against
Avista Corp. in this proceeding and therefore no tariffviolations by Avista Corp. that affected the market clearing price in any hour
during the Summer Period. On November 2,2012, the FERC issued an order affirming the partial initial decision and dismissing
Avista Corp. from the proceeding, thereby terminating all claims against Avista Corp. for the Summer Period. In the same order, the
FERC also held that a market-wide remedy would not be appropriate with regard to any respondent during the Summer Period. The
FERC stated that it is clear that the Ninth Circuit did not mandate a specific remedy on remand and, instead, left it to the FERC's
discretion to determine which remedy would be appropriate. On February 15,2013, the ALJ issued an initialdecision ruling thatthe
Califomia Parties met their burden in the case against Avista Energy by relying on "ssreens" that identified transactions that potentially
could have signified tariffviolations. The initial decision did not discuss evidence offered by Avista Energy, on an hour-by-hour basis,
rebutting the alleged violations. With respect to Avista Energy's one exchange transaction with the CallSO during the Refund Period,
the judge made no findings with respect to the justness and reasonableness of that transaction, but nonetheless determined that Avista
Energy owed approximately $0.2 million in refunds with regard to the transaction.
In November of 2013, Avista Corp. and Avista Energy arrived at a settlement in principle that would resolve this matter which
obviates the need for further litigation. The 2001 bankruptcy of PG&E resulted in a default on its payment obligations to the CalPX,
and as a result, Avista Energy has not been paid for all of its sales during the Refund Period. Those funds have been held in escrow
accounts pending resolution of this proceeding. The settlement would return $15 million of Avista Energy's receivable to Avista
Energy, with the balance of the Avista Energy receivable flowing to the purchasers associated with the hourly transactions at issue.
There is no admission of wrongdoing on the part of the settling parties, and thus it is further agreed that no part of the refund payment
by Avista Energy constitutes a fine or a penalty. The settlement resolves all claims for alleged overcharges during the Summer and
Refund Periods in the Califomia Refund Proceeding, and in the Pacific Northwest Refund Proceeding, for sales made to CERS, as
discussed below. The settlement also includes settlement of the Federal Energy Regulatory Commission Inquiry, the Pacific Northwest
Refund Proceeding, and the California Attorney General Complaint (the "Lockyer Complaint").
The settlement is subject to approval by the FERC. The Company filed the settlement at the FERC for its approval on March 7,2014.
The Company does not expect that this matter will have a material adverse effect on its furancial condition, results of operations or
cash flows.
PaciJic Northw est 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 fu:ding that the equities do not justiff the imposition of
refunds. In August 2007, the Ninth Circuit found that the FERC, in denying the request for refunds, had failed to take into account new
evidence of market manipulation in the California enerry market and its potential ties to the Pacific Norlhwest energy market and that
such failure was arbiffary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's findings must be
reevaluated in light of the evidence. The Ninth Circuit expressly declined to direct the FERC to grant refunds. On October 3, 201 l, the
FERC issued an Order on Remand, finding that, in light of the Ninth Circuit's remand order, additional procedures are needed to
address possible unlawful activity that may have influenced prices in the Pacific Northwest spot market during the period from
FERC FORM NO.1 .1 123.34
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
December 25, 2000 through June 20, 200 I . 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 will not be sufficient to establish a causal
connection between a particular seller's alleged unlawful activities and the specific contract negotiations at issue.
On July I | , 2012, Avista Enerry and Avista Corp. filed settlements of all issues in this docket with regard to the claims made by the
City of Tacoma, which the FERC approved. The two remaining direct claimants against Avista Corp. and Avista Energy in this
proceeding are the City of Seattle, Washinglon (Seattle), and the California AG (on behalf of CERS).
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 l, 2000 through and including June 20, 2001.
OnApril ll,20l3,theCaliforniaPartiesfiledapetitionforreviewoftheOctober3,20ll OrderonRemand,andtheApril5,20l3
Order on Rehearing, in the Ninth Circuit. Seattle filed a petition for review of the same orders on April26,20l3. On May 22,2013,
the Ninth Circuit issued an order consolidating the California Parties' and Seattle's petitions for review with respect to the Order on
Remand and the Order on Rehearing.
The hearing before an ALJ began on August 27 , 2013, and briefing is now concluded. The ALJ's initial decision is anticipated on or
before March 18,2014.
As discussed in "California Refund Proceeding" above, in November 2013, Avista Corp. and Avista Energy arrived at a settlement in
principle that would resolve these matters with regard to the CERS claims. The settlement is subject to approval by the FERC. The
Company filed the settlement at the FERC for its approval on March 7,2014. Seattle continues to pursue claims against both Avista
Corp. and Avista Energy, and if, refunds are ordered by the FERC with regard to any particular contract with Seattle, Avista Corp. and
Avista Enerry could be liable to make payments. The Company cannot predict the outcome of this proceeding or the amount of any
refunds that Avista Corp. or Avista Enerry could be ordered to make. Therefore, the Company cannot predict the potential impact the
outcome of this matter could ultimately have on the Company's results of operations, financial condition or cash flows.
California Attorney General Complaint (the "Lockyer Complaint")
In May 2002,the FERC conditionally dismissed a complaint filed in March 2002by the California AG that alleged violations of the
FPA by the FERC and all sellers (including Avista Corp. and its subsidiaries) of electric power and enerry into Califomia. The
complaint alleged tlrat the FERC's adoption and implementation of market-based rate authority was flawed and, as a result, individual
sellers should refund the difference between the rate charged and ajust and reasonable rate. In May 2002,the FERC issued an order
dismissing the complaint. [n September 2004, the Ninth Circuit upheld the FERC's market-based rate authority, but held that the FERC
erred in ruling that it lacked authority to order refunds for violations of its reporting requirement. The Court remanded the case for
further proceedings, which ultimately resulted in summary disposition at the FERC in favor of Avista Corp. and Avista Enerry. The
proceeding is now before the Ninth Circuit.
As discussed in "Califomia Refund Proceeding" above, in November 20 13, Avista Corp. and Avista Energy arrived at a settlement in
principle that would resolve tlese matters and obviate the need for fi.rther litigation. The settlement is subject to approval by the
FERC. The Company filed the settlement at the FERC for its approval on March 7,2014. The Company does not expect that this
matter will have a material adverse effect on its financial condition, results of operations or cash flows.
Colstrip Generating Project - Complaint Alleging llater Pollution
In March 2007, two families that own property near the holding ponds from Units 3 & 4 of the Colstrip Generating Project (Colstrip)
filed a complaint against the owners of Colstrip and Hydrometrics, Inc. in Montana District Court. Avista Corp. owns a l5 percent
interest in Units 3 & 4 of Colstrip. The plaintiffs alleged that the holding ponds and remediation activities adversely impacted their
FERC FORM NO.1 .1 123.35
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0411'12014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
property. They alleged contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to
their property. They also sought punitive damages, attomeys' fees, an order by the court to remove certain ponds, and the forfeiture of
profits earned from the generation of Colstrip. In September 20 I 0, the owners of Colstrip filed a motion with the court to enforce a
settlement agreement that would resolve all issues between the parties. In October 201 I the court issued an order which enforced the
settlement agreement. All subsequent appeals by the plaintiffs of the court's decision were denied and in 2013 a motion to dismiss the
case was approved by the court. Under the settlement, Avista Corp.'s portion of payment (which was accrued in 2010) to the plaintiffs
was not material to 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 (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 I 5 percent interest in Units 3 & 4 of Colstrip. The other Colsfrip
co-owners are 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. The
Plaintiffs request that the Court grant injunctive and declaratory relief 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.
On May 3,2013, the Colstrip owners and operator filed a partial motion to dismiss, seeking dismissal of 36 of the 39 claims. The
Plaintiffs filed their opposition on May 31,2013, and the owners and operator filed their reply on June 21, 2013. On July 17, 2013, the
Court held a preliminary pretrial conference, and on July I 8, 2013, the Court issued an Order establishing a procedural schedule and
deadlines.
On September 72,2013, the Plaintiffs filed Plaintiffs' First Motion for Partial Summary Judgment on the Applicable Method for
Calculating Emission Increases from Modifications Made to the Colstrip Power Plant. The Colstrip Owners and Operator Response
filed their reply on November 15, 2013.
On September27,2013, the Plaintiffs filed an Amended Complaint. The Amended Complaint withdrew from the originalComplaint
fifteen claims related to seven pre-January l, 2001 Colship 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 I , 2001 Colstrip projects. The Plaintiffs request that ttre Court
grant injunctive and declaratory relief, order remediation of alleged environmental damage, 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.
On October I I , 20 I 3, the Colstrip owners and operator filed a motion to dismiss, seeking dismissal of all of Plaintiffs' claims
contained in the Amended Complaint. Due to the preliminary nature of the lawsuit, Avista Corporation cannot, at this time, predict the
outcome of the matter.
Harbor Oil Inc. Site
Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB tansformer oil in the late 1980s and early
1990s. In June 2005, the Environmental Protection Agency (EPA) Region l0 provided notification to Avista Corp. and several other
parties, as customers of Harbor Oil, that the EPA had determined that hazardous substances were released at the Harbor Oil site in
Portland, Oregon and that Avista Corp. and several other parties may be liable for investigation and cleanup of the site under the
Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal "Superfund" law,
which provides for joint and several liability. Six potentially responsible parties, including Avista Corp., signed an Administrative
Order on Consent with the EPA on May 3 I, 2007 to conduct a remedial investigation and feasibility study (RI/FS). Based on the RI/FS
submitted to the EPA, the EPA issued a Record of Decision (ROD) which proposes the "No Action Alternative" for the site. Based on
FERC FORM NO. 1 (ED.123.36
Name of Respondent
Avista Corporation
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
the review of its records related to Harbor Oil, the Company does not believe it is a significant contributor to this potential
environmental contamination based on the small volume of waste oil it delivered to the Harbor Oil site. As such, and in light of the
EPA's ROD, the Company does not expect that this matter will have a material effect on its financial condition, results of operations or
cash flows. The Company has expensed its share of the RI/FS ($0.5 million) for this matter.
Spokane River Licensing
The Company owns and operates six hydroelectric plants on the Spokane River. Five of these (Long Lake, Nine Mile, Upper Falls,
Monroe Street, and Post Falls) are regulated under one 50-year FERC license issued in June 2009 and are referred to as the Spokane
River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The license
incorporated the 4(e) conditions that were included in the December 2008 Settlement Agreement with the United States Department of
Interior and the Coeur d'Alene Tribe, as well as the mandatory conditions that were agreed to in the Idaho 401 Water Quality
Certifications and in the amended Washington 401 Water Quality Certification.
As part of the Settlement Agreement with the Washington Department of Ecology (Ecology), the Company has participated in the
Total Maximum Daily Load (TMDL) process for the Spokane River and Lake Spokane, the reservoir created by Long Lake Dam. On
May20,20l0,theEPAapprovedtheTMDLandonMay2T,20l0,Ecologyfiledanamended40l WaterQualityCertificationwith
the FERC for inclusion into the license. The amended 401 Water Quality Certification includes the Company's level of responsibility,
as defined in the TMDL, for low dissolved oxygen levels in Lake Spokane. The Company submitted a draft Water Quality Attainment
Plan for Dissolved Oxygen to Ecology in May 2012 and this was approved by Ecology in September 2012. This plan was subsequently
approved by the FERC. The Company began implementing this plan in 2013, and management believes costs will not be material. On
July 16, 2010, the City of Post Falls and the Hayden Area Regional Sewer Board filed an appeal with the United States District Court
for the District of Idaho with respect to the EPA's approval of the TMDL. The Company, the City of Coeur d'Alene, Kaiser Aluminum
and the Spokane River Keeper subsequently moved to intervene in the appeal. In September 201 I , the EPA issued a stay to the
litigation that will be in effect until either the permits are issued and all appeals and challenges are complete or the court lifts the stay.
The stay is still in effect.
During 2013, through a collaborative process with key stakeholders, a decision was reached to not move forward with a specific capital
project to add oxygen to Lake Spokane. At the time of such decision, the Company had expended $ l.3 million on the discontinued
project. On September 26,2013 and October 23,2013, the UTC and IPUC, respectively, issued Orders approving the Company's
petition for an accounting order authorizing deferral of costs related to the discontinued project. The Washington portion of the project
costs were $0.9 million and this amount has been recorded as a regulatory asset until the next general rate case. The Idaho portion of
the costs of $0.5 million was recorded as a regulatory asset during the fourth quarter of 2013 and will be included in the next general
rate case. The Company will address the prudence and recovery of these costs in the next Washington and Idaho general rate cases,
expected to be filed in 2014.
The UTC and IPUC approved the recovery of licensing costs through the general rate case settlements in 2009. The Company will
continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to implementing the license for
the Spokane River Project.
Cabinet Gorge Total Dissolved Gas Abatement PIan
Dissolved atmospheric gas levels in the Clark Fork River exceed state of Idaho and federal water quality standards downstream of the
Cabinet Gorge Hydroelectric Generating Project (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. In the second
quarter of 20 I I , the Company completed preliminary feasibility assessments for several altemative abatement measures. ln 2012,
Avista Corp., with the approval of the Clark Fork Management Committee (created under the Clark Fork Settlement Agreement),
FERC FORM NO.1 12 123.37
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t1112014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
moved forward to test one of the alternatives by constructing a spill crest modification on a single spill gate. Based on testing in 20 I 3,
the modification appears to provide significant Total Dissolved Gas reduction. Further evaluation and desigrr improvements are
underway prior to applying this approach to other spill gates. The Company will continue to seek recovery, through the ratemaking
process, ofall operating and capitalized costs related to this issue.
Fish Passage at Cabinet Gorge and Noxon Rapids
In 1999, the USFWS listed bull trout as threatened under the Endangered Species Act. 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 desigas for Cabinet Gorge are still being finalized. Construction cost estimates and schedules will be
developed after several remaining issues are resolved, related to Montana's approval of fish transport from Idaho and expected
minimum discharge requirements. Fishway desigr for Noxon Rapids has also been initiated, and is still in early stages.
In January 201 0, the USFWS revised its 2005 designation of critical habitat for the bull trout to include the lower Clark Fork River as
critical habitat. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address
issues related to bull trout. 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.
Aluminum Recycling Site
In October 2009, the Company (through its subsidiary Pentzer Venture Holdings II, Inc. (Pentzer)) received notice from Ecolory
proposing to find Pentzer liable for a release of hazardous substances under the Model Toxics Control Act (MTCA), under
Washington state law. Pentzer owns property that adjoins land owned by the Union Pacific Railroad (UPR). UPR leased their property
to operators of a facility desigrated by Ecology as "Aluminum Recycling - Trentwood." Operators of the UPR property maintained
piles of aluminum dross, which designate as a state-only dangerous waste in WashinSon State. In the course of its business, the
operators placed a portion of the aluminum dross pile on the property owned by Pentzer. During the second quarter of 2013, the
Company completed an agreement with UPR which resolves all liability related to the MTCA action. Through Pentzer Corporation, a
wholly-owned subsidiary of the Company, the Company made a one-time payment of $0.1 million and UPR has taken full
responsibiliry for the cleanup activities at the site. Based on information currently known to the Company's management, the Company
believes any potential liability related to the site has been resolved, and does not expect this issue will have a material effect on its
financial condition, results ofoperations or cash flows.
C o llect ive B arg aining A gr e ements
The Company's collective bargaining agreement with the International Brotherhood of Electrical Workers 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 bargaining unit employees expired in March 2014. Two local agreements in Oregon, which cover
approximately 50 employees, expired in March 2014. Negotiations are curently ongoing for these labor agreements.
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 tlese 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 sigrificant.
The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitrnents
for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties
FERC FORM NO.1 .1 123.38
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 operations, the Company seeks, to the extent
appropriate, recovery ofincurred costs through the ratemaking process,
The Company has potential liabilities under the Endangered Species Act for species of fish that have either already been added to the
endangered species list, listed as "thleatened" 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 this issue.
Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights.
The state of Montana is examining the status of all water right claims within state boundaries. Claims within the Clark Fork River basin
could adversely aftect the enerry 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. In addition, the state of Washington has indicated an interest in initiating adjudication for the Spokane River
basin in the next several years. The Company is and will continue to be a participant in these 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.
NOTE 18. INFORMATION SERVICES CONTRACTS
The Company has information services contracts that expire at various times through 2017. The largest of these conhacts provides for
increases due to changes in the cost of living index and further provides flexibility in the annual obligation from year-to-year. Total
payments under these contracts were as follows for the years ended December 3l (dollars in thousands):
2013 20t2
Information service contract payments $ 13221
The majority of the costs are included in other operating expenses in the Statements of Income. The following table details minimum
future contractual commitments for these agreements (dollars in thousands):
2014 2015 2016 2017 2018 Thereafter Total
contractuar obligations IG' d--Fi,' ffi 5-56-8' 6- I- $ 30f88
NOTE 19. REGULATORY MATTERS
Power Cost Deferrals and Recovery Mechonisms
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:
o short-term wholesale market prices and sales and purchase volumes,
o the level and availability ofhydroelectric generation,
. the level and availability of thermal generation (including changes in fuel prices),
r the net value from optimization activities related to the Company's generating resources, and
. retail loads.
FERC FORM NO. 1 .12-88 123.39
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4111t2014
Year/Period of Report
2013tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
ln Washington, the Energy Recovery Mechanism (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 the margin on 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 $17.9 million as of December 31, 2013, and
these deferred power cost balances represent amounts due to customers. As paft of the approved Washington general rate case
settlement in December 20 1 2, during 2013 a one-year credit designed to return to customers $4.4 million from the existing ERM
defenal balance reduced the net average electric rate increase impact to customers in 2013. Additionally, during 2014 a one-year credit
up to $9.0 million will be returned to electric customers from the ERM deferral balance, so the net average electric rate increase impact
to customers effective January 1, 2014 was also be reduced. The credits to customers from the ERM balances do not impact the
Company's net income.
Under the ERM, the Company absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or
below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is cunently $4.0
million. The Company will incur the cost of or receive the benefit from, 100 percent of this initial power supply cost variance. The
Company shares annual power supply cost variances between $4.0 million and $10.0 million with customers. There is a 50 percent
customers/SO percent Company sharing ratio when actual power supply expenses are higher (surcharge to customers) than the amount
included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing ratio when actual power
supply expenses are Iower (rebate to customers) than the amount included in base retail rates within this band. To the extent that the
annual power supply cost variance from the amount included in base rates exceeds $10.0 million, there is a 90 percent customers/I0
percent Company share ratio ofthe cost variance.
The following is a summary of the ERM:
Annual Power Supply Cost Variability
Deferred for Future
Surcharge or Rebate
to Customers
within +/- $0 to $4 million (deadband)
higher by $4 million to $10 million
lower by $4 million to $10 million
higher or lower by over $ l0 million
As part of the April 2012 Washington general rate case filing, the Company proposed modifications to the ERM deadband and other
sharing bands. The proposed modifications were not agreed to as part of the settlement agreement, and the ERM continued unchanged.
However, the trigger point at which rates will change under the ERM was modified to be $30 million rather than the previous l0
percent of base revenues (approximately $45 million) urtder the mechanism.
Avista Corp. has a Power Cost Adjustment (PCA) mechanism in Idaho that allows it to modif, electric rates on October I of each year
with Idaho Public Utilities Commission (IPUC) approval. Under the PCA mechanism, Avista Co1p. 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 I 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 $5.1 million as of December 31,2013 compared to a
regulatory liability of $5.1 million as of December 31,2012.
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Corp. files a purchased gas cost adjustment (PGA) in all three states it serves to adjust natural gas rates for: l) 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. These annual PGA filings in Washington and Idaho provide for
FERC FORM NO.1 .'l 123.40
0%
50%
75%
90%
Expense or Benefit
100%
50%
25%
10%
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
the deferral, and recovery or refund, of 100 percent of the difference between actual and estimated commodity and pipeline
transportation costs, subject to applicable regulatory review. The annual PGA filing in Oregon provides for deferral, and recovery or
refund, of 100 percent of the difference between actual and estimated pipeline hansportation costs and commodity costs that are fixed
through hedge transactions. Commodity costs that are not hedged for Oregon customers are subject to a sharing mechanism whereby
Avista Corp. defers, and recovers or refunds, 90 percent ofthe difference between these actual and estimated costs. Total net deferred
natural gas costs to be refunded to customers were a liability of $12.1 million as of December 31, 2013 compared to a liability of S6.9
million as of December 31,2012.
llashington General Rale Cases
In December 201 1 , the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in May
20 I I . The settlement agreement provided for the deferral of certain generation plant maintenance costs. For 20 I I and 2012 the
Company compared actual non-fuel maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of baseline
maintenance expenses used to establish base retail rates, and deferred the difference. This defenal occurred each year, with no carrying
charge, with defened costs to be amortized over a four-year period, beginning the year following the period costs are defened. Total
net deferred costs under this mechanism in Washington were a regulatory asset of $3.1 million as of December 3l, 2013 compared to a
regulatory asset of $4.0 million as of December 31,2012. As part of the settlement agreement relating to the Company's latest general
rate case approved in December 2012,the parties agreed to terminate the maintenance cost deferral mechanism on December 31,2012,
with the four-year amortization of the 2011 and2012 deferrals to conclude in 2015 and 2016, respectively.
In December 2012,the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in
April 2012. The settlemen! effective January 1,2013, provided that base rates for Washington electric customers increase by an
overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for Washington natural gas customers
increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). Under the settlement, there was a one-year
credit designed to return $4.4 million to electric customers from the existing ERM deferral balance so the net average electic rate
increase impact to the Company's customers in 2013 was 2.0 percent. The credit to customers from the ERM balance did not impact
the Company's earnings.
The approved settlement also provided that, effective January 1,2014, the Company increased base rates for Washinglon electric
customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and for Washington natural gas customers
by an overall 0.9 percent (desigrred to increase annual revenues by $1.4 million). The settlement provides for a one-year credit up to
$9.0 million to electric customers from the ERM deferral balance, so the net average electric rate increase to customers effective
January 1,2014 was 2.0 percent. The credit to customers from the ERM balance will not impact the Company's eamings. The ERM
balance as of December 31,2013 was a liability of $17.9 million.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 47 .0 percent, resulting in an
overall rate ofretum on rate base of7.64 percent.
The December 2012 UTC Order approving the settlement agreement included cefiain conditions.
( I ) The new retail rates to become effective January l, 2014 will be temporary rates, and on January l, 20 I 5 electric and natural
gas base rates will revert back to 201 3 levels absent any intervening action from the UTC. The original settlement agreement
has a provision that the Company will not file a general rate case in Washington seeking new rates to take effect before
January 1,2015.
(2) In its Order, the UTC found that much of the approved base rate increases are justified by the planned capital expenditures
necessary to upgrade and maintain the Company's utility facilities. If these capital projects are not completed to a level that
was contemplated in the settlement agreement, this could result in base rates which are considered too high by the UTC.
Avista Corp. is required to file capital expenditure progress reports with the UTC on a periodic basis so that the UTC can
FERC FORM NO. 1 1 123.41
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
monitor the capital expenditures and ensure they are in line with those contemplated in the settlement agreement. The
Company expects total utility capital expenditures to be above the level contemplated in the settlement agreement.
On February 4, 2074 the Company filed electric and natural gas general rates cases with the UTC. The Company has requested an
overall increase in base electric rates of3.8 percent (designed to increase annual electric revenues by $18.2 million) and an overall
increase in base natural gas rates of8.l percent (desigred to increase annual natural gas revenues by $12.1 million). The requests are
based on a proposed overall rate of return of 7.71percent, with a common equity ratio of 49.0 percent and a l0.l percent return on
equiry.
Avista Corp. has also proposed a rebate beginning January l, 2015, related to its sale of renewable energy credits (REC), that would
reduce customers' monthly electric bills by I . I percent. The rebate associated with the sale of RECs is in response to the UTC Order
approving the Company's previous general rate case settlement in December 2012. This proposed REC rebate would commence
simultaneously with the expiration of two rebates that, together, are currently reducing customers' monthly electric bills by 2.8 percent.
The net effect, commencing January l, 2015, of the proposed new l.I percent rebate and the expiration of the current 2.8 percent
rebate would be an increase in monthly electric bills of approximately 1.7 percent from 2014 levels. These rebates do not increase or
decrease Avista Corp.'s earnings.
The combination of the 3.8 percent requested increase in base electric rates and the effective 1.7 percent increase attributable to the
rebates would be a 5.5 percent increase electric billings.
As part of the Company's electric and natural gas general rate case filings, it has requested the implementation of decoupling
mechanisms which sever the link between actual volumetric sales and the recovery of the Company's fixed costs. Under the proposed
decoupling mechanisms, the Company would compare actual non-power supply (electric) and non-PGA (natural gas) revenue to the
allowed non-power supply and non-PGA revenue, as the case may be, and the difference would be deferred and either rebated or
surcharged to customers, depending on the position ofthe deferral accounts, over a one-year period. The deferral balances would be
reviewed annually by the UTC prior to the implementation of any annual rate adjustments under the mechanisms.
The proposed mechanisms would be subject to an annual eamings test which proposes that if the Company's actual annual
"Commission-basis" rate of return exceeds the most recently authorized Commission-basis rate of return for the Company's
Washington electric and natural gas operations, the amount of a proposed surcharge is reduced or eliminated to reduce the rate of
return to the Commission-authorized level. In addition, the mechanisms would be subject to an annual rate increase limitation which
would prevent the amount of the incremental proposed rate adjustments under the mechanisms from exceeding a 3 percent rate
increase for each ofelectric and natural gas operations.
The UTC has up to I I months to review the filings and issue a decision.
Idalro General Rate Cuses
ln September 201 l, the IPUC approved a settlement agreement in the Company's general rate case filed in July 201 l. The settlement
agreement provides for the deferral of ceftain generation plant operation and maintenance costs. In order to address the variability in
year-to-year operation and maintenance costs, beginning in 201 l, the Company is deferring certain changes in operation and
maintenance costs related to the Coyote Spring 2 natural gas-fired generation plant and its l5 percent ownership interest in Units 3 & 4
of the Colstrip generation plant. The Company compares actual, non-fuel, operation and maintenance expenses for the Coyote Springs
2 and Colstrip plants with the amount of expenses authorized for recovery in base rates in the applicable deferral year, and defers the
difference from that currently authorized. The deferral occurs annually, with no carrying charge, with deferred costs being amortized
over a three-year period, beginning in the year following the period costs are deferred. The amount ofexpense to be requested for
recovery in future general rate cases will be the actual operation and maintenance expense recorded in the test period, less any amount
deferred during the test period, plus the amortization of previously defened costs. Total net deferred costs under this mechanism in
Idaho were regulatory assets of $2.8 million as of December 31, 2013 and $2.3 million as of December 31,2072.
FERC FORM NO.1 (ED. 12-88 123.42
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
In March 2013, the IPUC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in
October 2012. As agreed to in the settlement, new rates were implemented in two phases: April 1,2013 and October 1,2013.
Effective April 1 , 20 I 3, base rates increased for the Company's Idaho natural gas customers by an overall 4.9 percent (desigred to
increase annual revenues by $3.1 million). There was no change in base electric rates on April 1,2013. However, the settlement
agreement provided for the recovery of the costs of the Palouse Wind Project, subject to the 90 percent customers/I0 percent Company
sharing ratio, through the PCA mechanism until these costs are reflected in base retail rates in the next general rate case.
The settlement also provided that, effective October 7,2013, base rates increased for Idaho natural gas customers by an overall 2.0
percent (designed to increase annual revenues by $ I .3 million). A credit resulting from deferred natural gas costs of $ 1 .6 million is
being returned to the Company's Idaho natural gas customers from October l, 2013 through December 31,2074, so the net annual
average natural gas rate increase to natural gas customers effective October 1,2013 was 0.3 percent.
Further, the seftlement provided that, effective October l, 2013, base rates increased for Idaho electric customers by an overall 3.1
percent (designed to increase annual revenues by $7.8 million). A $3.9 million credit resulting from a payment to be made to Avista
Corp. by the Bonneville Power Administration relating to its prior use of Avista Corp.'s transmission system is being returned to Idaho
electric customers from October 1,2013 through December 31 ,2014, so the net annual average electric rate increase to electric
customers effective October 1,2013 was L9 percent.
The $1.6 million credit to Idaho natural gas customers and the $3.9 million credit to Idaho electric customers do not impact the
Company's net income.
The settlement agreement allows the Company to file a general rate case in Idaho n2014; however, new rates resulting from the filing
would not take effect prior to January 1, 2015.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 50.0 percent.
The seftlement also includes an after-the-fact earnings test for 2013 and 2014, such that if Avista Corp., on a consolidated basis for
electric and natural gas operations in Idaho, earns more than a 9.8 percent return on equity, Avista Corp. will refund to customers 50
percent of any earnings above the 9.8 percent. In 2013, the Company's retums exceeded this level and the Company will refund $2.0
million to Idaho electric customers and $0.4 million to Idaho natural gas customers. The period over which these amounts will be
returned to customers has not yet been determined by the IPUC.
Oregon General Rate Case
On January 2l,2ll4,the Public Utility Commission of Oregon (OPUC) approved a settlement agreement to the Company's natural gas
general rate case (originally filed in August 2013). As agreed to in the settlement, new rates will be implemented in two phases:
February 1,2014 and November 1,2014. Effective February 1,2014, rates increased for Oregon natural gas customers on a billed
basis by an overall 4.4 percent (designed to increase annual revenues by $4.3 million). Effective November 7,2014, rates for Oregon
natural gas customers will increase on a billed basis by an overall l.55 percent (desigrred to increase annual revenues by $ I . million).
The billed rate increase on November 1 ,2014 could vary slightly from that noted above as it is dependent upon actual costs incured
through September 30,2014 related to the Company's customer information system upgrade and the actual costs incurred through June
30,2014 related to the Company's Aldyl A distribution pipeline replacement program. The estimated capital expenditures included in
the general rate case settlement are $6.5 million and $2.0 million, respectively, forthe two projects. If the actual costs incurred on the
above projects are greater than the amounts contemplated in the general rate case settlement, the additional costs could be approved for
recovery, subject to a prudence review.
The approved settlement agreement provides for an overall authorized rate of return of 7 .47 percent, with a common equity ratio of 48
percent and a 9.65 percent retum on equiry.
Bonneville Power Administration Reimbarsemenl and Reardan ll/ind Generation Project
FERC FORM NO. I .1 123.43
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
0411112014
Year/Period of Report
20131Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
On May 9 , 2013 , the UTC approved the Company's Petition for an order authorizing certain accounting and ratemaking freatnent
related to two issues. The first issue relates to transmission revenues associated with a settlement between Avista Corp. and the
Bonneville Power Administration (BPA), whereby the BPA reimbursed the Company $l 1.7 million for Bonneville's past use of Avista
Corp.'s transmission system. The second issue relates to $4.3 million of costs the Company incurred over the past several years for the
development of a wind generation project site near Reardan, Washington, which has been terminated. The UTC authorized the
Company to retain $7.6 million of the BPA settlement payment, representing the entire portion of the settlement allocable to the
Washington business. However, this amount was deemed to first reimburse the Company for the $2.5 million of Reardan project costs
that are allocable to the Washington business, leaving $5. I million to be retained for the benefit of shareholders.
The BPA agreed to pay $0.3 million monthly ($3.2 million annually) for the future use of Avista Corp.'s transmission system. The
Company is separately tracking and defening for the customers'benefit, the Washington portion of these revenue payments in 2013
and2014 ($2.1 million annually). The Company implemented a one-year $4.2 million rate decrease for customers effective January l,
2014 to partially offset the electric general rate increase effective January 7,2014. To the extent actual revenues from the BPA in 20 I 3
and2014 differ from those refunded to customers in 2014, the difference will be added to or subtracted from the ERM balance. ln
Idaho, under the terms of the approved rate case settlement, 90 percent of the portion of the BPA settlement allocable to the Idaho
business ($4.1 million) is being credited back to customers over l5 months, beginning October 2013, and the Company is amortizing
the Idaho portion of Reardan costs ($ I .7 million) over a two-year period, beginning April 20 I 3.
NOTE 20. SUPPLEMENTAL CASH FLOW INFORMATION (in thousands)
2013 2012
Cash paid for interest
Cash paid for income taxes
$70,444 $68,508
$42,497 $6,631
FERC FORM NO.1 (ED. 1 123.44
This Page fntentionally Left Blank
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn orisinat
(21 nA Resubmission
uale or Hepon(Mo, Da, Yr)
04t11t2014
YearHefloo 0r Kepon
End of 20131Q4
b IA I trMtr,N I U L)F AUUUMULA I EU U(JMI'I(EI-IENUIVE INUUME, U9MPI{EIIENUIVE INUUME, ANU HEUUINU AU I IVI I IEi,
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.
_rne
No.
Item
(a)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currency
Hedges
(d)
Other
Adjustments
(e)
1 Balance ofAccount 219 at Beginning of
Preceding Year 1 34,046 ( 5,770,872)
2 Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net lncome ( 290,263)
3 Preceding QuarterfYear to Date Changes in
Fair Value 323,478 ( 1,096,s49)
4 Total (lines 2 and 3)33,215 ( 1,096,s49)
5 Balancc ofAccount 219 at End of
Preceding Quarter/Year 167,261 ( 6,867,421)
6 Balance of Account 219 at Beginning of
Current Year 167,261 ( 6,867,421)
7 Cunent QtrfYr to Date Reclassifications
from Acct 219 to Net lncome ( 12,4'.t1)
8 Cunent QuarterfYear to Date Changes in
Fair Value ( 1,740,705')2,633,346
I Total (lines 7 and 8)( 1 ,753,1 16)2,633,346
10 Balance ofAccount 219 at End ofCunent
Quarter/Year ( 1,585,855)( 4,234,075\
FERC FORM NO. 1 (NEW 06-02)Page 122a
Name of Respondent
Avista Corporation
This Reoort Is:(1) 5]An Originat(2) -A Resubmission
uate ol Kepon(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 20131Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
-tne
No.
Other Cash Flow
Hedges
lnterest Rate Swaps
(0
Other Cash Flow
Hedges
lSpecifyl
(s)
Totals for each
category of items
recorded in
Account 21 9
(h)
Net lncome (Carried
Forward from
Page 117, Line 78)
(i)
Total
Comprehensive
lncome
(i)
1 ( 5,636,826)
2 ( 2e0,263)
3 ( 773,071)
4 ( 1,063,334)78,210,066 77,146,732
5 ( 6,700,160)
6 ( 6,700,160)
7 ( 12,411)
I 892,641
I 880,230 1'11,076,833 111,957,063
10 ( 5,819,930)
FERC FORM NO. 1 (NEW 06-02)Page 122b
Name oI l1esP9noenl
Avista Corporation
r r [5 nEpur I 15.(1) $An Original(2) l_lA Resubmission
uare or Kepon(Mo, Da, Yr)
o4t11t2014
rearrrenoo or r.(epon
End of 20131Q4
SUMMARY OF U I ILI I Y PLqNI AND ACCUMULA I EL' PI'{OVISI(JNI'
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Leport in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (0, and (g) report other (specify) and in
:olumn (h) common function.
Line
No.
Classification
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Eleclric
(c)
1 Utility Plant
2 ln Service
3 Plant in Service (Classified)4,268,598,88€3,165,732,54€
4 Property Under Capital Leases 6.442.345
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (3 thru 7)4,275,041,23!3,165,732,54€
I Leased to Others
10 Held for Future Use 4,964,37€4,773,791
11 Construction Work in Progress 't57,258,69C 97.884,894
12 Acquisition Adjustments
13 Total Utility Plant (8 thru 12)4.437,264,301 3,268,391,233
14 Accum Prov for Depr, Amort, & Depl 1,491,212.83t 1,136,326,135
15 Net Utility Plant (13 less 14)2,946,051,471 2,132,065,098
16 Detail of Accum Prov for Depr, Amort & Depl
17 ln Service:
18 Depreciation 1,454,623,624 1 , 123,890,02C
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant 36,589,205 12.436,11
22 Total ln Service (18 thru 21)1,491,212,83C 1,136,326,13t
23 Leased to Others
24 Depreciation
25 Amorlization and Depletion
26 Total Leased to Others (24 &25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 Amort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31 ,321 1,49'.t,212,83C 1,'t36,326,13t
FERC FORM NO.1 (ED.12-89)Page 200
Name of Respondent
Avista Corporation
This Reoort ls:(1) fiAn Original(2) nA Resubmission
L'ate or Hepon(Mo, Da, Yr)
04t11t20't4
YearPenoo or Kepon
End of 20131Q4
SUMMAI{Y OF U I ILI I Y I'LAN I ANU AUUUMUI4 I EU PK(JVIUI()NIi
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(D
Other (Specify)
G)
Common
(h)
Line
No.
837,923,76(264,942,571 3
858,86r 5,583,48r 4
5
6
7
838,782,62t 270,526,06:,8
o
190,58t 10
5,077,631 54,296,15{1',!
12
844,050,84t 324,822,22t 13
283,1 73,03{71 ,7't3,65;14
560,877,81(253,108,56:15
17
281,451,29t 49,282,31(1
1,721,74i 22,431,U1 21
283,173,03{71,713,65i 22
24
25
26
28
29
3C
32
283,173,03t 71.713.651 33
FERC FORM NO.1 (ED.12-89)Page 201
Name oI Kesponoenl
Avista Corporation
This Reoort ls:(1) 5]An orisinat(2) TIA Resubmission
Date of Report(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
End of 20131Q4
ELECTRIC PLANT lN SERVICE (Account l0'102, 103 and 106)
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. lnadditiontoAccountl0l,ElectricPlantinService(Classified),thispageandthenextincludeAccountl02,ElectricPlantPurchasedorSold;
Account 103, Experimental Electric Plant Unclassified; and Account '106, Completed Construction Not Classified-Electric.
3. lncludeincolumn(c)or(d),asappropriate,correctionsofadditionsandretirementsforthecurrentorprecedingyear.
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 1 06 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. lnclude also in column (d)
Ltne
No.
ACCOUnI
(a)
EaranceBeginning of Year
(b)
Addrttons
(c)
1. INTANGIBLE PLANT
2 301) Oroanization
3 (302) Franchises and Consents 44,651,922
4 (303) Miscellaneous lntanoible Plant 5,009,71€'1.'135.32:
5 TOTAL lntanqible Plant (Enter Total of lines 2, 3, and 4)49,661,638 1 ,135,323
6 2, PRODUCTION PI.ANT
7 A. Steam Production Plant
8 t310) Land and Land Riohts 3,488,301 1.508
9 '31 1) Structures and lmorovements 126.221.007 1.327.44?
10 t312) Boiler Plant Equipment 164,036.458 3,335,83S
't1 (313) Engines and Enqine-Driven Generators 6,77C
12 [31 4) Turboqenerator Units 52.327.599 1,268,32:
13 (315) Accessory Electric Equipment 26,162,267 554.772
14 '316) Misc. Power Plant Equioment 15.941.361 419,77e
't5 (317) Asset Retirement Costs for Steam Production 585,275
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)388.759.038 6.903.66:
17 B. Nuclear Production Plant
18 320) Land and Land Riohts
19 [32'l ) Structures and lmprovements
20 [322) Reactor Plant Eouioment
21 [323) Turbooenerator Units
22 [324) Accessorv Electric Eouiomenl
23 (325) Misc. Power Plant Equioment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hvdraulic Production Plant
27 330) Land and Land Riohts 57.951.081 329.778
28 (331) Structures and lmprovements 44.268.474 2,263,30e
29 (332) Reservoirs, Dams, and Waterways 124,134,363 7.387.442
30 333) Water Wheels. Turbines. and Generators 163.044.481 18:
31 (334) Accessory Electric Equipment 34,012,512 3,658,35t
32 335) Misc. Power PLant Eouioment 8.127.342 1 .184.36€
33 (336) Roads. Railroads. and Bridqes 2.020,756 320,284
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hvdraulic Production Plant (Enter Total of lines 27 thru 34)433,559,009 15.143.71
36 D. Other Production Plant
37 (340) Land and Land Riohts 905.1 67
38 (341) Structures and lmorovements 1 6,581 ,560 208,59(
39 (342) Fuel Holders, Products, and Accessories 21 .168.978 5,06t
40 (343) Prime Movers 23,688,559 220,911
41 (344) Generators 198,862,632 6,395,592
42 (345) Accessorv Electric Eouioment 17.111.998 4,546,41!
43 (346) Misc. Power Plant Equipment 1,719.527 13't.67(
44 (347) Asset Retirement Costs for Other Production 351.683
45 TOIAL Other Prod. Plant (Enter Total of lines 37 thru 44)280.390.104 11.508.241
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)1.102,718,151 33,555,62'
FERC FORM NO.1 (REV. 12-05)Page 2O4
Name of Respondent
Avista Corporation
This Reoort ls:(1) fiRn Originat
(21 11A Resubmission
Date(Mo,of Report
Da, Yr)
o4t11t2014
Year/Period of Report
End of 2O13lQ4
ELECTRIC PLANT lN SERVICE (Account 101 , 102, 103 and 1 06)(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 1 01 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. lnclude 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 1 02, state the property purchased or sold, name of vendor or purchase,
and date of transaction. lf proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
Keltrements
(d)
Adjustments
(e)
Transfers
(0
Balance at
End pffear
Ltne
No.
2
44.6s',t.922 3
13'1.806 6.013.233 4
131,80€50,665,1 55 5
3,489,809 I
120.39€127.428.055 I
1,079,37C 166,292.927 10
6.770 11
618,104 52.977.820 12
147.793 26.565.246 13
16.361.137 14
585,275 15
1.965.662 393.707.039 16
18
19
20
21
22
23
24
25
58.280.857 27
150.786 46,380,994 28
83,371 13't .438.434 29
69,886 162,974,77e 30
374,883 37.295.984 31
91,606 9.220.102 32
2.341.039 33
34
770.532 447.932.188 35
905,167 37
23,474 16.766.676 38
21,174,046 39
23.909.470 40
5,983 205.252.241 41
1.313.87C 20.344.543 42
356,713 1,494,484 43
35't.583 44
1,700.042 290.198,3't0 45
4.436.23e 1 .131 .837.537 46
FERC FORM NO.,t (REV.12-05)Page 205
Name of Respondent
Avista Corporation
This Reoort ls:(1) fien Originat(2) -A Resubmission
Date of Report(Mo, Da, Yr)
04t1112014
Year/Period of Report
End of 20131Q4
ELECTRIC PLANT lN SERVICE (Account 101 , 102, 103 and 106) (Continued)
-Ille
No.
ACCOUnI
(a)
t atanceBeginning of Year
(b)
Acldrti0ns
(c)
47 3. TRANSMISSION PLANT
48 (350 Land and Land Riohts 18,731.287 446,52(
49 (352) Structures and lmprovements 17,104,372 2,207,751
50 (353) Station Eouioment 213.222,173 8.863.91(
51 354 Towers and Fixtures 17.122,931 1.62!
52 (355) Poles and Fixtures 154.797.876 9.863.18(
53 (356 Overhead Conductors and Devices 1 16,767,616 4,077,98t
54 (357 Underqround Conduit 2,605,488 232,90i
55 358 Underoround Conductors and Devices 2,330.072 1 2Ar
56 359 Roads and Trails 1872.246 77,611
57 (359.1 ) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)544,554,061 25,772.78i
59 4. DISTRIBUTION PLANT
60 360 Land and Land Riohts 6.735,049 283.714
6'l (36 Structures and lmprovements 17,970,103 315,35(
62 (362 Station Equipment 11 1,338,207 6,244,89t
63 363 Storaoe Batterv Eouioment
64 (364 Poles. Towers. and Fixtures 261.335,205 20,277,90t
65 (365) Overhead Conductors and Devices 173,751,442 1 3.888. 1 8u
bb (365) Underoround Conduit 85,678.110 2,735,06t
67 (367 Underqround Conductors and Devices '1 41 ,648,755 9,505,24t
68 (368) Line Transformers 198.972.431 10,632,331
69 (369) Services 132,648,550 4,833,67(
70 (370) Meters 47,965,62A 653.761
71 (371) lnstallations on Customer Premises
72 372) Leased ProDerW on Customer Premlses
73 (373) Street Liohtino and Sional Svstems 36.385.470 2,811.371
74 (374) Asset Retirement Costs for Distribution Plant 129.707
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)1.214.558.649 72.181.49t
76 5. REGIONAL TRANSMISSION AND MARKET OPEMTION PI-ANT
77 t380) Land and Land Riohts
78 (381) Structures and lmprovements
79 (382) Computer Hardware
80 '383) Comouter Software
81 (384) Communication Equipment
82 (385) Miscellaneous Reqional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Reqional Transmission and Market Oper
84 TOTAL Transmission and Market Ooeration Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Riohts 385,053 13,61'l
87 (390) Structures and lmorovements 6.229.403 576,26'
88 (391) Office Furniture and Equipmenl 7,870,002 555,89r
89 (392) Transoortation Eouioment 't7,608.384 5,872.46i
90 '393) Stores Equipment 395,329
91 (394) Tools, Shop and Garaqe Equipment 3.185.939 90,90s
92 (395) Laboratorv Eouioment 920,024 6,05(
93 '396) Power Operated Equipment 36,041,674 3.747.M1
94 (397) Communication Eouioment 48.854.842 4.470,941
95 (398) Miscellaneous Equipment 30,511 26,611
96 SUBTOTAL (Enter Total of lines 86 thru 95)121.52'.t.161 15 359 80(
97 (399) Other Tanqible Property
98 (399. 1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96. 97 and 98)121,521,161 15 359.80(
100 TOTAL (Accounts '101 and 106)3,033,013,660 148.005.02:
101 (102) Electric Plant Purchased (See lnstr. 8)
102 'Less) (102) Electric Plant Sold (See lnstr. 8)
103 (1 03) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103)3.033.013.660 148,005,02I
FERC FORM NO.1 (REV.12-0s)Page 205
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An orisinal(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
YeariPeriod of Report
End of 20131Q4
ELECTRIC PLANT lN SERVICE (Account 101, 102, 103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
ransrers
1fl
Balance at
End of Year(o)
Line
No.
19.177.807 48
18,295 19,293,831 49
1.266.86C 220,819,229 50
17.124.556 51
81 6,1 92 163,844,864 52
637,694 120,207,906 53
2,838.390 54
2,331,360 EE
1,949,859 56
57
2.739.041 567,587,802 58
7,018,762 60
82,392 't8,203,061 61
1,660,668 115.922.437 62
63
1,063,03€280,550,075 64
-310,842 187.950,468 65
-34.85S 88,448,037 66
538, I 5S 150.615.842 ot
1.938.553 207,666,1 99 68
-91,51C 137,573,730 69
661,148 47.958.233 70
71
72
69.403 39,127,438 73
129.707 74
5,576,158 1,281.163,989 75
77
78
79
80
81
82
83
84
398,664 86
25,54e 6.780.117 87
344,417 8.081,480 88
461,012 23,019,835 89
395,329 90
261,88C 3,0 14,968 91
211.128 714,946 92
632,319 39.156.402 93
466,584 52.859.207 94
8 57,117 95
2,402,896 134,478,065 96
97
98
2.402.896 134,478,065 99
'1 5,286,1 37 3.165.732.548 100
101
102
103
15,286.137 3,1 65,732,548 104
FERC FORM NO. 1 (REV.12-05)Page
Name oI Hesponoent
Avista Corporation
This Reoort ls:(1) 5]en orisinat(2, nA Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 2013/Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account'105)
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.
LineNo.
uesailPU()n anq L()calron
Of ProlertV
uate uflotna[v tnctuoec
in This Atcount(b)
uate trxpecleo ro De useq
in Utililr Service
E atance aI
End of Year(d)
2
3
4 Distribution Plant Land, Spokane, Washington Oct 2008 Unknown 1,623,321
5 Distribution UG Plant Land, Spokane, Washington Dec 20'1 0 Unknown 2',\2,647
6 Transmission Plant Land, Spokane, Washington Dec 201 0 Unknown 197,254
7 Transmission Plant Land, Moscow, ldaho March 201 1 Unknown 126,640
I Distribution Plant Land, Spokane, Washington March 2011 Unknown 540,307
I Distribution Plant Land, Spokane, Washington Oct2O11 Unknown 414,073
10 Transmission Plant Land, Spokane, Washington Dec 201 1 Unknown 1,143,033
11 Distribution Plant Land, Spokane, Washington Dec 201 1 Unknown 250,489
12 Other Production Plant Land, Spokane, Washington Dec 201'l Unknown 40,896
13 Distribution Plant Land, Deary, ldaho June 2012 Unknown 72,367
14 Transmission Plant Land, Thornton, Washington Aug 2012 Unknown 1,383
15 Distribution Plant Land, Spokane, Washington od20't2 Unknown 151 ,381
16
17
18
19
20
22
23
24
25
26
27
28
29
30
31
32
33
34
?E
3€
37
38
ac
4C
41
42
4:,
4t
4t
4t
47 Total 4,773,791
FERC FORM NO.1 (ED. 12-96)Page 214
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An orisinat(2) 1-TA Resubmission
uale or Kepon(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
CONSTRUCTION WORK lN PROGRESS - - ELECTRIC (Account 107)
L Report below descriptions and balances at end of year of projects in process of construction (1 07)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 ofthe Uniform System ofAccounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1 ,000,000, whichever is less) may be grouped.
Line
No.
Description of Project
(a)
Construction work in progress
Electric (Account 107)
(b)
1 Nine Mile Redevelopment 20,405,502
2 Clark Fork IMP 15,412,280
3 Spokane River lmplementation 6.579.669
4 Productivity lnitiative 5,767,316
5 Moscow 230kV Sub Rebuild 230kV Yard 5,731j02
6 Little Falls Powerhouse Redevelopmnl 5,209,831
7 Customer lnformation System (ClS) Replacement 4,511,569
I High Voltage Protection Updgrade 1,861,206
9 Regulating Hydro 1,723,453
10 Millwood Sub - Rebuild 't,491,955
11 Line Ratings Mitigation Project 1,429,569
12 Sys Wood Substation Rebuilds 1,419,632
13 Blue Creek 1 1SkV Rebuild 1,413,514
14 Cabinet Gorge HED U#1 Refurbishment 1.390,201
15 Post Falls S Channel Gate Replacement 1,200,680
16 Systm-Replc/lnstl Capacitor Banks 1 ,1 92,965
17 Distribution Spokane North & West 1,050,091
18 Sandpoint Grid Modernization Project 1,038,75'l
19 Clearwater 115 kV Substation Upgrades 1,010,865
20 Minor Projects under $1,000,000 15,141,651
21
22 Research, Development, and Demonstrating:
23 SGDP Pullman Smart Grid Demo Proj 2,902,992
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 97,884,894
FERC FORM NO.1 (ED.12-87)Page 216
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An originat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILI'Y PLANT (Account 108
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 1 1, 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. lf 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. ln 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.
Section A. Balances and Changes During Year
LII Ig
No.
IIEII I
(a)
. I Orat.(c+d+e)
(b)
Etcuu tu TtdillService(c)
EttruU tu Ttailt nEtufor Future Use(d)
EIEUTIIU TIAIILLeased to Others
(e)
1 Balance Beginning of Year 1 ,065,032,018 1 ,065,032,01{
(403) Depreciation Expense 74,025,638 74,025,63{
(403.1 ) Depreciation Expense for Asset
Retirement Costs
(413) Exp. of Elec. Plt. Leas. to Others
Transportation Expenses-Clearing 4,587.922 4,587,92i
Other Clearing Accounts
Other Accounts (Specify, details in footnote):-164,900 -164,90(
1 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
78,448,66C 78.448.66(
1 Book Cost of Plant Retired 15,240.233 15,240,23i
I Cost of Removal 1,889,741 1,889,74
1 Salvage (Credit)25,394 25,39,
1l TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru '14)
17,104,580 '17,104,58(
1 Other Debit or Cr. ltems (Describe, details in
footnote):
-2.486.078 -2,486,07t
1
1 Book Cost or Asset Retirement Costs Retired
1!Balance End of Year (Enter Totals of lines 1
'10, 15, 16, and 18)
1 ,123,890,020 1,123,890,02(
Section B. Balances at End of Year According to Functional Classification
2(Steam Production 277,816,759 277,816,751
21 Nuclear Production
22 Hydrau lic Prod uction-Conventional 123,'.t18,375 123,118,37!
la Hydraulic Production-Pumped Storage
2t Other Production 82,790,065 82,790,06t
2l Transmission 189,994,238 189,994,23{
2(Distribution 394,968.478 394,968,47t
2',Regional Transmission and Market Operation 55,202,105 55,202,10!
2t General
2l TOTAL (Enter Total of lines 20 thru 28)1,123,890,020 1,123,890,02(
FERC FORM NO.1 (REV.12-0s)Page 219
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4l't1t2014
Year/Period of Report
2013to,4
FOOTNOTE DATA
Includes:
Adjustment. to 2013 Beginning Reserve Balance of 12,760
ARO adjustment of 985,900 Eo 108000
Miscellaneous adjusLment of $15,2]-9 to 108000Accretion expense of $22,019 l-82376 Lo 108000
Accumulated provision of non-recoverable plant of $-290,798 for KettIe Fa11s and Boulder
Park
Schedule Page: 219 Line No.: 15 Column: c
Includes:
Change in Removal Work in Progress of $-2,486,078
FERC FORM NO. 1 (ED.12.87 P 450.1
Name or Kesponoent
Avista Corporation
This Reoort ls:(1) E]An Originar(2) f-'lA Resubmission
Date of Report
(Mo, Da, Yr)
o4111t2014
Year/Period of Report
End of 20131Q4
INVESTMENTS lN SUBSIDIARY COMPANIES (Account 123.
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) lnvestment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) lnvestment 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.
-tne
No.
uescflplron oT rnvestmenl
(a)
Date Acquired
(b)
Date Ofuafgritv BeSin?Jlg of Year
1
2 Avista Capital - Common Stock 1 997 216.728.833
Avista Capital - Equity in Earnings -102.654.241
4 OCI lnvestment in Subs 167,261
5 Avista Capital - Other Changes in Net lnvestment 4.472,570
b
7
8
c
10
11
12
13
14
15
'16
17
18
19
2C
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42 total Cost ofAccount 123.1 $ 0l TOTAL 118.714.423
FERC FORM NO,1 (ED.12-89)Page 224
Name oI Hesponoent
Avista Corporation
tnrs Kepon rs:(1) [An Original(2) 1-1A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2013/Q4
INVESTMENTS lN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
4. Fot 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 ofthe pledge.
5. lf 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 (0 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
trqurry rn buDsrorary
Earninls,of Year
F(evenues tor Year
(0 End pt,vear
Garn or Loss trom lnvestment
Disoosed of'(h)
Line
No.
1
-10,503,285 206,225,548 2
4,593,239 -98,061,002 3
1 .753.1 1 6 1,585,855 4
1.180.843 5,653,413 5
b
7
I
9
10
11
12
13
14
15
't6
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
4,593,239 11,075,558 112,232,104 42
FERC FORM NO. I (ED.12-89)Page 225
Name of Respondent
Avista Corporation
lnts Heoon ls:(1) 5]en Originat(2) 1A Resubmission
Date of Report(Mo, Da, Yr)
o411112014
Year/Period of Report
End of 20131Q4
MATERIALS AND SUPPLIES
1 . For Account 1 54, 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. ln 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.
Line
No.
Account
(a)
Balance
Beginning of Year
(b)
Balance
End of Year
(c)
Department or
Departments which
Use Material(d)
,|Fuel Stock (Account 151)4j20,767 3,170,050 (1)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and E)dracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to - Construction (Estimated)16,046,143 17JU,229 (1)
o Assigned to - Operations and Maintenance
7 Production Plant (Estimated)2,645,483 2,721,461 (1)
8 Transmission Plant (Estimated)54,922 '166,825 (1)
o Distribution Plant (Estimated)2U,561 316,067 (1)
'10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)4,864,288 6,347,128 (1),(2)
12 TOTAL Account 154 (Enter Total of lines 5 thru 1 1)23,875,397 26,655,710
13 Merchandise (Account 1 55)
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
20 TOTAL Materials and Supplies (Per Balance Sheet)27,996,1 64 29,825,760
FERC FORM NO.1 (REV.12-0s)Page 227
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
(1)
(2)
227 Line No.: 1EIecEric
Gas
Footnote Linked. See note on 227, Row: 1, co!/item:
Schedule Page: 227 Line No.:7 Column: d
Footnot.e Linked. see note on 227, Row: 1-, co1/item:
gchedute-Page: -Foot,not.e Linked. See rroLe orl 227, Row: 1, co1/item:
Footnote Linked. See noLe on 227, Row: L, cof,/item:
9SlS!y!e!gge: 227 Line No.:11 Column: d
Footnote Linked. See no|ue ora 227, Row:
FERC FORM NO. 1 (ED. 1 450.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) E An Original
(2) n A Resubmission
uale or F(epon(Mo, Da, Yr)
04t11t2014
Year/Period of Report
gn6 py 2013/Q4
fransmission Service and Generation lnterconnection Study Costs
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. ln column (a) provide the name of the study.
4. ln column (b) report the cost incurred to perform the study at the end of period.
5. ln column (c) report the account charged with the cost of the study.
6. ln column (d) report the amounts received for reimbursement of the study costs at end of period.
7. ln column (e) report the account credited with the reimbursement received for performing the study.
Ltne
No.Description
(a)
Costs lncurred During
Period
(b)
Account Charged
(c)
alermourselnerrl's
Received Duringthe Period
(d)
Account Credited
With Reimbursement
(e)
2
3
4
5
6
7
8
I
0
1
2
3
4
5
6
7
I
I
20
22 AVA Noxon Upgrade 40,2'14 1 86200
23 Palouse Wind Phase ll 7.965 1 86200
24 AVA Nine Mile Upgrade 3,259 1 86200
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-Fl3-Q (NEW. 03-07)Page 231
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
20131Q4
FOOTNOTE DATA
:231 Line No.:24 Column: a
Schedule Page: 231 Line No.: 22 Column: a ITot,al charges incurred life Uo date.:231 Line No.:23 Column: aincurred Life to date.
Total charges incu e to date.
p"g" aso.r
-l
Name of Respondent
Avista Corporation
This
(1)
(2)
Reoort ls:
[]An orisinat
nA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
OTHER REGULATORY ASSETS (Account 82 3)
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.
Line
No.
Description and Purpose of
Other Regulatory Assets
(a)
Balance at Beginninl
of Cunent
Quarterffear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent Quarter/Year
(0
Written ofl During the
Ouarler /Year Account
Charged (d)
Written ofl During
the Period Amount
(e)
1 Reg Asset Post Ret Liab 306,407,66!228 149,423,373 156,984,296
2 Regulatory Asset FAS109 Utility Planl 65,464,601 283 2,579,600 62,88s,00s
3 Requlatory Asset Lancaster Generation 3,966,66i 407 1,360,000 2,606,667
4 Requlatory Asset FAS109 DSIT Non Plant t,664,76(283 407,172 1,257,594
5 Requlatory Asset FAS109 DFIT State Tax Cr 7,464JU 283 4,282,115 3,182,069
b Requlatory Asset FAS109 WNP3 4,9't6,33'283 737,482 4,178.855
7 Requlatory Asset Roseburq/Medford 265,011 8,72(4A7 273,740
8 Regulatory Assel Spokane River Relicense 622,361 407 78,736 543,626
9 Requlatory Asset- Spokane River PM&E 575,88(557 73,312 502,574
10 Requlatory Asset- Lake CDA Fund 9,437,59!407 211,065 9,226,534
11 Requlatory Asse! Lake CDA IPA Fund 2,000,00(2,000,000
12 Requlatory Asset- SDokane RiverTDG ldaho 468,89t 468,893
13 Req Assets- Decouolinqs Surcharqe 7,324 24"7,566
14 Requlatory Asset- Lake CDA DEF Costs 1,310,141 1,310,141
15 Requlatory Asset BPA Residential Exchanqe 540,80:564,99;1,105,802
16 Requlatory Asse! CNC Transmission 483.26!407 252,637 230,632
17 DEF CS2 & COLSTRIP 6,312,39t 407 499,344 5,813,05'l
18 L|DAR O&M REG DEF 587,25t 407 519,893 67.365
19 Reardan Wind Generation 852,641 852,642
20 lD Wind Gen AFUDC 369,37i 407 138,515 230,858
21 RequlatorY Asset WarBila Units 75'.t,81i 407 337,788 414,029
22 MTM St Regulatory Assel 3s,081,52r 244 24,252,110 10,829,415
23 MTM Lt Requlatory Asset 25,217,69i 244 1,960,1 32 23,257,565
24 Regulatory Asset FAS'143 Assel Retirement 0bligation 2,398,84a 230 288,613 2,110,232
25 Req Asset AN- CDA Lake Settlement 37,627,20t 407 2.226.946 3s,400,262
26 Req Asset WA-CDA Lake Settlemenl 1,204,27t 407 152,11 1,052,152
27 Requlatory Asset Workers Como 2,278,67t 208,25i 2,486,93'l
28 CS2 Lev Ret 909,49!407 s00,s00 408,999
29 Reoulatorv Asset lD PCA Defenal 2 8,209,41:557 3,144,178 5,065,235
30 Sookane Rlver TDG 871,181 871,194
31 lnterest Rate Swap Asset 36,525,85(36,525,856
32 DSM Asset 2,578,59!9,576.20r 407 2,578,59(9,576,204
33 SWAPS ON FMBS 40,697,80€557 40,697,80t
34 Misc Rea Asset 129,70a 129,705
35
36
37
38
39
40
41
42
43
44 TOTAL:559,831,454 58,726,259 236,975,774 381,s81,939
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
This Page Intentionally Left Blank
Name oI F{espondent
Avista Corporation
This Reoort ls:(1) 5]An orisinat(2) nA Resubmission
Date of Report(Mo, Da, Y0
041'.t1t2014
Year/Period of Report
End of 2UAA4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
1. Repo( 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.
Line
No.
Description of Miscellaneous
Deferred Debits
(a\
Balance at
Beginning of Year
1b)
Debits
(c\
CREDITS Balance at
End of Year
(flChargedAmount
Iel
1
2 Colstrio Common Fac.1 ,1 1 0,999 406 1.110.999
3 Requlatorv Asset-Mt Lease Pvmt 1.352.565 540 360,684 991,881
4 Regulatory Asset-Mt Lease Pymt 2.706.480 540 676,63'2,029,848
5 Colstrio Common Fac.2.355.642 2.355.642
6 Prepaid Airplane Lease LT 318,859 931 fi7 j6e 171 ,693
7 Misc DD- Airplane Lease 102,737 VAR 21,14t 81.591
8 Plant Alloc of Clearinq Jrl 3.584.496 VAR 520,161 3,064,335
I Misc Error Suspense -336,980 370,61t VAR 33,635
10 Renewable Enerov-Cert Fees 164,844 557 49.59r 115.250
11 Nez Perce Settlement 160,749 557 5.2'ti 155,537
12 Lonq Term Note RecAcct 5,419 143 5,41!
13 Req Asset lD-Lake CDA 240.056 506 30,97t 209,081
14 lD Panhandle Forest Use Permit 181,017 181 ,01 i
15 Credit Union Labor and Exo 35,01 0 3,78t VAR 38.795
16 Outdoor Lqhtnq Greenbelt Pathwv 98.227 98,221
17 Horizon Wind lnterco 61,845 557 61.84t
18 KF Water Riohts Suoolv 769 310 76!
19 ldaho Clk Fork Relic 186,950 't86,95(
20 Misc Work Orders <$50,000 126,209 20,88(VAR 147,095
21 Subsidiarv Billinos 't78.266 21.62'557 199,887
22 "Null" Proiects Directlv to 186 15,197 VAR 13.841 1 353
23 Reoulatorv Assets Consv 1.660.713 51,89r VAR 1,712,608
24 Noxon 230 KV Sub Permits 107,86(1 07.860
25 Ootional Wind Power -186.231 10.93(909 -175,295
26 Gas Telemetrv equip 59,05'59 051
27 Misc Deffered Debits/Res Accto 1.577.531 676,084 901,446
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Misc. Work in Progress
48 uererreo Keguralory uomm.
Expenses (See pages 350 - 351)
49 TOTAL 15,701,369 13,312,292
FERC FORM NO.1 (ED.12-94)Page 233
Name of Respondent
Avista Corporation
This Reoort ls:(1) []An orisinal(2) nA Resubmission
Date of Report(Mo, Da, Yr)
041't112014
Year/Period of Report
End of 2O13lQ4
ACCUMULATED DEFERRED INCOME TAXES (Account'1 90)
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.
Ltne
No.
uescrrplron ano Localron
(a)
E arancef
vT
E egrnrng
(b)
t,arance aI trno
of Year
(c)
1 Electric
6,261,06t 5,1 83,280
Other
TOTAL Electric (Enter Total of lines 2 thru 7)6,261,06t 5,183,280
Gas
1 2,161,93i 991,860
11
1
1
14
1 Other
1 TOTAL Gas (Enter Total of lines 10 thru 15 2,161,932 99'1,860
1 Other 140,002,46S 64,064,282
1 TOTAL (Acct 190) (Total of lines 8, 16 and 17)148,425,465 70,239,422
Notes
FERC FORM NO.1 (ED.12-88)Page
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An Original(2) nA Resubmission
Date
(Mo,of Report
Da, Yr)
04t1112014
Year/Period of Reporl
End of 2013lQ4
CAPITAL STOCKS (Account 201 and 204)
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. lf 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.
-tne
No.
Class and Series of Stock and
Name of Stock Series
(a)
Number of shares
Authorized by Charter
(b)
Par or Stated
Value per share
(c)
Call Price at
End of Year
(d)
1 Account 201 - Common Stock lssued
2 No Par Value 200,000,000
3 Restricted shares
4 Total Common 200,000,000
5
6
7 Account 2O4 -Prefened Stock lssued 10,000,000
8
o
0 Cumulative
1
2
3 Total Preferred 10,000,000
4
5
6
7
8
9
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
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn originat(2) 5A Resubmission
uale ol Hepon(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
CAPITAL STOCKS (Account 201 and 204) (Continued)
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.
OUTSTANDING PER BALANCE SHEET(Total amount outstanding without reduction
for amounts held by respondent)
HELD BY RESPONDENT Line
No.AS REACQUIRED STOCK (Account 217)IN SINKING AND OTHER FUNDS
unares(e)Amount(f)5nares(s)UOSI(h)Shares(i)Amount
0)
1
60,076.752 869,342,827 104,41e 2,718,992 2
3
60,076,752 869,342,827 '104,41(2,718,992 4
5
6
7
I
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
35
37
38
39
40
41
42
FERC FORM NO.1 (ED.12-88)Page 251
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Reoort Is:(1) 5]Rn orisinat(2) nA Resubmission
uate oI Kepon(Mo, Da, Yr)
04t'.t1t2014
Year/Period of Report
End of 20131Q4
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
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 1 12, 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 2'l 1)-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.
LtneNo.Item(a)AmounI(b)
Equity transactions of subsidiaries 8,089,025
2
3
4
5
6
7
I
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
2E
29
30
3l
32
33
34
35
36
37
38
39
40 TOTAL 8,089,025
FERC FORM NO.1 (ED. 12-87)Page 253
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An Orisinat
(21 nA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
f6{ 6f 2013/Q4
CAPI I AL SI OCK EXPENSE (ACcoUnt 2 1 4)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. lt 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.
LIIIE
No.
urass ano Denes oI DIocK(a)E alance aI trno oT Year
(b)
Common Stock - no par 19.561,527
2
3
4
5
6
7
I
9
10
11
12
13
14
15
16
17
18
19
20
2'l
22 TOTAL 19,561,527
FERC FORM NO.1 (ED.12-87)Page 254b
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t't1t2014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
Ssbsdt te!?se:2$_Lins_Ap,-!-._9e@mry_D_ I
Beginning Balance $ (14,977,565)
lssuance of common stock 14,798
TAX BENEFIT . OPTIONS EXERCISED 1,867,478
Excess Tax Benefits on stock compensation (464,677')
Stock compensation accrual (6,001,560)
Ending Balance $ (19,561,527)
FERC FORM NO. 1 IED.l 450.1
Name oI Kesponoent
Avista Corporation
This Reoort ls:(1) fiRn Originat(2) 1A Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Periocl of Report
End of 20131Q4
LONG-TERM DEBT (Account 221 , 222. 223 and 224\
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. ln 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. lnclude 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. ln column (b) show the principal amount of bonds or other long-term debt originally issued.
7. ln 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.
lndicate 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.
Line
No.
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 FMBS - SERIES A-7,53% DUE 05/05/2023 5,500,000 42,712
2 FMBS - SERIES A -7.54o/o DUE 5lOSl2023 1,000,000 7,766
3 FMBS - SERIES A - 7.39o/o DUE 511112018 7,000,000 54,364
4 FMBS - SERIES A-7.45o/o DUE 6/1 1/2018 15,500,000 170,597
5 FMBS - SERIES A -7.18o/o DUE 811112023 7,000,000 54,364
6 ADVANCE ASSOCIATED-AVISTA CAPITAL ll (ToPRS)51,547,000 1,296,086
7 FMBS - 6.37% SERIES C 25,000,000 158,304
I FMBS .5.45% SERIES 90,000,000 1,432,081
I FMBS - 6.25% SERIES 150,000,000 2,'180,435
''t 0 FMBS - 5.70% SERIES 150,000,000 4,9243M
11 FMBS - 5,95% SERIES 250,000,000 3,08't,419
12 FMBS - 5.125o/o SERIES 250,000,000 2.859.788
13 COLSTRIP 2010A PCRBs DUE2032 66,700,000
14 COLSTRIP 20108 PCRBs DUE 2034 17,000,000
15 FMBS.3.89% SERIES 52,000,000 383,338
16 FMBS - 5.55% SERIES 35,000,000 258,834
17 4.45% SERTES DUE 12-14-2041 85,000,000 692,833
18 4.23% SERTES DUE 11-29-2047 80,000,000 730,833
19 FMBS. O.84% SERIES 90,000,000 51 2,1 38
20
21
22
23
24
25
26
27
28
29
30
31
32
33 TOTAL 1,428,247,00(18,840,196
FERC FORM NO.1 (ED.12-96) page 256
Name of Respondent
Avista Corporation
This Report ls:(1) []An Original(2) [-lA Resubmission
Date of Report(Mo, Da, Yr)
04t1112014
Year/Period of Report
End of 20131Q4
LUNU- | trKM Utrtr r (ACCOUnI ZZ't, ZZt, ZZJ an(j ZZ4) (UOnItnUeO)
10. ldentify 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. ln a footnote, give explanatory (details) for Accounts 223 and 224 oi nel 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. lf the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose ofthe pledge
14. lf the respondent has any long{erm debt securities which have been nominally issued and are nominally outstanding at end of
year, describe such securities in a footnote.
15. lf 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 Accounl 427, interest on
Long-Term Debt and Account 430, lnterest on Debt to Associated Companies.
'16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
Nominal Date
of lssue
(d)
Date of
Maturity
(e)
AMORTIZA'-ION PERIOD vutSlanuil tufiotal amount outstandino without' reduction for amounts h-eld byres02pfent)
lnterest for Year
Amount
(D
Line
No.Date From
(fl
Date To
(q)
05-06-1 993 05-05-2023 05-06-1 993 05-05-2023 5,500,00(414,150 1
05-07-1 993 05-05-2023 05-07-1 993 05-05-2023 1,000,00(75,400 2
05-1 1 -1 993 05-1 1-2018 05-l 'l-1 993 05-1 1 -201 8 7,000,00(517,300 3
06-09-1 993 06-'11-2018 06-09- t 993 06-1 1 -201 8 15,500,00(1.154.750 4
08-1 2-1 993 08-11-2023 08-1 2-1 993 08-1 1-2023 7,000,00(502,600 5
06-03-1 997 06-01 -2037 06-03-1 997 06-01-2037 51,547,00(467,113 6
06-1 9-1 998 06-1 9-2028 05-19-'t 998 06-1 9-2028 25,000,00(1,592,500 7
11-18-2004 12-01-2019 1'.t-18-2004 't2-01-2019 90,000,00(4,905,000 8
11-17-2005 1 2-01 -2035 11-',t7-2005 12-01-2035 '150,000,00(9.375.000 I
12-15-2006 07-0't-2037 12-15-2006 07-o1-2037 150,000,00(8,550,000 10
04-02-2008 06-01 -201 I 04-02-2008 06-01 -201 8 250,000,00(14,875,000 11
09-22-2009 04-0'.t-2022 09-22-2009 04-01-2022 250,000,00(12,812,500 12
12-15-2010 10-1-2032 12-15-20'.t0 10-'t-2032 66,700,00(13
12-15-2010 3-'l-2034 12-15-20'.10 3-1-2034 17,000,00(14
12-20-2010 12-20-2020 12-20-2010 12-20-2020 52,000,00(2,022,80A 15
12-20-2010 12-20-2040 12-20-2010 12-20-2040 35,000,00(1,942,500 16
12-14-2011 12-14-2041 12-14-2011 12-14-2041 85,000,00(3,782,50('t7
11-30-2012 11-29-2047 11-30-2012 11-29-2047 80,000,00(3,384,00(18
8-14-2013 8-14-2016 8-14-2013 8-1 3-201 6 90,000,00(289,80(19
20
21
22
23
24
25
26
27
28
29
30
3'l
32
1,428,247,00(66,662,913 33
FERC FORM NO.1 (ED.12-96)Page 257
Name of Respondent
Avista Corporation
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4l'11t2014
Year/Period of Report
2o13tQ4
FOOTNOTE DATA
lSchedule Page: 256 Line No.: 6(1) Electric Column: a
(2) Gas g Column: b I
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.
lSchedule Page: 256 Line No.: 13 Column: c IThe Company reaquired these bonds in 2010'€"lr9g!@
The Company reacquired this debt in 20'10. These bonds have not been retired or canceled; the Company plans, based on
iditv needs and market to remarket these bonds at a future date.
Scneaute Page:256 L
The Company reaquired these bonds in 201-0.256 Line No.: 19 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-1 11176;
2. Order of the ldaho Public Utilities Commission, Order No. 32338, entered August 25,2011;
3. Order of the Public Utility Commission of Oregon, Order No. 1 1334, entered August 26,2011;
Order of the Public Service Commission of the State of Montana. Default Order No. 4535
Expenses may change as invoices related to this i-ssuance
FERC FORM NO.1 (ED.12 450.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) E]An Originar(2) T-1A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2O13lQ4
RECONCILIATION OF REPORTED NEI INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
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. lnclude 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. lndicate clearly the nature of each reconciling amount.
2. lf 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.
_tne
No.
!,anrcutars (uelaIs)
(a)
,\mounI
(b)
1 rlet lncome for the Year (Page 1 17)111,076,833
2
3
4 laxable lncome Not Reported on Books
5 4,167,283
6
7
I
9 )eductions Recorded on Books Not Deducted for Return
10 1 34,569,1 30
11
12
13
14 ncome Recorded on Books Not lncluded in Return
15 8,543,211
16
17
18
19 )eductions on Return Not Charged Against Book lncome
20 -188,476,610
21
22
23
24
25
26
27 :ederal Tax Net lncome 129,011,557
28 Show Computation of Tax:
29 State Tax 2,066,358
30 :ederal Tax Net lncome less state tax 131,077,915
31
32 :ederal Tax @35o/o 45.877.270
33
34 rrior Year & Misc True Ups -6,225,476
35 )abinet Gorge Tax Credits -161 ,682
36 I-otal Federal Expense 39,490,112
37
38
39
40
41
42
43
44
Page 261
Name of Respondent
Avista Corporation
This
(1)
(2\
leoort ls:
5]an originat
;-1A Resubmission
Date of Report(Mo, Da, YQ
o4t1'.12014
Year/Period of Report
End of 20131Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
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. lf the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. lnclude 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. lnclude 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 proportioils of prepaid taxes chargeable to current year, and (c) taxes pald 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.
-tne
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR I axesCharoed
QpringYear(d)
'F6rd
DurinoYear-(e)
Adjust-
ments
(f)
I axes Accrueo(Account 236)(b)
Preoatd laxes
llnclude in Account 165)(c)
1 FEDERAL:
2 lncome Tax 2010 -868,026 253,1 1 8 1,283,663
lncome Tax2011 4,138,388 -127,744 -1,313,384
4 lncome Tax2012 1,429,077 -4,182,457 -3,626,826 1,141,098
lncome Tax (Current)42,305,967 44,861,559 1,111,375
Retained Earnings
7 Prior Retained Earnings -1,392,676 1
8 Prior Retained Earnings -2,070,474
Prior Retained Earnings 't.994.624 -129,426
1 Current Retained Earnings 483.257
11 Total Federal -758,335 37,383,083 41.487.85'.1 1
1
1 STATE OF WASHINGTON:
14 Property Tax (2012)10,622,o'.t2 298,233 't0,919,839
1T Property Tax (2013)1 2,1 00,002 1,035
1 Excise Tax (2010)-22,495
't7 Excise Tax (2012)2,327,224 -33,351 2,293,873
1 Excise Tax (2013)24,687,534 21,825,161
1 Natural Gas Use Tax 610 4,983 4,668 8,182
2C Municipal Occupation Tax 2.542,334 23,002,889 22,492,794
21 Sales & Use Tax (2006)-8,'t73 8,1 73
22 Sales & Use Tax (2011)12 -12
2i Sales & Use Tax (2012)54,903 50,415 -15,149
24 Sales & Use Tax (2013)631,368 535,307 6,988
2l Motor Vehicle Tax (2013)124,978 124,978
2e Total Washington 15,516,427 60,816,636 58,248,070 8,1 82
2i
2t STATE OF IDAHO:
29 lncome Tax (2010)-4,633 4,633
3C lncome Tax (2011)'135,640 117,539 262,836 9,657
31 lncome Tax (2012)-22,958 33,604 't0,646
32 lncome Tax (2013)896,539 960,000
33 Property Tax (2012)3,276,997 -23,426 2,900,575
34 Property Tax (2013)6,626,716 3,307,099
.E Motor Vehicle Tax (2013)26,152 26,152
3€Sales & Use Tax (2005)436 -436
37 Sales & Use Tax (2012)2,1 69 6,554 4,385
38 Sales & Use Tax (2013)1 03,1 70 94,742 -4,385
?c lnigation Credits (201 2)
40 KWH Tax (2012)35,680 -3,625 32,054
41 TOTAL 22,309,64i 129,012,14e 129,217,98t
FERC FORM NO.1 (ED.12-96) page 262
Name of Respondent
Avista Corporation
This ReDort ls:(1) 5]An Orisinat(2) 1-1A Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Yea/Penoo oI Kepon
End of 2013/Q4
TAXES ACCRUED. PREPAID AND CHARGED DURING YEAR (Continued)
5. lf 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 (l) 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 1 09. 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.
EALANCE AT END OF YEAR DISTRIBUTION OF TA S CHARGED Line
No.(Taxes accrued
Account 236)(o)
Prepaid Taxes
(lncl. in Account 165)
Electric
(Account 408.1 , 409.1 )(i)
Extraordinary ltems
(Account 409.3)
Adtustments to Ret.
Earnings (Account 4391(k)
Other
fl)
1
162,519 2
2,697,260 -127,744
2,014,544 -400,213 -3,782,244 4
-3,666,967 34,682,140 7.623,827
€
-1,392,677 7
-2,070,474
-2,124,050 -'t29,426
483,257 483,257 1C
4,863,102 34,154,183 3,228,900 11
12
13
405 137,233 161 ,000 14
12,098,968 9,652,002 2,448,000 15
-22.495 16
49,363 16,012 17
2,862,373 18,969,454 5,718,080 18
9,1 07 5,252 -269 19
3,052,429 17,349,476 5,653,413 20
21
22
-10,661 23
'103,048 631,368 24
124,978 25
18,093,174 46,064,054 14,752,582 26
27
28
4,633 29
1 17,539 30
26,883 6,721 3',l
-63,461 698,624 't97,915 32
352,996 -23,426 33
3,319,617 5,402,049 1,224,667 34
26,152 2E
.436 36
37
4,043 103,170 38
39
-3,626 40
22j03,801 101 ,884,296 27,127,852 41
PageFERC FORM NO. I (ED. 12-96)
Name of Respondent
Avista Corporation
This
(1)
(2\
leport ls:
IAn Original
;-1A Resubmission
Date of Report(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 20131Q4
IAAES AUUKUEU, PKEPAIU ANU UHAKGEU IJUKINU YEAK
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. lf the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. lnclude on this page, taxes paid durlng 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. lnclude 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.
-I tt
No,
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR I AAEUCharoed
vgns(d)
Paid
QtringYear(e)
Adjust-
ments
(0
I axes Accrueo(Account 236)
(b)
PreDato laxes(lnclude in Account 165)
I KWH Tax (2013)339,1 92 320,008
Franchise Tax (2012)1,480.762 1,480,762
Franchise Tax (2013)4.409,709 2.835.752
Total ldaho 4,904,093 12,529,767 12,237.180 9,657
6 STATE OF MONTANA:
lncome Tax (2010)7.714 -7,714
lncome Tax (201 1)389,771 -392,990 3,219
lncome Tax (2012'l 27,779 -95,790
1 lncome Tax (2013)601,062 417,384
11 Property fax Q012)3,600,374 27,500 3.627.443
1 Property Tax (2013)8,1 63,1 29 4.091,832
1 Colstrip Generation Tax 2,948 2,948
14 KWH Tax (2012)279,528 279,528
1:KWH Tax (2013)961,868 794,967
1 Motor Vehicle Tax (2013)3,147 3,'t47
I Consumer Council Tax 34 1 22
1 Public Commission Tax 113 4 74
1 Total Montana 4,305,313 9,263,163 9,217.345 3,219
2C
21 STATE OF OREGON:
22 lncome Tax (2010)-138,944 152,854 403,286 389,376
23 lncome Tax (201 1)7.398 11,679 -295,000 -314,077
24 lncome Tax (2012)231,742 -256.743
2!lncome Tax (2013)886,066 100,000
2e Property Tax (2012)-1,976,033 1,975,925 -107 'l
2i Property Tax (2013)2,249,347 4,335,454
2t Motor Vehicle Tax (2013)'1,607 1,607
2S BETC Credit (2010 and Prior)1,448 38,202 -57,133
3(BETC Credit (2011)-365,909 310,014 25,933
31 BETC Credit (2012)-18,696 -39,093
5z Glendale Regulatory Cr. 2008 -210,889 35,39i 175,492
5J Glendate Regulatory Cr. 2009 70,289 -105,200
34 Franchise Tax (2010)681 -168
AE Franchise Tax (201 'l)26,916 -26,916
3€Franchise Tax (2012)748,205 750,757 27,083
37 Franchise Tax (201 3)3,573,552 2,683,738
3t Total Oregon -1,623,792 8,977,90C 7,979,735 75,298
?c
4C STATE OF CALIFORNIA:
41 TOTAL 22,309,642 '129,012,14t 129,217,98t
PageFERC FORM NO. 1 (ED.12-96)
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]an Originat(2) 1A Resubmission
Date(Mo,of Report
Da, Yr)
o4t11t2014
YeailPenoo or Kepon
End of 2013lQ4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
5. lf 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 defened income taxes or taxes collected through payroll deductions or otherwise pendlng
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (l) 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.
BALANCE AT :ND OF YEAR DISTRIBUTION OF TAXES CHARGED Line
No.(Taxes accrued
Accolnf 236)
Preparo r axes
(lncl. in ffirnt t0s1
Electric(Account 408.1 , 409.1 )(i)
Extraordrnary ltems
(Account 409.3)
AOIUSIMENIS IO l{EI.
Earnings (Account 439)
(k)
Other
fl)
1 9,1 84 339,854 -662 1
2
1,573,957 3,212,543 1,197,167 I
5,206,337 9,652,901 2,876,866 4
A
6
-7,714 7
-392,990 8
-68,011 -95,790 I
183,678 601,062 10
431 27,500 11
4,071,297 8,1 63,1 29 't2
2,948 13
14
166,901 961,868 15
3,147 16
11 17
43 3 18
4,354,3s0 9,660,720 -397,557 19
20
21
152,854 22
11,679 23
-25,00'l -64,'l 86 -192,557 24
786,066 221,516 664,550 25
1,022,574 953,352 26
-2,086,1 07 1,172,534 1,076,812 27
1,607 28
17,483 38,202 29
-29,962 31 0,014 30
-57,789 31
35,397 32
-34,911 33
513 34
35
24,531 36
889,814 3,573,552 37
-550,329 2,3s2,438 6,625,462 38
39
4t
22,103,80'l 101,884,296 27,127,852 41
FERC FORM NO.1 (ED.12-96)Page 263.1
Name ot Kespondent
Avista Corporation
This ReDort Is:(1) fiAn Originat(2) l--lA Resubmission
Date of Reoort(Mo, Da, Yi)
04t11t2014
Year/Period of Report
End of 20131Q4
TAXES ACCRUED, PREPAID ANO CHARGED DURING YEAR
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. lf the
actual, or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. lnclude 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. lnclude 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.
Ltne
No.
Kind of Tax
(See instruction 5)
(a)
tsALANCE AT BEGINNING OF YEAR I dAESCharoed
R{i}s(d)
'Fiffi
R{J?s(e)
Adjust-
ments
(0
r axes Accrueo(Account 236)(b)
IJreDato laxes
ilnclude in Account 165)
1 Income Tax (2011)-6,325 5,52!
lncome Tax (2012)-1,600 1,60C
lncome Tax (20'13)1,600
4 Total California -7,925 7,124 1,600
MISCELLANEOUS STATES:
lncome Tax (2012)1
lncome Tax (2013)-34,438 -88,1 75
Total Misc States 1 -34,43i -88,1 75
1
11 COUNTY & MUNICIPAL
1 Vehicle Excise Tax 5,005 5,005
1 WA Renewable Energy -56'1 -25,26C -25,260
1 Misc.-25,577 89,1 6€66,462 -8J82
1 Total County -26,138 68,911 46,207 -8,182
1
1
1
1
2C
21
22
23
24
25
26
27
28
29
30
31
5/,
v
aa
3(
3i
3t
AC
4C
41 TOTAL 22,309,642 129,012,14t 129,217,98t
FERC FORM NO. 1 (ED.12.96)Page
Name of Respondent
Avista Corporation
lnts Keoon ts:(1) 5]Rn Originat(2) nA Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (CONI|NUECI)
5. lf 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 otheruise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (l) 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.
tsALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accruedAccoln| 236)
Prepaid Taxes
(lncl. in Account 165)
Electric(Account 408.1 , 409.1 )
Extraordinary ltems
(Account 409.3)
Ao.lusrmenrs ro t1el.
Earnings (Account 439,
(k)
Other
(D
No.
-800 5,525 1
1,600 2
1,600 3
-2,400 7,125 4
5
6
1 7
-122,613 -34,438 8
-122,613 -34.437 I
1
11
5,005 12
-561 -25.260 ,|
1't,055 89,166 14
11,616 68,911 15
1€
17
1
19
2C
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
22,1 03,801 't01 .884.296 27,127,852 41
FERC FORM NO.1 (E0.12-96)Page 263.2
Name or Kesponoent
Avista Corporation
This Reoort ls:(1) 5]Rn Originat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2O13lQ4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255
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).lnclude in column (i)
the average period over which the tax credits are amortized.
-tIte
No.
n ucounl
Subdivisions(a)
Ealance at E,eotnntnool Year
(b)
Deferred for Year Currer )calrons IoYear's lncome Adjustments
G)ACCOU(r nmounr
(d)
ACCOUnT NO.(e),\mounI(0
3o/o
4o/o
7o/o
10%
12,420,63f 411 -186,271
TOTAL 12.420,63t -186,271
1(Gas Property (100%62,172 411 15,99(
1 130,24t 411 23,761
TOTAL PROPERTY 192,42C 39,75(
I
1t
1
1(
1
2(
2'
2i
2i
2t
2!
2t
2i
2t
3(
31
3t
5J
3z
3!
3(
3i
3t
?(
4(
41
4i
4i
4t
4t
4e.
4i
4t
FERC FORM NO.1 (ED.12-89)Page
Name ot F<esponoenl
Avista Corporation
This Reoort ls:(1) 5]nn Originat(2) l-lA Resubmission
Date of Report
(Mo, Da, Yr)
0411112014
Year/Period of Report
End of 20131Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)
Balance at Endof Year
rh)
Averaoe Fenoo
of Allocation
to lncome/it
ADJUSTMENT EXPLANATION Ltne
No.
1
2
3
4
5
12,234,367 6
7
12,234,367 8
o
46,176 10
106,488 11
152,664 12
13
14
15
16
17
'18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
.E
3€
37
38
ac
4C
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED.12-89)
Name of Respondent
Avista Corporation
I nrs Keoon ts:(1) 5]An Originat(2) nA Resubmission
uate oI Keoon(Mo, Da, Yi)
04t11t2014
Year/Period of Report
End of 20131Q4
OTHER DEFFERED CREDIT S (Accouni 253)
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.
Line
No.
Description and Other
Defened Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End of Year
(f)
Contra
Account(c)
Amount
(d)
I Defer Gas Exchange (253028)1,499,99C 10 1,500,000
2 Rathdrum Refund (253120)239,57e 550 33,821 205,754
3 NE Tank Spil (253130)16,797 186 1 16,782
4 Bills Pole Rentals (253140)280,96C 15,379 296,339
5 cR-cs2 GE LTSA (2s3150)2,999,302 232 996,1 6i 2,003,140
6 CR-Credit Resource Actg 1,577,531 186 676,085 901,446
7 DOC EECE Grant (253155)752,55C 136 481,17C 271,380
8 Defer Comp Retired Execs (253900)59,24S 431 22,991 36,255
I Defer Comp Active Execs (253910)8,806,1 5C 364,302 9.170,452
10 Executive lncent Plan (253920)140,00c 140,000
11 Unbilled Revenue (253990)683,441 364,833 1,048,274
12 WA Energy Recovery Mechanism 8,756,638 186 8,7s6,63[8,024,194 I,024,194
13 Misc Deferred Credits 80,772 186 238,60f 296,202 138,369
14 REC Deferral 277,0',t0 186 119,171 1,449.11 1,606,948
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
47 TOTAL 26,1 69,966 '1't,324,668 1 0,514,035 25,359,333
FERC FORM NO.1 (ED.12-94)Page 269
This Page Intentionally Left Blank
FERC FORM NO. 1 (ED. 12-96)Page 274
Name of Respondent
Avista Corporation
tnrs KeDon ls:(1) fiAn Original(2) TIA Resubmission
uate oI Kepon(Mo, Da, Yr)
04111t2014
YeailPenod ol Kepon
End of 20131Q4
ACCUMULATED DEFFERED INCOME TMES . OTHER PROPERTY (Account 282)
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.
-tne
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
Amounts Debited
to Account 410.1
(c)
Amounts Credited
to Account 41 1.1
(d)
Electric 276,927,675 14,480,652
Gas 't02.114.468 5,902,039
4 Other 40,174,474 7,562,843
TOTAL (Enter Total of lines 2 thru 4)41 9,216,61 27,945,534
7
TOTAL Account 282 (Enter Total of lines 5 thru 419,216,61 27,945,534
11 Federal lncome Tax 408.150.290 27,945,534
12 State lncome Tax 11,066,323
1 Local lncome Tax
NOTES
Name of Respondent
Avista Corporation
tnrs KeDon ts:(1) 5]An Orlsinal(2) nA Resubmission
Date of Report I Year/Periocl of Report(Mo' Da, Yr) I enO of 2013/e4
04t11t2014
AL;UUMULA I hD UE,I-ER}{EU TNU(JME rA ES - U r rlEK r.KUr.EK r Y (ACCOUnI ZUZ) (Uonlrnueo)
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 41 'l .2
(f)
Debits Credits
Account
Credited(s)
Amount
(h)
Account
Debited
(i)
Amount
0)
291,408,32 2
-61 ,91i 107.954.59r 3
47,737,31 4
-61,91'447,100,23!5
6
7
I
-61 ,9't:447j00,231 9
-6't ,91:436,033,91:11
't1,066,32:12
13
NOTES (Continued)
FERC FORM NO. I (ED. 12-95)Page 275
Name oI Kesponoent
Avista Corporation
This Report ls: I Date of Report(1) [An Original | (Mo, Da, Yr)(2) nA Resubmission | 0411112014
Year/Periocl of Report
End of 2O13lQ4
AL;UUMUI.A IE,L' L'EI-I-EF{ED INCOME IAXES - OTHER (ACCOUNI 263)
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 (Specifo),include deferrals relating to other income and deductions.
-rne
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
to Acco,u"1tt 41 0.1 to Acco(rdlt 411.1
3 Electric 17,538,524 -292,58t 512,038
4
5
€
7
8
c TOTAL Electric (Total of lines 3 thru 8)17,538,524 -292,58t 512,038
11 Gas -1,803,226 1,854,753
12
1
't4
15
1€
17 TOTAL Gas (fotal of lines 11 thru 16)-1.803.226 -1,854,75:
18 Other 229,946,659 -3,863,652
tc TOTAL (Acct 283) (Enter Total of lines 9, 17 and '18)245,681,957 -6,010,99:512,038
21 Federal lncome Tax 245,681.957 -6,010,99:512,038
22 State lncome Tax
23 Local lncome Tax
NOTES
FERC FORM NO.I (ED.12-95)Page 276
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn orisinat(2) nA Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2O13lQ4
ACGUMULA I EL' [JEI.EHRELI INU9ME IAXE,S - (J IHETT (ACCOUNI 263) ((]ONI|NUEC'
3. Provide in the space below explanations for Page 276 and 277. lnclude amounts relating to insignificant items listed under Other,
4. Use footnotes as required.
CHANGFS DI IRING YtrAFI ADJUS'I IIS
Balance at
End of Year
(k)
Line
No.
Amounls ueotleo
to Account 410.2
(e)
Amounts ureo[eo
to Account 4'l 1.2
rfl
Deblts credits
cr?$lted
Amount
(h)
ACCOUnIDebited/i\
,{mounI
(i)
3,570,506 -1,062,903 19,24'.t,501 3
4
5
6
7
I
3,570,506 1,062,903 19,241,501 o
-198,635 -3,856,614 11
12
13
14
15
't5
-198,63{-3.856,614 17
-5,268,539 74,354,921 146,459,547 18
-1,698,033 74,354,92'.1 -'t,261,53t 161,U4,434 19
-1,698,033 74,354,921 -1,261,53t 161.844.434 21
22
23
NOTES (Continued)
FERC FORM NO.1 (ED.12-96)Page Ztl
Name of Respondent
Avista Corporation
I nts i(eoon ls:(1) fien Originat(2) llA Resubmission
uale ot Kepon(Mo, Da, Y0
04t11t2014
YeailHenoo oI Kepon
End of 20'l3lQ4
OTHER REGULATORY -lABlLlTlES (Account 254)
1. Report below the particulars (details) called for concelning 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 $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
Quarterffear
(b)
DEBITS
Credits
(e)
Balance at End
of Cunent
Quarterl/ear
(0
ACCOUnI
Crediled
(c)
t\mounr
(d)
1 ldaho lnvestment Tax Credit (254005)1 2,308,073 190 6,898,s.l 5 5,409,558
2 Oregon BETC Credit (254010)1,553,984 190 r,053,984 500,00c
3 Noxon, ITC (254025)3,344,0'17 190 50,154 3,293,863
4 Settled lnl Rate Swaps (254090)12,965,59 12.965.59C
5 Unsettled lnt Rate Swaps (254100)33,543,251 33,543,25€
6 0regon Commercial Fee (254120)( 1,943)'1,94
7 FAS 109 lnvest Credit (2541 80)103,608 190 21,408 82,20C
8 Nez Perce Q54220\682,364 557 22,008 660,35€
9 Oregon Senate Bill (254250)70,470l,407 1,429 71,89r
10 Decouolino Rebate (254328)5531 407 3.252 2,275
11 BPA Parallel Cap (254331)5,397,101 5,397,1 0€
12 Reo Liabilitv WA Rec's (254360)$,n2 186 93.222
13 U nrealized Cunencv Exchanoe {254399)3,602 143 59,46i 55,861
14 Mark to Market ST 12547401 1
15 Colstrip/CS2 I
16 ldaho PCA r8,566,192 182 1 8,566,19'9,879,39 9,879.394
17 SWAPS on FMBS 1 8,656,780 427 1 8,656,78(
18 Rosebuo/Medford 8,721 8,72t
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 55,244,962 45,426,414 61,923,782 71,742,330
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Report ls:(1) [An Original(2) J-1A Resubmission
L'aIe or KeDon(Mo, Da, Yi)
o4t11t2014
YearHenoo oI Kepon
End of 20131Q4
ELECTRIC OPERATING REVENUES (Account 400)
1 . The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (0, and (g). Unbilled revenues and MWH
related to unbilled revenues need nol be reported separalely as required in the annual version ofthese pages.
2, Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (0 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. lf 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 9250,000 or greater in a footnote for accounts 451, 4s6, and 457.2.
_tne
No.
Title of Account
(a)
Operating Revenues Year
to Date Quarterly/Annual(bl
uperaung Hevenues
Previous year (no Quarlerly)
/c'l
1 Sales of Electricity
2 (440) Residential Sales 331,866,712 315,137,034
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See lnstr. 4)289,604,042 286,567,954
5 Large (or lnd.) (See lnstr. 4)113,631,87€'1 19,588,721
6 (444) Public Street and Highway Lighting 7,266,653 7,240,388
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) lnterdepartmental Sales 1 ,103,974 1,025,713
10 TOTAL Sales to Ultimate Consumers 743,473,259 729,559,810
't1 (447) Sales for Resale 143,390,565 148,004,414
12 TOTAL Sales of Electricity 886,863,824 877,5il,224
13 (Less) (449.1) Provision for Rate Refunds 2.047.837
14 TOTAL Revenues Net of Prov. for Refunds 884,815,987 877,564,224
't5 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451 ) Miscellaneous Service Revenues 590,953 559,797
18 (453) Sales of Water and Water Power 432,332 468,800
19 (454) Rent from Electric Property 3,023,492 2,971,731
20 (455) lnterdepartmental Rents
2'l (456) Other Electric Revenues 135,207,886 124,709,799
22 (456.1) Revenues from Transmission of Electricity of Others 25,386,252 't1,u'l,754
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 164,640,915 140,351,881
27 TOTAL Electric Operating Revenues 1,049,456,902 1,017,916,105
FERC FORM NO. 1/3-Q (REV, 12-0s)Page 300
Name or Hespondent
Avista Corporation
ThiS
(1)
(2')
Reoort ls:
5]Rn originat
T-lA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
YeailPenod ol Hepon
End of 2013/Q4
ELECTRIC OPERATING REVENUES (Account 400)
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 classificauon
in a footnote.)
7. See pages 1 08-'t 09, lmportant 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. lnclude unmetered sales. Provide details of such Sales in a footnote.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH Line
No.Year to Date Qua(erly/Annual
(d)
Amount Previous year (no Quarterly)
(e)
Current Year (no Quarterly)
(f)
Previous Year (no Quarterly)
(o)
3.745.255 3,608,62(321,098 318,69i 2
3, 146,819 3,127,15t 40,202 39,86!4
1,979,324 2,099,64t 1,386 1,39t 5
25,818 25,87t 527 50:b
7
8
12,193 11,69:99 9t 9
8,909,409 8.873.00I 363,312 360,55:10
4,409,585 5,634,39t 't1
1 3,3 t8,994 14,507,40i 363,312 360,55t 12
13
1 3,318.994 14,507,40:363,312 360,55:14
Line 12, column (b) includes $ -543,700 of unbilled revenues.
Line 12, column (d) includes -22,931 MWH relating to unbilled revenues
FERC FORM NO. 1/3-Q (REV. 12-05)Page 301
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn Orlsinat(2) J--1A Resubmission
Date of Report(Mo, Da, Yr)
0411112014
Year/Period of Report
End of 20131Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
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 310-31 1 .
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301 . lf 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.
LIIIE
No.
I DUI
(a)
9919
(b)
n9vEI tuE
(c)
,\verage Numoer
of clso\omers
]\vvn or DatesPer Customer(e)
Kevenue PerKWh Sold(0
1 RESIDENTIAL SALES (440)
1 Residential Service 3,609,234 305,867,84(305,84(11,801 0.0847
2 Residential Service
3 Residential Service
12 Res. & Farm Gen. Service 80,152 10,246,19t 13,43:5,967 0.127t
15 MOPS ll Residential
22 Res. & Farm Lg. Gen. Service 49,76t 4,035,2'1€8(622,10C 0.0811
30 Pumping-Special 17t I 1,00(0.172(
32 Res. & Farm Pumping Service 9,81r 1,051,97:1,734 5,65i 0.1072
1 48 Res. & Farm Area Lighting 4,36f 1,O34,77t 0.237C
11 49 Area Lighting-High-Press.243 74,24i 0.305f
56 Centralia Refund
1 95 Wind Power 150,53:
1 72 Residential Service
1 73 Residential Service
1 74 Residential Service
1 76 Residential Service
77 Residential Service
1!58A Tax Adjustment 48,745,
2(58 Tax Adjustment 9,076,20,
21 SubTotal 3,753,57!33't,488,41 '321,09t 11,69(0.088:
2t Residential-Unbilled -8,32t 378,30(-0.0454
2i Total Residential Sales 3.745.25!331,866,71 321,09t 11,664 0.088e
2t
2!coMMERCTAL SALES (442)
2(2 General Service
21 3 General Service
2t 11 General Service 847,692 91 ,612,62(36,121 23,46t 0.1081
2l 12 Res. & Farm Gen. Service
3(16 MOPS ll Commercial
31 1 9 Contract-General Service
21 Large General Service 1,864,97e 158,010,18,2,95(630,272 0.0847
JJ 25 Extra Lg. Gen. Service 349,401 21 ,122,411 26,877,462 0.060!
3t 28 Contract-Extra Large Serv
3t 31 Pumping Service 92,91!7,564,54',1,10(83,783 0.0814
3t 47 Area Lighting-Sod. Vap 6,192 1 ,340,41(0.216!
3'i 49 Area Lighting-High-Press.2,491 574.89"0.230t
3t 56 Centralia Refune
?C 95 Wind Power 76,741
4C 74 Large General Service
41 TOTAL BiIIed 13.341.921 887,407,52t 363,31'36.72i 0.066t
42 Total Unbilled Rev.(See lnstr. 6)-22,93'-543,70(0.023i
43 TOTAL 13,31 8,992 886,863,82r 363,31:36,66(0.066(
FERC FORM NO.1 (ED. 12-95)Page 304
Name of Respondent
Avista Corporation
This Reo(1) E(2) -
ort ls:
An Original
A Resubmission
Date of Report I Year/Period of Report
(Mo, Da, Yr) I ena of 211gte40411112014 I
-
SALES OF ELECTRICITY BY RATE SCHEDULES
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 . lf 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 yeat (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.
Ltne
No.
rrurilurr dilu I tue ut r.(ale scneoute
(a)
MVVn UO|O
(b)^EVgilUg(c)
f\vetagE t\utIlIJel
of Cys.j\omers
KWn OI 5aresPer Customer(e)
KEVENUE HETKWh Sold(f)
1 75 Large General Service
76 Large General Service
77 General Service
58A Tax Adjustment 47,84t
58 Tax Adjustment "t0,473,53r
SubTotal 3,163,67:290,727,52t 40,201 78,69r 0.09 t9
Commercial-Unbilled -16,85,1,123,47t 0.0667
Total Commercial 3,'146,81(289,604,041 40,201 78,27!0.092c
1(INDUSTRIAL SALES (442)
11 2 General Service
1i 3 General Service
1:I Lg Gen Time of Use
1 'l 1 General Service 9,79:1,089,65(25/38,554 0.1'1 13
1 12 Res. & Farm Gen. Service
1 21 Large General Service 210,36(1 7,1 99,61 1 161 1,298,55f 0.0818
1i 25 Extra Lg. Gen. Service 1,673,07(87.564,66,/1 92,948,33:0.0523
1t 28 Contract - Extra Large Service
1(29 Contract Lg. Gen. Service
2(30 Pumping Service - Special 20,86t 1,423,04i 3 673, 1 61 0.068i
21 31 Pumping Service 58,56 4,920,69:771 75,46t 0.084(
32 Pumping Svc Res & Firm 4,13'345,87t 14!28,49(0.083i
2a 47 Area Lighting-Sod. Vap.22t 48,1 37 o.2't3(
2t 49 Area Lighting - High-Press 6 13,03:0.2't3i
2!95 Wind Power 1,72t
2t 48 Area Lighting-Sod. Vap.I 344 0.344(
ll 73 General Service
2t 74 Large General Service
2l 75 Large General Service
3(76 Pumping Service
31 77 General Service
Ct 58A Tax Adjustment 1,12t
3:58 Tax Adjustment 824,74'
3t SubTotal '1.977.07i 113,430,40(1,38(1,426,462 0.0574
ea lndustrial-Unbilled 2,24i 201,47t 0.0897
3(Total lnduskial 1,979,32t 113,631,87t 1,38(1,428,081 0.0574
31
3t STREET AND HWY LtGHTtNG (444
3!6 Mercury Vapor St. Ltg.
4(7 HP Sodium Vap. St. Ltg
41 TOTAL BiIIed 13,341,921 887.407.521 363,31:36,72i 0.0661
42 Total Unbilled Rev.(See lnstr. 6)-22,93 -543,70(0.023;
43 TOTAL 13,318,99,886,863,822 363,31'36,66{0.066(
FERC FORM NO.I (ED.12-95)Page
Name of Respondent
Avista Corporation
I nts Keoon ts:(1) 5]Rn Original(2) nA Resubmission
uale or Kepon(Mo, Da, Y0
04t1',U2014
YearPenoo oI Kepon
En6 q1 2013/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
'l . 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 . lf 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.
-tne
No.
truiltuEr dilu I [tE 9t nattr ]uilguutE
(a)
tvtvYil outu
(b)
Kevenue
(c)
AVetdgt trulItuEr
of Customers/d)^vvn oI uares
Per Customer(e)TW['H"fd"'(f)
11 General Service 10t 't2,52i 21,00(0.1 19:
41 Co-Owned St. Lt. Service 21t 42,29(1 13,624 0.194(
42 Co-Owned St. Lt. Service 20,62t 6,530,76'392 52,35(0.316€
High-Press. Sod. Vap.
43 Cust-Owned St. Lt. Energy 911 1 9,00(0.1012
and Maint. Service
44 Cust-Owned St. Lt. Energy 69t 69,28;3(23,06i 0.1 001
and Maint. Svce - High-Pres
Sodium Vapor
I 45 Cust. Owned St. Lt. Energy Svc 1,38{97,39t 'tt 86,56:0.070:
11 46 Cust. Owned St. Lt. Energy Svc 2,78i 257.66'.1 6t 42,81!0.0926
1 58A Tax Adjustment -73(
1 58 Tax Adjustment 256,55t
1 SubTotal 25,81t 7,266,651 521 48,991 0.281!
1 Street & Hwy Lighting-Unbilled
1 Total Street & Hwy Lighting 25,81t 7.266.65t 52i 48,991 0.281!
1
1{OTHER SALES TO PUBLIC
1 (445)
2(None
21
22 INTERDEPARTMENTAL SALES 12,191 1,102,12i o(123,16i 0.09M
2a 58 Tax Adjustment 1,84i
2t Total lnterdepartmental 12,19i 1j03,971 9!123.16i 0.090r
2!
2t SALES FOR RESALE (447)4.409.58t 143,390,56:0.032f
2i 61 Sales to Other Utilities (NDA)
2t
2l
3(Total Sales for Resale 4,409,581 143,390,564 0.032t
31
Jt
3:
3t
at
3(
3i
3t
?C
4(
41 TOTAL Billed 13,341,921 887,407,52t 363,31:36,72i 0.066{
42 Total Unbilled Rev.(See lnstr. 6)-22,93 -543,70(0.023i
43 TOTAL 1 3,318,99,886,863,82r 363,3'1:36,66(0.066(
FERC FORM NO.I (ED. 12-95)Page 304.2
This Page Intentionally Left Blank
Name oI Kespondent
Avista Corporation
tnts Ket(1) E(2) I-lAn Original
lA Resubmission
Date of Report(Mo, Da, Y0
04t1112014
Year/Period of Report
End of 2O13lQ4
SALES FOR RESALE (Account 447)
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. ln 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). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for tong{erm 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.9., 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.
lF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer tha4 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.
lU - 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.
_tne
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
rvrontnfi"fi6d'oeman
(e)
Averaoe
Monthly CP-Demant
(f)
BP Energy Company SF ISDA
2 BP Energy Company SF Tariff 9
3 Black Hills Power, lnc.SF Tariff 9
4 Bonneville Power Administration LF Tariff 8
5 Bonneville Power Administration LF ACS-06
6 Bonneville Power Administration SF Tariff 9
7 Bonneville Power Administration LF Taritl 12
8 British Columbia Hydro and Power Author LF Tarifi 12
I Brookfield Energy Marketing LP SF Tarifi 9
10 Burbank, City of SF Tariff 9
11 Calpine Energy Services LP SF Tarifi 9
12 Cargill Power Markets, LLC SF Tariff 9
13 Chelan County PUD No. 1 SF Tariff 9
14 Chelan County PUD No. 1 LF Tarifl 12
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO.1 (ED.12-90)Page 310
Name of Respondent
Avista Corporation
rnrs Kepoft rs:(1) ffiAn Originat(2\ l_lA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
SALES FOR RESALE (ACCount 447)(Continued)
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 Outof-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. ln Column (c), identifo 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 (0. 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 O. 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.
MegaWatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
LIner unarges
($)
(i)
5,224,071 5,224,071 1
2s5,866 7,207,638 7,207,63t 2
2,400 44,680 44,68(3
16,412 579,1 06 579.1 0(4
1,783 47,191 47,191 5
161 ,486 4,510,379 4,510,37!6
80 2,607 2,601 7
39 1,604 1,602 I
1,200 164.00(164,00(9
400 6,20(6,20(10
276,556 6,399,92:6,399,92:11
176,441 5.172.39i 5,'172,39:12
8,800 262,94C 262,94t 13
1 41 41 1A
0 0 0 0 0
4,409,585 5,179,351 119,562,425 18,648,789 143,390,565
4,409,585 5,179,351 119,562,425 18,648,789 143,390,565
FERC FORM NO.1 (ED.12-90)Page 311
Name ot Hespondent
Avista Corporation (1) E(2) l-
DON IS:
]An original
lA Resubmission
uale o, Kepon(Mo, Da, Yr)
04111t2014
YearHenoq or Kepon
End of 20131Q4
SALES FOR RESALE (Account 447)
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. ln 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). ln 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.9., 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.
lF - for intermediate-term firm seryice. The same as LF service except that "intermediate{erm" means longer than one year but Less
than five years.
SF - for short{erm 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.
lU - 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.
-tne
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVEI AgE
\4onthly NCF Deman
(e)
AVeraoeMonthly CPDemanr
(0
I Citigroup Energy, lnc.SF Tariff 9
2 Clark County PUD No. 1 SF Tariff 9
3 Clatskanie Peoples PUD SF Tariff 9
4 Constellation Energy Commodities Group SF Tariff 9
5 Douglas County PUD No. I SF Tariff 9
6 EDF Trading North America, LLC SF Tariff 9
7 Eugene Water & Electric Board SF Tariff 9
I Exelon Generation Company, LLC SF Tariff 9
I Grant County PUD No. 2 SF Tariff 9
10 Grant County PUD No. 2 LF Taritt 12
11 Grant County PUD No. 2 SF Tariff 9
12 lberdrola Renewables, LLC SF Tariff 9
13 lberdrola Renewables, LLC SF Tariff 9
14 lberdrola Renewables, LLC SF Tariff 9
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO. 1 (ED.12-90)Page
Name of Respondent
Avista Corporation
This Reoort ls:(1) fiRn Originat(2) llA Resubmission
Date of Report I Year/Period of Report
(Mo, Da, Yr) | End ot 2013/e404t11t2014 I
-
SALES FOR RESALE (Account 447)(Continued)
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. ln 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 O. Explain in a footnote all components of the amount shown in column O. 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.
MegaWatt Hours
Sold
(q)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
gtner unarges
($)
(i)
33,280 913,262 913,26i ,|
21,250 834,1 07 834,1 0i 2
4.225 141 ,145 14',t,',t4t 3
2,574 68,540 68,54(4
7,880 289,0 t 1 289,011 5
90,784 2,765,275 2,765,27!b
12,935 462,685 462,68a 7
17,202 514,1 03 51 4,1 0:8
8,097 248.577 248,571 9
9 269 26!10
1,80(1,80(11
337,924 9,934,031 9,934,031 12
353,75(353,75(13
1,00(1,00(14
0 0 0 0 0
4,409,585 5.179,351 119,562,425 18,648,789 143,390,565
4,409,585 5,179,351 119,562,425 18,648,789 143,390,565
FERC FORM NO.1 (ED.12-90)Page 31 1.1
Name of Respondent
Avista Corporation
tnts x(1) t(2\ r
pon ls:
]An originat
lA Resubmission
Date of Report(Mo, Da, Yr)
04111t2014
YeailPenocl 01 t{epon
End of 20131Q4
SALES FOR RESALE (Account 447)
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. ln 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). ln 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{erm service. "Long{erm" 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.9., 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.
lF - 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.
lU - 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.
_rne
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthry Billing
Demand (MW)
(d)
Actual Demand (MW)
n vtt aqc
lVlonthly NCF Deman
(e)
AVeraoeMonthly CP-Demanc
(0
1 ldaho Power Company SF Tariff 9
2 ldaho Power Company LF Tarill 12
3 ldaho Power Balancing SF Tariff 9
4 J. Aron & Company SF Tariff 9
5 JP Morgan Ventures Energy SF Tariff 9
b Macquarie Energy, LLC SF Tariff 9
7 Mizuho Securities USA, lnc.SF ISDA
8 Modesto lrrigatlon District SF Tariff 9
o Morgan Stanley Capital Group, lnc.3F Tariff 9
10 Morgan Stanley Capital Group, lnc.SF Tariff 9
11 Morgan Stanley Capital Group, lnc.SF Tariff 9
12 Morgan Stanley Capital Group, lnc.SF Tariff 9
13 NaturEner Power Watch, LLC SF Tariff 9
14 NaturEner Power Watch, LLC LF Tarift 12
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO.I (ED.12-90)Page 310.2
Name of Respondent
Avista Corporation
lhts ReDon ls:(1) finn Originat(2) l-lA Resubmission
uale or Kepon(Mo, Da, Yr)
04t11t2014
YeailF,enoo oI Kepon
End of 2013/Q4
SALES FOR RESALE (Account 447 (Continued)
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. ln 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 (0. Explain in a footnote all components of the amount shown in column O. 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 instructlon 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.
MegaWatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+D
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
other charges
($)
(i)
26,334 855,'198 855,'t9{1
35 't,236 1,23(2
131 ,836 4,656,686 4,656,68(3
20,025 583,275 583,27I 4
59,432 1,574,545 1,574,54!5
113,663 3,244,411 3,244,41 o
-2,013. 194 -2,01 3,192 7
4,392 186,616 'r86,61r 8
,l62,693 5,060,972 5,060,97i 9
62,741 62,74t 10
870,311 870,311 11
41,65(41,65(12
4,597 145,206 145,20(13
33 1,134 1,13t 14
0 0 0 0 0
4,409,585 5,179,351 119,562,425 18,648,789 143,390,565
4,409,585 5,179,351 119,552,425 't 8,548,789 143,390,565
FERC FORM NO.1 (ED.12-90)Page 311'2
Name of Respondent
Avista Corporation (1) E(2) T
oon ls:
]nn originat
lA Resubmission
Date of Report(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 2O13lQ4
SALES FOR RESALE (Account 447)
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. ln 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). ln 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{erm" 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.9., the supplier must attempt to buy emergency energy
from third partles 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
lF - 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{erm" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
lU - 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.
_tne
No.
Name of Company or Public Authority
( Footn ote Affi liation s)
(a)
Statistical
Classifi-cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVeI aut
vlonthly NCF Deman
(e)
AVeraoeMonthly CP-Deman<
(0
1 NaturEner Power Watch, LLC SF Tariff I
2 NaturEner Power Watch, LLC SF Tariff 9
3 NaturEner Power Watch, LLC SF Tariff 9
4 Newedge USA, LLC SF ISDA
5 NextEra Energy Power Market SF Tariff 9
b Noble America Gas & Power S.F Tariff 9
7 NorthWestern Energy LLC SF Tariff 9
I NorthWestern Energy LLC LF Taritf 12
9 NorthWestern Energy LLC LF Tariff 9
10 NorthWestern Energy LLC SF Tariff 10
't'l Okanogan County PUD SF Tariff 9
12 PacifiCorp SF Tariff 9
13 PacifiCorp LF Tarifi 12
14 PacifiCorp LF Tariff 9
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO.1 (ED.12-90)
Name of Respondent
Avista Corporation
rnrs KeporI rs:(1) EAn Original(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
SALES FOR RESALE (Account 447:(Continued)
OS - for other service. use this category only for those services which cannot be placed in the above-deflned 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) afier this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. ln 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 (0. For all other types of service, enter NA in columns (d), (e) and (f1. 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 O. Explain in a footnote all components of the amount shown in column O. 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.
Megawatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
(Jtner unarges
($)
(i)
98,41€98,41(1
276,182 276,18'2
1 ,|3
-5,420,862 -5,420,86i 4
1,903 62,769 62,76(5
10,600 349,74C 349,74(6
87,692 3,565,645 3,565,64{7
87 2,551 2,551 8
7,369 227,609 227,601 9
1,165,95{1 ,1 65,95{10
11,730 466,691 466,691 11
135,355 4,435,355 4,435,35{12
250 7,668 7,66t 13
4,691 144.842 144.84i 14
0 0 0 0 0
4,409,585 5,179,351 1'.tg,s62,425 18,648,789 143,390,565
4,409,585 5,179,351 119,562,425 18,648,789 143,390,565
FERC FORM NO.1 (ED.12-90)Page 31 1.3
Name of Respondent
Avista Corporation
tnrs x(1) t(2\ l'
oon ts:
]nn originat
lA Resubmission
Date of Report(Mo, Da, Yr)
04t11t20'14
Year/Period of Report
End of 2O13lQ4
SALES FOR RESALE (Account 447)
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. ln 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). ln addition, the reliability of requirements service must
be the same as, or second only to, the supplie/s service to its own ultimate consumers.
LF - for tong{erm 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.9., 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.
lF - 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.
lU - 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.
-ine
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
nvEt aug
Monthly NCF Deman
(e)
Averaoe
Monthly CP'Demanc
(0
1 Peaker LLC LF Tariff 9
2 Pend Oreille Public Utility District LF Tariff 9
3 Pend Oreille Public Utility District LF Tariff 9
4 Pend Oreille Public Utility District SF Tariff 9
5 Pend Oreille Public Utility District LF 290 (PNCA)
6 Portland General Electric Company SF Tariff 9
7 Portland General Electric Company LF Tarill 12
8 Powerex SF Tariff 9
I Powerex SF Tariff '10
10 PPL EnergyPlus, LLC SF Tariff 9
11 PPL EnergyPlus, LLC SF Tariff 9
12 PPL EnergyPlus, LLC -F Tariff 9
13 Puget Sound Energy -F Tariff 9
14 Puget Sound Energy SF Tariff 9
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO.1 (ED.12-90)Page 310.4
Name of Respondent
Avista Corporation
tnrs Kepon rs:(1) [An Original(2) l-lA Resubmission
Date of Report I Year/Period of Report
(Mo' Da' Yr) I end or 2o13te4o4t11t2014 |
-
SALES FOR RESALE (Account 447) (Continuecl)
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 Outof-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. ln 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 supplie/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 O. Explain in a footnote all components of the amount shown in column O. 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.
MegaWatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
urner unarges
($)
(i)
1,748,41!1,748,414 1
438,141 438.141 2
14,658 466,29t 466,29€3
55,496 1,614,82i 1,614,82i 4
10,75t 10,75t 5
94,981 3.316.44f 3,316,44t 6
70 2,27e 2,27e 7
360,921 9,872,092 9,872,092 8
8(8(9
15,63(15,63(0
49,153 1,682,36t 1,682,36t 1
16,746 517,293 517,29i 2
21 ,437 662,1 3€662,1 3(3
203.003 6.800,98€6,800,98(4
0 0 0 0 0
4,409,585 5,179,351 119,562,425 18,648,789 143,390,565
4,409,585 5,179,351 119.562.425 18,648,789 143,390,565
FERC FORM NO.1 (ED.12-90)Page 31'1.4
Name of Respondent
Avista Corporation (1) E(2) T
)on ts:
]An Original
IA Resubmission
Date of Report(Mo, Da, Yr)
04111t2014
YeailPenoo oI Kepon
End of 2O13lQ4
SALES FOR RESALE (Account 447)
1. Report all sales for resale (i.e., sales lo purchasers other than ultimate consumers) transacted on a seftlement 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. ln 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). ln 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.9., 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.
lF - 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{erm 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 unil
lU - for intermediate-term service from a designated generating unit. The same as LU service except that 'lintermediate-term" means
Longer than one year but Less than five years.
-tne
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthry Billing
Demand (MW)
(d)
Actual Demand (MW)
AVEI AUE
Vlonthly NCF Deman
(e)
AVeraoeMonthly CP-Demanc
(0
Puget Sound Energy LF f arill 12
2 Rainbow Energy Marketing SF Tariff 9
3 Redding, City of 3F Tariff 9
4 Sacramento Municipal Utility District SF Tariff 9
5 Sacramento Municipal Utility District LF Taritl 12
6 Sacramento Municipal Utility Districl LF Tariff g
7 San Diego Gas & Electric Company 3F Tariff 9
I Seattle City Light SF Tariff 9
9 Seattle City Light LF Tarill 12
10 Shell Energy N.A.SF Tariff 9
11 Sierra Pacific Power Company SF Tariff 9
12 Sierra Pacific Power Company LF f arifi 12
13 Snohomish County PUD SF Tariff 9
14 Southern California Edison Company SF Tariff 9
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO.1 (ED.12-90)Page
Name of Respondent
Avista Corporation
tnts Keoon ts:(1) fiRn originat(2) f-lA Resubmission
uale oI Kepon(Mo, Da, Y0
o4t1112014
Year/Period of Report
End of 20131Q4
SALES FOR RESALE (Account 447) (Continued)
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. ln 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 O. Explain in a footnote all components of the amount shown in column O. 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.
Megawatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy L;narges
($)
(i)
ulner unarges
($)
(i)
24 962 96'I
49,450 't,288,442 1.288.441 2
208 8,',t12 8,11 3
74,423 2,593,434 2,593,431 4
3 95 9t 5
525,470 22.319.114 22,319,11 6
3,400 89,000 89,00(7
10,877 323,918 323,9'1t 8
20 495 49t o
427,743 13,569,679 '13,569,67!10
39,390 1 , 't47,016 1,147,01(11
53 1,628 '1,62t 1
20,111 719,876 719,87t 13
600 1 3,1 00 I 3,1 0(14
0 0 0 0 0
4,409,585 5,1 79,351 119,562,425 't8,648,789 143.390,565
4,409,58s 5,179,351 't 19,562,425 18,648,789 143,390,565
FERC FORM NO.1 (ED.12-90)Page 31'1.5
Name of Respondent
Avista Corporation (1) E(2\ r
,ort lS:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
041'.t1t2014
Year/Period of Report
End of 2O13lQ4
SALES FOR RESALE (Account 447)
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. ln 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). ln 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{erm" 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.9., 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{erm 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.
lF - for intermediate-term firm service. The same as LF service except lhat "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.
lU - 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.
Line
No:
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule orTariff Number
(c)
Averaoe
Monthry Billing
Demand (MW)
(d)
Actual Demand (MW)
AVEIdqE
Vlonthly NCF Deman
(e)
AVeraoeMonthly CP-Demanc
(0
1 Sovereign Power LF Tarifi 9
2 Sovereign Power LF Tariff 9
3 Tacoma Power SF Tariff 9
4 Tacoma Power LF Taritt'!2
5 Tacoma Power SF Tariff 9
b Tacoma Power 3F Tariff 10
7 Tenaska Power Services Co.SF Tariff 9
8 The Energy Authority SF Tariff 9
9 TransAlta Energy Marketing JF Tariff 9
10 Turlock lrrigation District SF Tariff 9
't1 United Materials of Great Falls, lnc.SF Tariff 10
12 lntraCompany Wheeling LF
13 lntraCompany Generation LF
14
Subtotal RQ 0 0
Subtotal non-RQ 0 0
Total 0 0
FERC FORM NO.1 (ED.12-90)Page 310.6
Name oI F(espondent
Avista Corporation
tnrs Keoon ts:(1) fiRn Original(2\ l-lA Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 20131Q4
SALES FOR RESALE (Account 447 (Continued)
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. ln 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 saies 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 O. Explain in a footnote all components of the amount shown in column O. 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.'t0. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Sold
(s)
REVENUE Total ($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
urner unarges
($)
fi)
77.884 77,881 1
10,572 333,022 333,02i 2
19,074 466,42a 466,42!3
o.:bJ 4
1,92C 1,92(5
6(6(6
79 7 37e 7,37(7
39,232 1 ,219,98€1,219,98t 8
143,449 4,338,517 4,338,51'I
8,600 249.848 249.U(10
14,U(14,64(11
-20.204.255 20,204,25a 12
654,51 654,51 13
14
0 0 0 0 0
4,409,585 5,179,351 119,562,425 18,648,789 143,390,565
4,409,585 5,179,351 119,562,425 18,648,789 143,390,565
FERC FORM NO.1 (ED.12-90)Page 311.6
iSchedule Page: 310 Line No.:1 Column: b I___J
SWAPll-cneai page:310 -Line No.:4 Cotumn: b
--
NWPP Reserve Shari-nq Sales
@1e-q,49_!3g9, 310
Capacity
6ch;dnte Paoe: 310.2 L'tne No.2 Column: b I
Capacit
Column: b
310.3 Line No.: I Column: b
NWPP Reserve Sharinq Sales
NorthWestern Energy LLC sale expires October 31, 2018.
i
NWPP Reserve Sharinq Sales
310.3 Line No.: 14 Column: b
Paci sale terminat,es r 31, 2018.
Peaker, LLC capacitrz contract terminates December 31 20L6.
310.4 Line No.:2 Column: bContractres 9/30/20]-4-
Contract res 9 201-4.
i
NWPP Reserve Sharing Sales
PPL sale terminates OcEober 31, 2018.
Name of Respondent
Avista Corooration
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
2013to,4
FOOTNOTE DATA
BPA Contract Terminates September 30, 2028.
BPA Cont,ract, TerminaEes ,January 1, 2036.
NWPP Reserve Shar
310 Line No.: 5 Column: b
310 Line No.:7 Column: b
MIPP Reserve Sharinq Sa1es
NWPP Reserve Sharing Sales
SWAP
310.2 Line No.: 11
310.3 Line No.: 2 Column: b
310.3 Line No.: 3 Column: b
310.3 Line No.:4 Column: b
SWAP
310.4 Line No.: 13 Column: b
Puget Sound Energy sale terminates October 31, 2018.
310.4 Line No.: 1 Column: b
310.4 Line No.: 3 Column: b
310.4 Line No.: 5 Column: b
FERC FORM NO.1 (ED.1 450.1
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013/Q4
FOOTNOTE DATA
: 310.5 Line No.: 5 Column: b
Contract ires 201-4.
I
€Sle!y!ef.99-319.6 _Line No.:1- Cotumn: b
Sovereiqn Power contract terminates l--31--201-5
I
: 310.5 Line No.:9 Column: b
:310.6 Line No.:2 Column: b
Power Contract terminates L-31--2015:310.6 Line No.:4 Column: b
NWPP Reserve Sharinq Sales
: 310.6 Line No.: 12 Column: a
: 310.6 Line No.: 12 Column: bIntracompany Wheeling terminates 09/30/2023.
Fchedule Page: 310.6 Line No.: 13Schedule Page: 310.6 Line No.: 13 Column: a IIntracompanv Generati-on - Sale of Ancillary Services
: 310.6 Line No.: 13 Column: b
Intracompany Generation - Sale of Ancil-lary ServJ-ces.
FERC FORM NO. 1 (ED. 1 450.2
Name or Responoent
Avista Corporation
This Reoort ls:(1) 5.1an originat(2) nA Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2O13lQ4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
-rne
No.
Account
(a)
Amount forCurrent Year
(b)
Amount forPrevious Year
(c)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Enqineerino 281.941 405,853
5 (501) Fuel 24,772,509 27,965,08C
6 (502) Steam Expenses 4.1 98, 'l 97 4,007.068
7 (503) Steam from Other SourcesILess) (504) Steam Transferred-Cr.
9 (505) Electric Expenses 1.017,827 903,81i
'10 (506) Miscellaneous Steam Power Exoenses 2,880,54C 2,366,64(
11 (50il Rents 33.093 21.91i
12 1509) Allowances
13 TOTAL Ooeration (Enter Total of Lines 4 thru 12)33,1 84,1 07 35.670.381
14 Maintenance
15 (510) Maintenance Suoervision and Enoineerino 457,703 496,86(
16 (51 1) Maintenance of Structures 680.76€607.1 3t
17 (512) Maintenance of Boiler Planl 6,100,955 4.845,431
't8 (513) Maintenance of Electric Plant 1,172,747 58/..21t
19 '514) Maintenance of Miscellaneous Steam Plant 799,354 565,1 41
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19)9,211,52e 7,098,78t
21 TOTAL Power Production Exoenses-Steam Power (Entr Tot lines l3 & 20)42,395,635 42.769J6e
22 B. Nuclear Power Generation
23 Operation
24 '517) Operation Supervision and Enoineerinq
25 (518) Fuel
26 (5'19) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Exoenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Suoervision and Enoineerino
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Eouioment
38 (531) Maintenance of Electrlc Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 [535) Ooeration Suoervision and Enoineerino 1.908.948 2.403.16t
45 (536) Water for Power 1,303,492 1,177.031
46 (537) Hydraulic Expenses 7.200.656 7.432.593
47 (538) Electric ExDenses 6.644.506 6,299,33€
48 (539) Miscellaneous Hydraulic Power Generation Expenses 716.O24 620,314
49 (540) Rents 6.851.497 6,8'10.597
50 TOTAL Operation (Enter Total of Lines 44 thru 49)24,625,123 24,743,043
5'l C. Hvdraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Enqineerinq 549,213 583,1 9€
54 (542) Maintenance of Structures 979.941 606,14€
55 (543) Maintenance of Reservoirs, Dams, and Wateruays 1,781,796 1,355,754
56 (544) Maintenance of Electric Plant 4,157,781 2.804.74
57 (545) Maintenance of Miscellaneous Hvdraulic Plant 578,1 69 485,261
58 TOTAL Maintenance (Enter Total of lines 53 thru 57)8,046,900 5.835.101
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)32.672.023 30,578.144
FERC FORM NO.1 (ED.12-93)Page 320
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn origlnat(2) J--1A Resubmission
Date of Report(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 20131Q4
ELECTRIC OPERATION AND MAINTENANCI EXPENSES (Continued)
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
-lne
No.
Account
(a)
Amount forCurrent Year
(b)
Amount forPrevious Year(c)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Enqlneerinq 1,394,573 1,289,90€
63 (547) Fuel 110,462,332 64,054,801
64 (548) Generation Exoenses 2.146.858 1,693,501
65 (549) Miscellaneous Other Power Generation Expenses 462,952 619,29i
66 (550) Rents -27,127 50,65i
67 TOTAL Operation (Enter Total of lines 62 thru 66)114.439.588 67.708.151
68 Maintenance
69 (551) Maintenance Supervision and Engineering 't .080.319 'l .867.04:
70 (552) Maintenance of Structures 50,978 12.411
71 (553) Maintenance of Generatino and Electric Plant '1,994,695 7,706,56C
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 182,724 161 ,20(
73 TOTAL Maintenance (Enter Total of lines 69 lhru 72)3,308,716 9,747,221
74 TOTAL Power Production Exoenses-Other Power (Enter Tot of 67 & 73)117,748.304 77.455.37(
75 E. Other Power Supplv Exoenses
76 (555) Purchased Power 205,763,918 239,356,42(
77 (556) Svstem Control and Load Disoatchino 965,965 864.53;
78 (557) Other Expenses 121.667.121 145,305,65:
79 TOTAL Other Power Suoolv Exo (Enter Total of lines 75 thru 78)328,397,004 385,526,621
80 TOTAL Power Production Exoenses ffotal of lines 21 , 41 , 59. 74 & 79)521.212.966 536.329.30;
81 2. TMNSMISSION EXPENSES
82 Operation
83 1560) Operation Supervision and Enoineerinq 2,476,590 2,165,26t
84
85 (561.1 ) Load Disoatch-Reliability 24.584 14,37!
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 1,296,586 1,175,921
87 (561.3) Load Dispatch-Transmission Service and Schedulino 1,107.366 962,64t
88 (561.4) Schedulinq. System Control and Dispatch Services
89 (561.5) Reliability, Planninq and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation lnterconnection Studies
92 (561.8) Reliabilitv. Plannino and Standards Develooment Services
93 (562) Station Expenses 457,928 419.662
94 (563) Overhead Lines Exoenses 525,234 468,93(
95 1564) Underoround Lines Expenses
96 (565) Transmission of Electricitv bv Others 17,926,901 17,551 ,614
97 '566) Miscellaneous Transmission Exoenses 1.969.445 1,787,281
98 (567) Rents 101,82:1't5.92!
99 TOTAL Operation (Enter Total of lines 83 thru 98)25,886,457 24,661,631
100 Maintenance
101 (568) Maintenance Supervision and Enqineerinq 1,095,334 2,123,80i
102 '569) Maintenance of Structures 384.45!451.661
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Software
105 (569.3) Maintenance of Communication Equipment
106 (569.4) Maintenance of Miscellaneous Reqional Transmission Plant
107 (570) Maintenance of Station Equipment 1,353,879 1 ,1 39,39€
108 (57'l) Maintenance of Overhead Lines 1.473.05C 1,750.864
109 (572) Maintenance of Underqround Lines 21,166 8,37i
'1 10 (573) Maintenance of Miscellaneous Transmission Plant 49.081 96.1 93
111 TOTAL Maintenance fiotal of lines 101 thru 110)4 376 96!5.570.298
112 TOTAL Transmission Expenses (Total of lines 99 and I 1 1)30,263,426 30,231,93C
FERC FORM NO.1 (ED. 12-93)Page 321
Name of Respondent
Avista Corporation
This Reoort ls:(1) finn Originat(2) ;'-1A Resubmission
uale or Hepon(Mo, Da, Yr)
o4l'11t2014
YeailPenoo oI Kepon
End of 20131Q4
ELECTRIC OPERATION AND MAINTENANCI EXPENSES (Continued)
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
-tne
No.
Account
(a)
Amount forCurrent Year
(b)
Amount forPrevious Year
(c)
113 3. REGIONAL MARKET EXPENSES
114 Ooeration
115 (575. 1 ) Ooeration Supervision
116 (575.2) Day-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Riohts Market Facilitation
118 (575.4) Capacitv Market Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitorinq and Compliance
121 (575.7) Market Facilitation, Monitorinq and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 1 15 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and lmprovements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenancc of Computer Software
128 (576.4) Maintenance of Communication Eouioment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Reqional Transmission and Market Oo Exons ffotal 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Enoineerinq 2,459,976 2,195,632
135 (581) Load Disoatchino
136 (582) Station Exoenses 658,1 64 631,08C
137 (583) Overhead Line Expenses 2,570,589 2.900.414
138 (584) Underoround Line Exoenses 1.208,803 1.054.524
139 (585) Street Liqhtinq and Siqnal Svstem Expenses 96,492 166,25€
140 (586) Meter Exoenses 2,535,81C 2,249,211
141 (587) Customer Installations Expenses 723,178 676.051
142 (588) Miscellaneous Exoenses 6,388.373 7.563.801
143 (589) Rents 165,29C 352,1 08
144 TOTAL Ooeration (Enter Total of lines 134 thru 143)16.806.675 17.789.077
145 Maintenance
146 (590) Maintenance Suoervision and Enoineerino 1.693.053 1.720.09:
147 (59'l) Maintenance of Structures 338,632 370,67t
148 (592) Maintenance of Station Equipment 1,098,23'886,84!
149 '593) Maintenance of Overhead Lines 8.701 ,261 8,225.64(
150 (594) Maintenance of Underqround Lines 1,093,965 1.007.65t
151 (595) Maintenance of Line Transformers 863.1 7(972.94t
152 (596) Maintenance of Street Liohtinq and Siqnal Svstems 809,99t 674.261
153 (597) Maintenance of Meters 33,251 62.37i
154 '598) Maintenance of Miscellaneous Distribution Plant 433.201 495,77C
'155 TOTAL Maintenance (Total of lines 146 thru 154)15,064,78(14,416,27t
156 TOTAL Distribution Exoenses (Total of lines 144 and 155)31.871.45t 32.205.351
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 [901) Supervision 353,964 577,88:
160 (902) Meter Readins Expenses 3,209,97:2.905.71i
161 '903) Customer Records and Collection Exoenses 8.851.'l6t 8.191.471
162 (904) Uncollectible Accounts 2,534,68i 2,129,54i
163 (905) Miscellaneous Customer Accounts Expenses 237.65!229.44e
164 TOTAL Customer Accounts Expenses ffotal of lines 159 thru 163)15,187,451 14,034,05S
FERC FORM NO.1 (ED.12-93)Page 322
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn orisinat(2) -A Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20'13/Q4
ELECTRIC OPERATION AND MAINTENANCI EXPENSES (Continued)
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
-tne
No.
Account
(a)
Amount forCurrent Year
(b)
Amount forPrevious Year
(c)
165 6, CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
158 (908) Customer Assistance Expenses 20,642,475 24,468,405
169 (909) lnformational and lnstructional Expenses 'l .040.149 1.1 11.61t
170 (910) Miscellaneous Customer Service and lnformational Expenses 201 .012 176,221
171 TOTAL Customer Service and lnformation Expenses (Total 167 thru 170)21,883,636 25,756,24t
172 7. SALES EXPENSES
't73 Operation
174 (911) Suoervision
175 '912) Demonstratino and Sellino Expenses 7 40i 7.94t
176 (91 3) Advertisinq Expenses
177 (9'1 6) Miscellaneous Sales Exoenses
178 TOTAL Sales Expenses (Enter Total of lines 174 lhtu 177\7,402 7,94t
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
18t (920) Administrative and General Salaries 24,995,618 36,662,334
182 (921) Office Supplies and Expenses 4.124.034 4.136.95'
183 Less) (922) Administrative Expenses Transferred-Credil '102,053 65,80!
184 (923) Outside Services Employed 10,535,127 1't.659.87S
185 (924) Propertv lnsurance 1.449.064 1.325.54e
186 (925) lniuries and Damaqes 3,100,513 2,428.17!
187 {926) Emolovee Pensions and Benefits 1.214.925 1 364 061
188 (92il Franchise Reouirements 5.747 5,74i
189 (928) Regulatory Commission Expenses 5,838,865 5.559.471
190 929) (Less) Duolicate Charoes-Cr.
191 (930.1) General Advertisinq Expenses 117 2,394
192 (930.2) Miscellaneous General Expenses 3.108.30i 3.255,33€
193 (931) Rents 927.319 1,032.66f
194 TOTAL Operation (Enter Total of lines 181 thru 193)55,197,583 68.466.76C
195 Maintenance
196 (935) Maintenance of General Plant 8,858,776 7,8',t3,751
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)64.056.359 76.280.511
198 TOTAL Elec Op and Maint Expns ffotal 80,1 12,131,156,164,171,178,197)684,482,695 714,845,354
FERC FORM NO. 1 (ED.12-93)Page 323
Name of Respondent
Avista Corporation
This Re(1) E(2) f
lort ls:
]An Original
lA Resubmission
Date of Report
(Mo, Da, Yr)
04t1'.v2014
Year/Period of Report
End of 20131Q4
PURCHASED POWER (Account 555)(lncluding 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. ln 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). ln 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{erm 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.9., the supplier must atlempt 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.
lF - 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.
lU - 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.
No.
-rne Name of Company or Public Authority
. (Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
f\Verage
Vlonthly NCP Deman
(e)
Average
Monthly CP Deman<
(0
1 BP Corporation NA SF ISDA
2 BP Energy Company SF A/SPP
3 Black Hills Power, lnc.SF A/SPP
4 Bonneville Power Administration LF /VNP#3 Agr.
5 Bonneville Power Administration SF A/SPP
b Bonneville Power Administration SF Iariff #8
7 Bonneville Power Administration OS BPA OATT
8 Bonneville Power Administration SF BPA OATT
9 Calpine Energy Services LP SF ,1/SPP
10 Cargill Power Markets SF A/SPP
11 Cargill Power Markets SF ISDA
12 City of Spokane LU )URPA
13 City of Spokane IU PURPA
14 Chelan County PUD IU Rocky Reach
Total
FERC FORM NO. 1 (ED.12-90)Page
Name of Respondenl
Avista Corporation
tnrs Ke(1) E(2\ T
roft ts:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2013/Q4
PURCHASED POWER(Account 555) (Continue(,)(lncludinq povier exchanqe5)'
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. ln 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 seivice 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 O, 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. lf more energy was delivered than received, enter a negative amount. lf 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 ',l0. 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawan nours
Received
(h)
MegaWaU Hours
Delivered
(i)
Demand Charges
',ft
Energy Charges
($)
(k)
ulner unarges
($)
(t)
lolal u+K+l)of Settlement ($)
(m)
1 1 1
38,84r 1,553,87t 1,553,87t 2
1,40(43,65(43,65(3
374,961 15,334,59(15,334,59(4
102.29\2,792,25(2,792,251 5
22,221 694,64i 694,64i b
15,33i 15,33i 7
2,241 69,62r -1 73,85!-104,231 8
265,831 7,417,59(7,417,59t 9
53,81,1,897,67(1,897,67(10
-26,361 -26,36't 1l
52,571 2,385,69i 2,385,69;12
136,88r 6,361,452 6,361,452 13
-14,67(14
6,911,07i s54,654 557.179 16,564,81 i 183,742,212 5,456,89:205,763,91r
FERC FORM NO.1 (ED.12-90)Page 327
Name oI Kesponoenl
Avista Corporation
tnts
(1)
(2\
(e
ET
00n ts:
]An Originat
lA Resubmission
Date of Report(Mo, Da, Yr)
0411112014
Year/Period of Report
End of 20131Q4
PU ICHASED POWER (Account 555)lncluding 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. ln 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). ln 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{erm 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.
lF - 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.
lU - 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.
Line
No.
Name of Company or Public Authority
(Footnote Affi liations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVerage
Monthly NCP Deman
(e)
r\Verage
Monthly CP Demanc
(0
1 Chelan County PUD SF A/SPP
2 Chelan County PUD IU 3helan Sys
3 Clark County PUD No. 1 SF A/SPP
4 Clatskanie PUD SF A/SPP
5 Constellation Energy Commodities Group SF A/SPP
6 Deep Creek Energy, LLC IU ]URPA
7 Douglas County PUD No. 1 LU A/ells
I Douglas County PUD No. 1 LU A/ells Settlement
I Douglas County PUD No. 1 IF A/ells
10 Douglas County PUD No. 'l SF A/SPP
11 Douglas County PUD No. I EX 305
12 EDF Trading No America SF A'SPP
13 Eugene Water & Electric Board SF A/SPP
14 Exelon Generation Company, LLC SF A'SPP
Total
FERC FORM NO.1 (ED.12-90)Page 325.1
Name of Respondent
Avista Corporation
tnts x.e(1) E(2\ T
)on ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
PURCHASEq P.pWER(Account 555). (Continued)
( tncruotnq Dower excnanqes)
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. ln 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 O, 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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawall Hours
Received(h)
Megawa[ nours
Delivered(i)
uemano unarges
($)
0)
Energy Charges
($)
(k)
ulner unarges
($)
(t)
Total (j+k+l)
of Settlement ($)
(m)
6,02r 164,92 164,924 1
292.60 11,824,81i 11.824,81i 2
13,79 286.25 286,251 3
95,18,94 18,942 4
2,00(48,30(48,30(5
151 8,39 8,39i 6
131,441 1,535,59r 1,535,59(7
36,89 1 ,043,81:1,043,812 8
177,11 4,740,00(4,740,00c I
9,40(335,1 0l 335,1 0f 10
1 11 ,78C 111,780 1,567,50(83:1,568,33i 11
34.42i 783,55(783.55€12
3,10 140.1 9l 1 40,1 98 13
3,60(144,46,144,464 14
6,911,072 554,65!557.179 16,564,81:183,742,21i 5,456,89:205,763,91t
FERC FORM NO.1 (ED.12-90)Page 327.1
Name of Respondent
Avista Corporation
I nts r(e(1) E(2) T
ort ls:
An Original
A Resubmission
uale or Kepon(Mo, Da, Yr)
o4t't1t2014
Year/Periocl of Report
End of 2013/Q4
PURCHASED POWER (Account 555)(lncluding 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. ln 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). ln 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.9., 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 identifled 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.
lF - 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.
lU - 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.
-tne
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Avera9e
Vlonthly NCP Deman
(e)
/rverage
Monthly CP Demanc
(0
1 Ford Hydro Limited Partnership -U PURPA
2 Grant County PUD No. 2 -U >riest Rapids
3 Grant County PUD No. 2 SF A/SPP
4 Grant County PUD No. 2 =x
:ERC #1 04
5 Hydro Technology Systems U PURPA
b lberdrola Renewables LLC SF A/SPP
7 ldaho County Power & Light -U ]URPA
I ldaho Power Company SF A/SPP
9 ldaho Power Company - Balancing SF A/SPP
10 lnland Power & Light Company tQ 208
11 J. Aron & Company JF A/SPP
12 Jim White -U ,URPA
13 J P Morgan Ventures Energy LLC SF A/SPP
14 J P Morgan Ventures Energy LLC -U rPM Energy
Total
FERC FORM NO.1 (ED. 12-90)Page 326.2
Name of Respondent
Avista Corporation
lnrs Keoon ls:(1) finn Originat(2) l-lA Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
PUI{CHASEU PUWET{(Account 555) (Uonttnued)(lncludinq oovier exchanoeS)'
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. ln 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 O, 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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegiaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawafi Hours
Received
(h)
Megawa[ Hours
Delivered
(i)
uemano unarges
($)
0)
Energy unarges
($)
(k)
ulner unarges
($)
(t)
I OIal U+X+l)
of Settlement ($)
(m)
3,46 196,60,196,60r 1
346,96 5,932,3'l:5,932,31i 2
34,06 924,65r 924,6s(3
-24,461 -24,461 4
11,321 524,481 524,48(5
154,071 4,888,11 4,888,1 1 (6
2,25 83,24 83,24i 7
105.29(3.804.48r 3,804,48:I
2t 85(9
10r 6,70!6,70!10
2,00(62,05(62,05(11
1,241 115,19!115,191 12
35'13,791 13,791 13
73,471 3,227,881 3,227,881 14
6,911,07'554,65r 557,179 16,564,81:183,742,211 5,456,89:205,753,91
FERC FORM NO.1 (ED.12-90)Page
Name of Respondent
Avista Corporation
Thas Re(1) E(2) f
)ort ls:
lAn Original
lA Resubmission
Date of Report(Mo, Da, Yr)
o4l't1t2014
Year/Period of Report
End of 20131Q4
PURCHASED POWER (Account 555)(lncludinq power exchanqes)
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. ln 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). ln 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{erm firm service firm service
which meets the definition of RQ service. For all transaction ldentified 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.
lF - 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.
lU - 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 cannol 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.
_tne
No,
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVerage
Monthly NCP Deman
(e)
r\Verage
Monthly CP Demanc
(D
1 J P Morgan Ventures Energy LLC SF ISDA
2 Kootenai Electric Cooperative IU PURPA
3 Macquarie Energy LLC SF WSPP
4 Mizuho Securities USA, lnc SF ISDA
5 Morgan Stanley Capital Group SF WSPP
6 Morgan Stanley Capital Group SF ISDA
7 Newedge USA LLC 3F ISDA
8 NextEra Energy Power Marketing LLC SF WSPP
9 Noble America Gas & Power Corp.SF WSPP
10 NorthWestern Energy LLC SF WSPP
11 Okanogan County PUD No. 1 SF WSPP
12 PPL Energy Plus SF WSPP
13 PacifiCorp SF WSPP
14 Palouse Wind LLC -U PPA
Total
FERC FORM NO.1 (ED.12.90)Page 326.3
Name of Respondent
Avista Corporation
tnrs KeDon ts:(1) fiRn Originat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04t'.t'.U2014
Year/Period of Report
End of 20131Q4
I,UKUHAUEU POWEI{(Account 555) (Conttnued)(lncludinq oovrler exchanoeS)'
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. ln 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 (0. 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 O, 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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawa[ Hours
Delivered
(i)
uemano unarges
($)
0)
Energy unarges
($)
(k)
ulner unarges
($)
(t)
lolal u+K+l)
of Settlement ($)
(m)
I
10,74 267,301 267,30t 2
38,32 1,171,35(1,171,35(3
-296,98!-296,98(4
102,221 3,373,09(3,373,09(5
2,149,774 2,149,77t b
2,503,801 2.503.801 7
13,781 494,21 494,211 8
3,00(69,35(69,35(o
10,47 262,58 262,581 10
7,03 1 99,76i 199,761 1',!
1,348,36,38,930,96(38,930,96(12
73,49r 2,103,18i 2,1 03,1 8r 13
297,02-,16,284,921 16,284,92(14
6,911,07i 554,652 557,179 16,564,81:183,742,21'5,456,89:205,763,91r
FERC FORM NO.1 (ED.12.90)Page 327.3
Name oI Hesponc,ent
Avista Corporation
I nts Ke(1) E(2) T
roft ls;
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2O13lQ4
PURCHASED POWER (Account 555)(lncludinq power exchanqes)
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 lhe respondent has with the seller.
3. ln 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). ln 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.9., 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.
lF - 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{erm 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.
lU - for intermediate-lerm 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.
_tne
No.
Name of Company or Public Authority
(Footnote Afflliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Aclual Demand (MW)
AVerage
Monthly NCP Deman
(e)
AVerage
Monthly CP Deman<
(f)
1 Pend Oreille County PUD No. 1 SF Pend O'
2 Pend Oreille County PUD No. 't SF Pend O'
3 Phillips Ranch LU PURPA
4 Portland General Electric Company EX 304
5 Portland General Electric Company EX 178
b Portland General Electric Company SF WSPP
7 Potlatch Corporation -U PURPA
I Powerex Corp SF WSPP
I Puget Sound Energy SF /VSPP
10 Rainbow Energy Marketing Corp SF A/SPP
11 Rathdrum Power LLC LF Lancaster
12 Sacramento Municipal Utility District SF yVSPP
't3 Seattle City Light SF ,1/SPP
14 Sheep Creek Hydro LU PURPA
Total
FERC FORM NO.1 (ED.12-90)Page 326.4
Name of Respondent
Avista Corporation
tnts Keoon ts:(1) fiRn Originat(2) llA Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 20131Q4
PU i(UF|AI,EU I'UWE i((ACCOU nt 555 ) ( Uonttn Ued )(lncludinq povier exchanqeS)'
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. ln column (c), identiff 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 supplie/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 O, 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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purchased
(g)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.Megawatt Hours
Received
(h)
Megawa[ Hours
Delivered(i)
uemano unarges
($)o
Energy Charges
($)
(k)
LrIner unarges
($)
(D
Total (j+k+D
of Settlement ($)
(m)
1 14,89t 3,409,21(3.409.2',t(I
16,12 2,252 4,621 458,981 49,471 409,51t 2
6:2,89(2,89(3
430,72!43',t,40(4
9,1 6t 9,37t 117.19t 117,19t 5
5,70,142.081 142,08t b
214,081 9.188.31,9,188,31r 7
51,30,2,519,21 2,519,211 I
45,131 1,394,56:1,394,56;I
19,95:530,39:530,39''t0
1,656,29:25,529,971 25.529.97t 11
1,40(52,35(52,35(12
17 ,71 433,30r 433,30t 13
9,58i 354,59(354,59('t4
6,911,07'554,654 557,175 16,564,81:183.742.21i 5,456,89:205,763,91t
FERC FORM NO.1 (ED.12-90)Page 327.4
Name of Respondent
Avista Corporation
tnts Ke(1) E(2\ r
DOII IS:
lRn originat
lA Resubmission
Date of Report(Mo, Da, Yr)
0411'Uzo'.t4
Year/Period of Report
End of 2013/04
PURCI1{AFED POWER (Account 555)(rncruotnq Dower excnanqes)
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. ln 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). ln 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{erm 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{erm 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.
lF - 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{erm 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.
lU - for intermediate-term service from a designated generatihg 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.
Line
No.
Name of Company or Public Authority
(Footnote Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVerage
Monthly NCP Deman
(e)
,1verage
Monthly CP Demant
(0
1 Shell Energy SF ISDA
2 Shell Energy SF ,1/SPP
3 Sierra Pacific Power Company SF A/SPP
4 Snohomish County PUD No. 1 SF A/SPP
5 Sovereign Power IF Soverelgn
6 Spokane County LU )URPA
7 Stimson Lumber IU rURPA
8 Tacoma Power SF A/SPP
9 Tenaska Power Services Company SF A/SPP
10 The Energy Authority SF A/SPP
11 TransAlta Energy Marketing SF /USPP
12 lntraCompany Generation Services CS fATT
13 Other - lnadvertent lnterchange =x
14
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.5
Name oI Kesponoenl
Avista Corporation
lnrs Heoon ls:(1) []An original(2) l-lA Resubmission
uare or Kepon(Mo, Da, Y0
o4t11t2014
Year/Periocl of Report
End of 20131Q4
PU KUHAiiEq P.pWEt{(Account 555). (L;onttn ued)
{ tnctuorno Dower excnanoes}
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. ln column (c), identifo 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 O, 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. lf more energy was delivered than received, enter a negative amount. lf 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.
MegaWatt Hours
Purchased
(s)
POWER EXCHANGES COST/SETTLEMENT OF POWER Line
No.MegaWatt Hours
Received
(h)
Megawa[ Hours
Delivered
(D
uemano unarges
($)
0)
Energy unarges
($)
(k)
ulner unarges
($)
(t)
I OIal U+K+U
of Settlement ($)
(m)
820,96(820,96(1
1 45,1 3(4,314,34,4,314,341 2
201 701 70(3
26,541 679,66r 679,66{4
8,76t 208,141 208,14(5
1,191 80,88 80,88i b
34,99'1,862,061 1,862,06!7
52,24 1,811,04,1.811,041 8
29,46-,1,030,22 1.030,22i 9
30,94(841.40(841,40(10
42.251 1,332,60(1,332,60(11
654,511 654,5't 1 12
725 13
14
6,911,072 554,654 557,171 16,564,81 183,742,21'5,456,89:205,763,91t
FERC FORM NO.1 (ED.12-90)Page 327.5
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
S;iediid 32o Line No.: 1 cotumn: a -------=1
Fianncial SWAP
: 326 Line No.:7 Column: a
___.1Non Moneta
Financial- SWAP
Line No.: 11 Column: a
iSchedule Page: 326.1 Line No.: 11 Column: a INon MonetatSchedut
Non Monetary
lscneaute page: i262 Line No.:10 cotumn: aService to Deer Lake from Inland Power and Light. No demand charges associated with the
agJeement.,
lSchedule Page:326.9_|!nS ttp;1_ Column: aFinancial SWAP
fSrtgdqle Pa.gei!26.3 Line No.: 4Financial SWAP-@
Financial- SWAP
Schedule Page: 326.3 Line No.: 7 Column: a IFinancial SWAP
:326.4 Line No.:2 Column: a
Non Monetary
--Non Monet
lSchedule Page: 326.5 Line No.: 1 Column: a
Column: a I
FERC FORM NO.1 .'l 450.1
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
tnts x(1) t(2) f
x
on ls:
An Original
A Resubmission
uate ol Kepon(Mo, Da, Yr)
o4t11t2014
YearHenoo oI Kepon
End of 20131Q4
MISJII,JN (JT trLEU I I(IUI I Y TUK (J I NtrKb (I
lncludino transactions referred to as'wheelinq'\ccount 456.1)
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. ln 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 lnstruction for definitions of codes.
-rne
No.
Payment By
(Company of Publlc Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 PacifiCorp PacifiCorp PacifiCorp LFP
2 Seattle City Light Seattle City Light Grant County PUD LFP
3 Tacoma City Light Tacoma City Light Grant County PUD LFP
4 Grant County Public Utility District Grant County Public Utility Distr Grant County Public Utility Distr OS
5 Spokane lndian Tribes Bonneville Power Administration Spokane lndian Tribes LFP
6 USBR Bonneville Power Administration East Greenacres LFP
7 Consolidated lrrigation District Bonneville Power Administration Consolidated lrrigation District LFP
8 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO
I City of Spokane City of Spokane Avista Corporation OS
10 Stimpson Plummer Avista Corporation OS
11 Hydro Tech lndustries Meyers Falls Avista Corporation OS
12 First Wind Energy Marketing Palouse Wind Avista Corporation OS
13 Deep Creek Hydro Deep Creek Avista Corporation OS
14 Bonneville Power Administration Avista Corporation Bonneville Power Administration OS
15 Coral Power Avista Corporation Idaho Power Company SFP
'16 Coral Power Bonneville Power Administration ldaho Power Company SFP
17 Cargill Power Markets Bonneville Power Administration ldaho Power Company SFP
'18 Cargill Power Markets Northwestern Montana Bonneville Power Administration SFP
19 Cargill Power Markets Northwestern Montana Chelan County PUD SFP
20 Cargill Power Markets ldaho Power Company Bonneville Power Administration SFP
21 Morgan Stanley Capital Group Bonneville Power Administration ldaho Power Company SFP
22 Morgan Stanley Capital Group Bonneville Power Administration Northwestern Montana SFP
23 Morgan Stanley Capital Group Northwestern Montana Bonneville Power Administration SFP
24 Morgan Stanley Capital Group Northwestern Montana Chelan County PUD SFP
25 Morgan Stanley Capital Group Northwestern Montana ldaho Power Company SFP
26 Morgan Stanley Capital Group Northwestern Montana Grant County PUD SFP
27 Morgan Stanley Capital Group Grant County PUD Northwestern Montana SFP
28 Morgan Stanley Capital Group Chelan County PUD Northwestern Montana SFP
29 Puget Sound Energy Northwestern Montana Bonneville Power Administration SFP
30 Tenaska Northwestern Montana Bonneville Power Administration SFP
31 Pacificorp Pacificorp ldaho Power Company SFP
32 ldaho Power Company LSt Avista Corporation Bonneville Power Administration SFP
33 ldaho Power Company LSE Avista Corporation ldaho Power Company SFP
34 ldaho Power Company LSE Avista Corporation Northwestern Montana SFP
rOTAL
FERC FORM NO. 1 (ED.12-90)Page 328
Name of Respondent
Avista Corporation
I hrs ReDort ls:(1) fiRn Originat(2) llA Resubmission
Date of Report
(Mo, Da, Yr)
04t1',U2014
Year/Period of Report
End of 20131Q4
IKANSMIUSIUN 9F ELEU IKIUI I Y TUK U IHEK!' (ACCOUNT 45t'XUONIINUEO)(lncludinq transactions reffered to as'wheelinq') "
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations underwhich service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln column
(g) report the designation for the substation, or other appropriate identificatlon 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 0) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Megawatl Hours
Received(i)
Megawa[ nours
Delivered
0)
rERC No.182 Dry Creek Walla Wall )ry Gulch 2(60,57{60,57t 1
:ERC Trf No. t Chelan-Stratford 1 '15 Stratford 1'lskv SS 238,50;238,50i 2
:ERC Trf No. t Chelan-Stratford 1 15 Stratford 1 1skv SS 238,50i 238,501 3
=ERC No.104 Stratford Substation Soulee CyM/ilson Crk 2!89,97(89,97(4
rERC Trf No. t iA/estside -ittle Falls 3,48t 3,48(5
:ERC Trf No. t Bell Substation >ost Falls 4,231 4,231 6
=ERC Trf No. t Bell Substation 3KR/OPT/EFM/LIB 6,04(6,041 7
:ERC Trf No. t 1,869,69:1,869,691 8
:ERC No. 155 Sunset-Westside 'l 15k A/estside I
:ERC Trf No. t qVA Syst {VA Syst 't0
:ERC Trf No. I 't1
:ERC Trf No. t 12
:ERC Trf No. t 13
:ERC Trf No. t 14
:ERC Trf No. t 12,81t 't2,81t 15
:ERC Trf No. t 2E,831 28,83 16
:ERC Trf No. t 3,321 3,32,17
:ERC Trf No. t 52t 521 18
:ERC Trf No. t 40(4o(19
:ERC Trf No. t 1,40(1,40(20
:ERC Trf No. t 762 761 2'l
:ERC Trf No. t 331 33 22
:ERC Trf No. t 2,56:2,561 23
:ERC Trf No. t 8,402 8,40:24
:ERC Trf No. t 't7 1 17 25
:ERC Trf No. t 1 1 26
:ERC Trf No. t 25,454 25,45t 27
EERC Trf No. f 144 14,28
:ERC Trf No. €1,68C 1,68(29
:ERC Trf No. t 40(40(30
:ERC Trf No. I 3,34t 3,34{31
:ERC Trf No. I 6,562 6,56,32
:ERC Trf No. t 30,93(30,93(33
:ERC Trf No. t 27!27!34
51 2,977,701 2,977,701
FERC FORM NO.1 (ED. 12-90)Page 329
Name of Respondent
Avista Corporation
I nts Keoon ts:(1) Snn originat(2) l-lA Resubmission
Date of Report(Mo, Da, Y0
04t11t2014
Year/Period of Report
End of 20'l3lQ4
I K/\NDM|DD|(JN \rr ELtrU I }(tut I r r(rF( U I nE.KJ (ACCOUnI .+CO' (UOnIlnUeO'(lncludinq transactions reffered to as'wheelino') ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln 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). lf no monetary settlement was made, enter zero (1 1 01 1) 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 O must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
1 1. Footnote entries and provide explanations following all required data.
REVENUE FROM TMNSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
213,341 213.342 I
146,6'1 (37,'t'16 183,735 2
146,61!37,'l 1 6 1 83.735 3
26,91t 26,918 4
31,18'31j82 5
16,51i 16.517 6
38,83.i 38,837 7
6,835,77t 6.835.775 8
27,973 27,973 9
9,480 9,480 '10
6,12C 6,120 11
200,00c 200,000 12
402 402 13
14,884,00C 14.884.000 14
56,961 56,964 15
94,882 94,882 16
25,29(25,294 17
6,09:6,092 18
4,61I 4,615 't9
4,611 4,61:20
14,731 14,732 21
4,80:4,E0:22
45,56,45,564 23
134,32 134,321 24
2,92t 2,924 25
14!14t 26
466,79t 466,79!27
2,71t 2,71!28
6,461 6,46'1 29
2,30t 2,30€30
38,76(38,76€31
26,'t7t 26,17t 32
103,97'..103,972 33
92i 923 34
't 0,184,046 0 15,202,207 25,386,253
FERC FORM NO.1 (ED.12-90)Page 330
Name of Respondent
Avista Corporation (1) E(2) l-
rort ls:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2O13lQ4
II(ANS VllDDlL/l\ \./r ELEU I l1l\,1 I I rlJl1 U I nEl1O (AGGOUrlt '+OO. l,
ncludino transactions referred to as'wheelino')
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. ln 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 lnstruction for definitions of codes.
_rne
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 ldaho Power Company LSE Bonneville Power Administration ldaho Power Company SFP
2 Idaho Power Company LSE Bonneville Power Administration Northwestern Montana SFP
3 ldaho Power Company LSE Pacificorp ldaho Power Company SFP
4 ldaho Power Company LSE ldaho Power Company Bonneville Power Administration SFP
5 ldaho Power Company LSE Chelan County PUD ldaho Power Company SFP
6 Coral Power Avista Corporation Chelan County PUD NF
7 Coral Power Avista Corporation Grant County PUD NF
8 Coral Power Bonneville Power Administration ldaho Power Company NF
I Coral Power Bonneville Power Admin istration Northwestern Montana NF
10 Coral Power Northwestern Montana Avista Corporation NF
11 Coral Power Northwestern Montana Bonneville Power Administration NF
12 Coral Power Northwestern Montana Grant County PUD NF
13 Coral Power Northwestern Montana Pacificorp \F
14 Cargill Power Markets Avista Corporation Northwestern Montana \F
15 Cargill Power Markets Bonneville Power Administration ldaho Power Company \IF
16 Cargill Power Markets Northwestern Montana ldaho Power Company \F
17 Cargill Power Markets ldaho Power Company Bonneville Power Administration \IF
'18 PPL Energy Plus Bonneville Power Administration ldaho Power Company !F
19 PPL Energy Plus Northwestern Montana Bonneville Power Administration VF
20 PPL Energy Plus Northwestern Montana ldaho Power Company NF
21 Morgan Stanley Capital Group Bonneville Power Administration ldaho Power Company NF
22 Morgan Stanley Capital Group Bonneville Power Administration Northwestern Montana NF
23 Morgan Stanley Capital Group Northwestern Montana Bonneville Power Administration NF
24 Morgan Stanley Capital Group Northwestern Montana ldaho Power Company NF
25 Morgan Stanley Capital Group Northwestern Montana Grant County PUD NF
26 Norwestern Energy Northwestern Montana Bonneville Power Administration NF
27 PPM Energy lnc.Avista Corporation Bonneville Power Administration NF
28 PPM Energy lnc.Bonneville Power Administration ldaho Power Company NF
29 PPM Energy lnc.Northwestern Montana Bonneville Power Administration NF
30 Puget Sound Energy Bonneville Power Administration ldaho Power Company NF
31 Puget Sound Energy Northwestern Montana Bonneville Power Administration NF
32 Puget Sound Energy Puget Sound Energy ldaho Power Company NF
33 Powerex Bonneville Power Administration ldaho Power Company NF
34 Powerex Bonneville Power Administration Northwestern Montana NF
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.1
Name oI Hesponoent
Avista Corporation (1) E(2) r
ron ts:
An Original
A Resubmission
Date of Report(Mo, Da, Y0
04t11t2014
Year/Period of Report
End of 20'l3lQ4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456xcontinuec!)(lncludino transactions reffered to as'wheelino) "
5. ln column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations underwhich service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln 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. Repo( in column (i) and 0) the total megawatthours received and delivered.
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TMNSFER OF ENERGY Line
No.MegawaII Hours
Received(i)
Megawatt H0urs
Delivered(i)
EERC Trf No. t 229,161 229,16,1
FERC Trf No. t 40(401 2
FERC Trf No. t 1,621 1,62,3
FERC Trf No. t 4
FERC Trf No. t 3,904 3,902 5
FERC Trf No. €2t 2t b
FERC Trf No. t 10t 10r 7
FERC Trf No. t 12,545 12,54.8
FERC Trf No. t 19!19r 9
FERC Trf No. t 10
FERC Trf No. t 73!73t 't1
FERC Trf No. t ),2!12
FERC Trf No. t 14(141 13
FERC Trf No. I EI Ei 14
FERC Trf No. t 42t 42,15
FERC Trf No. t 1 I 16
FERC Trf No. €20(201 't7
FERC Trf No. t 1,17(1,171 18
FERC Trf No. t 12!121 19
FERC Trf No. t 90(90r 20
FERC Trf No. t 82(821 21
FERC Trf No. f 4(4l 22
FERC Trf No. t 4,254 4,25i 23
FERC Trf No. t 171 17,24
FERC Trf No. €1 25
FERC Trf No. t 364 36r 26
=ERC Trf No. t 284 281 27
=ERC Trf No. t 28(281 28
FERC Trf No. t 162 16i 29
=ERC Trf No. t 10(10(30
:ERC Trf No. {1,45(1,45(31
FERC Trf No. {53(53(32
=ERC Trf No. t 94!941 33
rERC Trf No. t u
O/2,977,704 2,977,7Q,
FERC FORM NO. 1 (ED. 12-90)Page 329.1
Name of Respondent
Avista Corporation (1) E(2) r
ron lsl
An Original
A Resubmission
Date of Report(Mo, Da, Y0
04t11t2014
Year/Period of Report
End of 2O13lQ4
I KANDMIJDI\.rN \Jr trLtrt/ I l1lt/l I I rl..rl1 r-r I r1El(D (AGCOUnI z+CO, tuOntlIlueq,(lncludinq transactions reffered to as'wheelinq') ' '
9. ln column (k) through (n), report the revenue amounts as shown on bills or vouchers. ln column (k), provide revenues from demand
charges related to the billing demand reported in column (h). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln 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). lf no monetary settlement was made, enter zero (1 101 1) 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 0 must be reported as Transmission Received and Transmission Delivered for annual report
purposes onlyon Page401, Lines 16 and17, respectively.
11. Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Ltne
No.
893,31r 893,314 I
1,95t 1,958 2
7,951 7,951 3
ta AC 4
15,091 15,091 5
'15I 155 6
621 624 7
53,41!53,41S I
81(816 o
231 231 10
4,28i 4,287 11
14t 't44 12
80r 808 13
3,1 6r 3,1 64 14
5,46i 5,467 15
81 87 16
2,30t 2,308 17
6,77i 6,777 18
72i 723 19
5,1 91 5,1 94 20
6,86:6,863 21
414 4'13 22
35,85C 35,850 23
1,55€1,556 24
18(180 2l
2,101 2,106 2e
1,65(1,650 21
1,61(1 ,616 2e
931 935 29
57i 577 3C
6.75(6,75(31
3,05r 3,05€32
8,63(8,63€33
5t 54 34
10,184,045 0 15,202,207 25,386,2s3
FERC FORM NO. 1 (ED. 12-90)Page 330.1
Name of Respondent
Avista Corporation
I nrs Keoon ts:(1) []An Originat(2) llA Resubmission
uale or F(epon(Mo, Da, Yr)
04t11t2014
YearPenoo oI Kepon
End of 2O13lQ4
I HAN!i MrssruN (Jr- ELEU I r{rut I Y r-OR O I HERS (Account 456.1)lncludinq transactions referred to as'wheelino')
'l . 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. ln 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 lnstruction for definitions of codes.
_tne
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Powerex Northwest Montana Bonneville Power Administration NF
2 Sierra Pacific Power Company Bonneville Power Administration ldaho Power Company NF
3 Sierra Pacific Power Company Portland General Electric ldaho Power Company NF
4 Transalta Energy Marketing Bonneville Power Administration ldaho Power Company NF
5 Tenaska Power Services Bonneville Power Administration Avista Corporation NF
6 Pacificorp Pacificorp Bonneville Power Administration NF
7 Pacificorp Pacificrop ldaho Power Company NF
I Pacificorp ldaho Power Company Bon neville Power Adm inistration NF
I Grant County PUD Avista Corporation Grant County PUD NF
10 Bonneville Power Administration Bonneville Power Administration ldaho Power Company NF
11 Portland General Eleckic Northwestern Montana Bonneville Power Administration NF
12 Portland General Electric Northwestern Montana Portland General Electric NF
13 ldaho Power Company Bonneville Power Administration ldaho Power Company NF
14 ldaho Power Company ldaho Power Company Bonneville Power Administration NF
15 ldaho Power Company LSE Bonneville Power Administration ldaho Power Company NF
16 ldaho Power Company LSE Bonneville Power Administration Northwestern Montana NF
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
TOTAL
FERC FORM NO.1 (ED.12-90)Page 328.2
Name of Respondent
Avista Corporation
tnts KeDon ts:(1) finn originat(2\ nA Resubmission
Date of Reporl(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
,lvl\ \.,r trLElJ I Ialvl I I r!!,l1 \,, lntrr1o (ACGOUnI z+COr(UOntlnUeA,(lncludinq transactions reffered to as 'wheelinq')
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. ln column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. ln 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 O the total megawatthours received and delivered
FERC Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(0
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.Iavvarr H(
Received(i)
MegavvaII nours
Delivered
0)
:ERC Trf No. t 76S 761 1
:ERC Trf No. t 1,124 1,12 2
:ERC Trf No. t 20c 201 3
]ERC Trf No. t 12!121 4
:ERC Trf No. t 7!7l 5
:ERC Trf No. t 3,74C 3,74t 6
:ERC Trf No. t 't3,'t4i 13,14 7
:ERC Trf No. t 8
:ERC Trf No. t 9
:ERC Trf No. t 26,86!26,86!10
:ERC Trf No. t 792 79t '11
:ERC Trf No. t 't7!17 12
:ERC Trf No. t 20c 201 13
]ERC Trf No. t 1,374 1,37,14
:ERC Trf No. t 27,499 27,49\15
:ERC Trf No. t 1,053 1,05 '16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
5i 2,977,704 2,977,701
FERC FORM NO. 1 (ED.12-90)Page
Name of Respondent
Avista Corporation
I nts KeDon ts:(1) []Rn orisinat(2) J-lA Resubmission
uale oI Kepon(Mo, Da, Yr)
04t11t2014
YearPenoo oI Kepon
End of 2013/Q4
I |{ANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)(lncludino transactions reffered to as'wheelino') ' '
9. ln 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). ln column (l), provide revenues from energy charges related to the
amount of energy transferred. ln 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). lf no monetary settlement was made, enter zero (1 1 01 1) 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 O 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.
REVENUE FROM TRANSMISSION OF ELECTRICIry FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
LIIIE
No.
4,43i 4,437 ,|
6,71i 6,712 2
1,221 1,222 3
721 721 4
57i 571
45,834 45,835 €
171,711 17'.t,714 7
1,151 1,154 8
1,80(1,80(9
170,90i 170,902 1C
4,951 4,951 'tl
1 ,01(1 ,01C 12
1,151 1,154 13
7,92t 7,928 14
1 83,1 7t 1 83,1 7t 't5
9,08:9,083 16
't7
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
10,184,046 0 15,202,207 25,386,253
FERC FORM NO.I (ED.12-90)Page 330.2
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t't'v2014
Year/Period of Report
20131Q4
FOOTNOTE DATA
lSchedule Page: 328 L141le No.: 2 Column: m
Use of facilities
SchedUse of faci-IiLies
aci-l-ities
Schedule Page: 328 Line No.:9 Column: m IUse of facilities
Deferral fee t.erm firm service reement
P-r-AAZrss;PZs-Line No.: 14 Column: m I
Use of faciLities
Para}Lel Capacity SupporU Agreement
FERC FORM NO. ,I (ED. 12.87 Page 450.1
Name oI Kespondent
Avista Corporation
This Reoort ls:(1) fiRn Originat(2) nA Resubmission
uale or Kepon(Mo, Da, Y0
o4t1'v2014
Year/Period of Report
En6 q; 2013/Q4
RANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(lncluding 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. ln 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. ln 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 lnstructions 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. ln 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. lf no
monetary settlement was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monelary 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.
-tne
No.Name of Company or Public
Authority (Footnote Affiliations)
(a)
Statistical
Classification
(b)
TMNSFER OF ENERG)EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
Magawalr-hoursReceived
(c)
rvrqgawar[-hoursDelivered
(d)
UEIIIAI I(.ICharoes($I
(e)
EI IEI UYCharoEs($r
(f)
UINETCharoes($r
(s)
rranlgiission
1 Bonneville Power Admin LFP 1,s01,980 I ,501,980
2 Bonneville Power Admin LFP 11,462,622 1,865,364 '13,327,986
3 Bonneville Power Admin LFP 788,748 788,748
4 Bonneville Power Admin os 24,360 24,360
5 Bonneville Power Admin FNS 't,046,774 148,550 1,195,324
6 Bonneville PowerAdmin NF 21,225 21,225 91,904 91,904
7 Benton County PUD No. 1 NF s06 506 bb/667
I Clark County PUD No. 1 NF 1,328 1,328 '1,99i 1,992
I Grays Harbor County PUD NF 72 72 108 108
10 Kootenai Electric Coop LFP 45,222 45,222
11 Northem Lighb LFP 133,517 133,517
12 NorthWestem Energy SFP 58,496 5,450 63,946
13 NorthWestem Energy NF 11,457 11,457 49,60!49,609
14 Portland General Elec LFP 628,000 14,989 642,989
15 Portland General Elec NF 13,659 13,659 19,06'19,062
16 Puget Sound Energy NF 5,011 5,01'l 6,088 6,088
TOTAL 78,711 78,716 15,665,35!202,829 2,058,7li 17,926,901
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Report ls:(1) [An Original(2) T-1A Resubmission
uale or Kepon(Mo, Da, Yr)
0411112014
YeaflF,efloo or Kepon
g66 61 20'13/Q4
TRANSMISSION OF ELECTRICITY BY OTHERS (.i
(lncluding transactions referred to as "wheelinl
\ccount 565)
t")
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. ln 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 afflliation 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. ln 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 lnstructions 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. ln 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. lf 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.
-tne
No.Name of Company or Public
Authority (Footnote Affl llations)(a)
Statistical
Classification
(b)
TRANSFER OF ENERG)EXPENSES OR TMNSMISSION OF ELECTRICITY BY OTHER
lvlagawalt-
hOUTSReceived
(c)
vragawarl-hours
Delivered
(d)
uemanqCharoes($r
(e)
trnetqvCharoEs($r
(f)
\,tI IgICharoes($r
(o)
Total Cost of
Tranffission
1 Seattle City Light NF 23,53'23,532 30,958 30,958
2 Tacoma Power NF 't,92t 1,926 2,441 2,441
3
4
E
6
7
8
o
10
11
12
't3
14
15
16
TOTAL 78,7lt 78,71(15,665,35!202,829 2,058,713 17,926,901
FERC FORM NO. 1/3-Q (REV. 02-04)Page
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
t$gheslgls Page: 332 Line No.:2 Column: g
Ancillary Services
I
Use of Facilities
AnciLl-ary Services
Ancillary Services
AncilIary Services
FERC FORM NO. 1 (ED.1 450.1
Name oT Kesponoenl
Avista Corporation
tntst(1)
(2)
(.
on ls:
An Original
A Resubmission
uare or Keoon(Mo, Da, Yi)
04111t2014
YearFefloo or Kepoft
End of 2O13lQ4
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line
No.
Description(a)
Amounl
(bl
lndustry Association Dues 550,79S
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist lnfo to Stkhldrs...expn servicing outstanding Securities 317,333
5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000
6 Community Relations 32.92e
7 Director Fees and Expenses 921,955
8 Educational and lnformational Expenses 9,034
I Rating Agency Fees 184,482
'10 Aircraft Operations and Fees 189,441
11 Other Miscellaneous General Expenses 902,337
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 TOTAL 3,108,307
FERC FORM NO.1 (ED.12-94)Page 335
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
\IENDORVarious vendors < $5,0003BL Media LLC
Adventures in Advertising
Bank of New York MellonCitibank NA
Coates Kokes
Coeur d'Alene Resort.Corporate Credit CardDavis Hibbitts & Midghall Inc
Desautel Hege Communications
Hanna & Associates
HP Enterprise Solutions
,fason R ThackstonKlundt Hosmer DesignMichael G AndreaOIsten
Pure Works IncRicoh USA Inc
The Davenport HotelUnion Bank of California
West Publishing Pract,ical Company
detail-:
PT]RPOSE
Miscellaneous
Professional services
Miscellaneous
Miscellaneous
MiscellaneousProfessiona] services
Miscellaneous
Miscellaneous
Professi-onal servicesProfessional servicesProfessionaL services
Workforce contract
Employee misc expensesProfessional services
Employee misc expensesWorkforce contractProfessional services
Miscellaneous
Miscellaneous
Miscellaneous
Subscript,ions
AMOUNT
$509 ,262
10, 852
7,sLL
15 ,04750,798
6, 511
16 ,022
35 ,6402l ,342
L5, 951_
40, 080
8, 558
5,768
36,725
7 ,6L6
15, 570
33 ,267
1-0 ,207
2l-,059
26 ,7 68
6 ,684
FERC FORM NO. 1 (ED.12.87 450.1
Name of Respondent
Avista Corporation
This Report ls:(1) [An Original(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 2013/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
(Except amortization of aquisition adjustments)
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. ldentifo at the bottom of Section C the type of plant
included in any sub-account used.
ln column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. lndicate at the bottom of section C the manner in which column balances are obtained. lf 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). lf 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. lf
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. lf 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 relaled.
A. Summary of Depreciation and Amortization Charges
Line
No.Functional Classification
(a)
De1creciation
Expense(Account 403)(b)
ueprecralron
Expense for Asset
Retirement Costs(Account 403.1 )(c)
Amontzalton ot
Limited Term
Electric Plant(Account 404)(d)
Amortization ofOther Electric
Plant (Acc 405)
(e)
Total
(fl
1 lntangible Plant 1,680,847 1,680,847
Steam Production Plant 7,661,394 7,651,394
Nuclear Production Plant
{ydraulic Production Plant-Conventional 8,053,492 8,053,492
Hydraulic Production Plant-Pumped Storage
)ther Production Plant 9,21't,859 2,450,031 11,661,890
Transmission Plant 10.014.786 10.014,786
)istribution Plant 35,524,899 35,524,899
legional Transmission and Market Operation
1 3eneral Plant 3,559,209 3,559,20S
11
12
Common Plant-Electric
TOTAL
10,605,806
84,631,445
6,648,082
8,328,929 2,450,031
17,253,88€
95,410,40t
B. Basis for Amortization Charges
FERC FORM NO. 1 (REV.12-03)Page 336
Name oI Kesponoent
Avista Corporation
lnrs Heoon ls:(1) 5]Rn orisinat(2) T-1A Resubmission
Date of Reoort(Mo, Da, Yi)
04t11t2014
YeailPenoo oI Kepon
End of 20131Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
_tne
No.Account No.
1a'l
uEPr EUrC9rE
Plant Base(ln Thousands)(b)
EDtI I rO]EU
Avg. Service
Llfe
IIEI
Salvage(Percent)/.lt
nPPrtru
Depr. rates(Percent)
(e)
Curve,ffi"
nvEr cgE
Remainino
Life
12 STEAM PLANT
13 )olstrip No. 3
14 11 51,121 70.0c -10.0(1.56 s1.5 22.1
15 )12 78,52i 60.0c -10.0(1.93 R1 21.5C
16 113
17 114 23,95(40.0c -5.0(2.79 R0.5 19.4C
18 t15 9,55(50.0c 1.73 R3 21.0C
19 116 9,231 53.0t 1.46 R2 20.9(
20 Subtotal 't72,381
21
22 )olstrip No. 4
23 11 51 ,25',70.0c -10.0(1.68 s1.5 23.9C
24 t12 52,64t 60.0c -10.0(2.20 R1 23.3C
25 113
26 114 15,67(40.0(-5.0(2.88 R0.5 20.9C
27 l'15 6,69(50.0(1.88 R3 22.9C
28 l'16 4,51i 53.0(1.62 R2 22.70
29 iubtotal 130,80(
30
31 (ettle Falls 0
32 l'10 141 1.45 SQ 18.0(
33 11 25,05 70.0(-10.0(1.51 s1.5 17.1(
34 )12 42,421 60.0(-10.0c 1.93 R1 16.7(
35 )14 13,34t 40.0(-5.0(2.1 R0.5 14.9(
36 115 10,31t 50.0(1.56 R3 16.4(
37 116 2,6'.tt 53.0(1.71 R2 16.8(
38 iubtotal 93,90(
39
40 IYDRO PLANT
41 )abinet Gorge
42 130 7,84i 100.0(2.0c R4 43.2(
43 ]31 12,'.!61 110.0(-20.0(1.5C R2 51.5(
44 332 31,93r 100.0('t.1 R1 47.7(
45 333 37,88(65.0(-10.0(2.04 R1.5 43.9(
46 334 5,60r 38.0(-5.0(2.97 R2.5 19.7(
47 335 4,50:65.0(0.38 Rl .5 49.9(
48 336 1,09S 55.0(1.96 s2 19.0(
49 Subtotal 101,02t
50
FERC FORM NO.1 (REV.12-03)Page
Name of Respondent
Avista Corporation
This Report ls:(1) []An Original(2) TIA Resubmission
Date of Report(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
End of 20131Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PI-ANT (Continued)
C. Factors Used in Estimating Depreciation Charges
-tne
No.Account No.
/a\
ugPr EUraurg
Plant Base
(ln Thousands)
rh)
E!'UrrratEu
Avg. Service
Life(c)
tYet
Salvaoe
(Perce'nt)(d)
nPPIEU
Depr. rates(Percent)(e)
CurverH"
nvtrr 49tr
Remaining
Life
/a\
1 Noxon Rapids
13 330 30,40(100.0(1.8C R4 48.8C
14 331 15,22t 110.0(-20.0(1.48 R2 58.4C
1 332 33,811 100.0(1.12 R1 52.6C
1 333 88,32:65.0(-10.0(1.98 R1.5 47.5C
1 334 14,311 38.0(-5.0(2.79 R2.5 29.5C
1 335 3,37t 65.0(0.80 R1.5 53.6C
1 336 241 55.0(1.89 S2 32.0C
2C Subtotal 185,70t
21
22 Post Falls
2?330 2,90t 75.0(2.81 R3 25.2C
24 331 1,48i 110.0(-20.0(2.09 R2 45.6C
2!332 11,85:100.0(1.71 R1 44,7C
2E 333 2,231 65.0(-10.0(2.42 R1.5 29.6C
21 334 711 38.0(-5.0(2.78 R2.5 18.2C
2E 335 221 65.0(1.15 Rl .5 42.1C
2l Subtotal 19,421
3(
31 Long Lake
32 330 41t 75.0(4.42 R3 11.0C
3:331 2,71!110.0(-20.0c 1.99 R2 38.9C
34 332 17,47t 100.0(1.65 R1 40.0c
?E 333 8,82t 65.0(-10.0(2.46 R1.5 33.3C
36 334 2,82i 38.0(-5.0(2.63 R2.5 22.5C
37 335 541 65.0(1.22 R1.5 39.4C
3t Subtotal 32,79t
3S
4t Little Falls
41 330 4,21i 100.0(3.35 R4 24.4C
42 331 1,08i 1 10.0(-20.0(1.94 R2 42.3C
4i 332 5,05(100.0('l.72 R1 43.6C
44 333 3,93S 65.0(-10.0(2.44 R1.5 33.6C
4!334 5,'13/38.0(-5.0(2.74 R2.5 22.2C
4e 335 131 6s.0(0.69 R1.5 40.6(
41 Subtotal 19,56t
4t
4S Upper Falls
5C 330 6t 100.0(3.6(R4 22.2(
FERC FORM NO.1 (REV. 12-03)Page 337.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn Orisinal(2) 1-1A Resubmission
uale oI Kepon(Mo, Da, Y0
04t11t2014
Year/Period of Report
End of 20131Q4
DEPRECIATION AND AMORTIZA lON OF ELECTRIC PI-ANT (Continued)
C. Factors Used in Estimating Depreciation Charges
-rne
No.Account No.
/a)
uEPr truraurtr
Plant Base
(ln Thousands)
/b'l
E!uil tatEu
Avo. Service- Life
trtrt
Salvage(Percent)
/ft\
^PPrtruDepr. rates
(Percent)Curvetlf"
nvgr agE
Remaining
Life
1o\
12 331 962 1 10.0(-20.0(1.77 R2 41,4(
13 332 7,671 100.0(1.85 R1 45.2C
14 333 1,18(65.0(-'10.0(2.5i R1.5 30.0(
15 334 4,26t 38.0(-5.0(2.81 R2.5 35."1(
16 335 10i 65.0('1.0t R1.5 41 .2C
17 336 32C 55.0(1.91 S2 26.2(
18 Subtotal 14,581
19
20 Nine Mile
21 330 1'l 100.0(2.4t R4 35.9(
22 331 4,302 110.0(-20.0(1.9t R2 46.5(
23 332 13,65:100.0(1.8:R1 45.1(
24 333 O EE(65.0(-10.0(2.1 R1.5 40.3(
25 334 2,74t 38.0(-5.0(2.8(R2.5 22.5(
26 335 301 65.0(0.8t R1.5 41.2t
27 336 62!55.0('1.9:S2 36.2(
28 Subtotal 31 ,1 9(
29
30 Monroe Street
31 331 8,441 I 10.0(-20.0(1.71 R2 56.9(
32 332 9,97t 100.0('1.3!R1 53.2C
33 333 1 1,031 65.0(-10.0('1 .9t Rl .5 45.5t
34 334 1,68t 38.0(-5.0(2.82 R2.5 23.4C
35 335 3t 65.0(1.1 R1.5 48.3C
36 336 5(55.0(1.8€S2 36.6C
37 Subtotal 31,221
38
20 OTHER PRODUCTION
4C Northeast Turbine
41 341 741 55.0(1.64 S4 8.0c
42 342 31 55.0(-10.0(2.93 R3 8.0(
4i 343 9,05t 55.0(0.81 s2.5 8.0c
44 344 2,60t 45.0(2.5C R1 7.4t
4:345 1.231 20.0(-5.0(12.49 S2 7.9(
4e 346 401 35.0(2.s1 R3 7.8(
4i Subtotal 14,08t
4t
4S Rathdrum Turbine
5C 341 3,441 55.0(3.12 S4 24.0(
FERC FORM NO.1 (REV. 12-03)Page 337.2
Name oI Kespondent
Avista Corporation
This Reoort ls:(1) 5]Rn orisinal(2) T-1A Resubmission
Date of Report(Mo, Da, Y0
04t1'.vzll4
Year/Period of Report
End of 20'l3lQ4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
-rne
No.Account No.
(a'l
uePr eGraIJre
Plant Base
(ln Thousands)(hl
Avg. Service
Life/cl
I IEI
Salvage
(Percent)
/d\
nPPrr9u
Depr. rates
(Percent)
MOnalry
Curvetffi"
AVEr age
Remainino
Life
1o)
1 342 1,69(55.0(-10.0c 3.57 R3 23.5C
1 343 5,721 55.0(2.77 s2.5 23.5C
14 344 48,85i 45.0(3.77 R1 21.6C
1 345 2,921 20,0(-5.0c 5.89 s2 't5.2C
16 346 11 35.0(2.51 R3 7.8C
17 Subtotal 62,75!
'18
19 Kettle Falls CT
20 342 8(55.0(-10.0(3.66 R3 17.7C
21 343 9,071 55.0(3.24 s2.5 17.8C
22 344 45.0(4.09 R,!16.6C
23 345 1 20.0(-5.0(6.68 S2 11.4C
24 Subtotal 9,17t
25
26 Boulder Park
27 341 1,20!55.0(2.54 S4 31.9C
28 342 11 55.0(-10.0c 2.62 R3 30.4C
29 343 5i 55.0(2.52 s2.5 30.9C
30 344 30,611 45.0(2.94 R1 26.9C
31 345 64!20.0(-5.0(6.03 S2 14.3C
32 146 1 35.0(2.87 R3 26.2C
33 Subtotal 32,65C
34
35 )oyote Springs 2
36 \41 11,37e 55.0(2.34 S4 32.8C
37 342 1 9,1 5C 55.0(-10.0(2.72 R3 31.4C
38 344 125,422 45.0(3.0c R't 27.9C
39 345 15,48S 20.0(-5.0(6.14 S2 13.4C
40 346 954 35.0(2.95 R3 27.4C
4'.!Subtotal 172,391
42
43 Solar Power 18:25.0(5.30 s2.5 17.9C
44 Subtotal 18:
45
46 Lancaster
41 342 91 55.0(-10.0(3.67 R3 29.4C
48 344 20(45.0(3.70 R1 26.6C
4!Subtotal 301
5(
FERC FORM NO.1 (REV. 12-03)Page $7.3
Name ot F<esponoent
Avista Corporation
This Report ls: I Date of Report(1) [An original | (Mo, Da, Y0(2) [lA Resubmission | 0411112014
Year/Period of Report
End of 2013/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PIANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Lrne
No.Account No.
t/e\
uePrecratJre
Plant Base
(ln Thousands)/h\
E5Ur r ratgu
Avg. Service
Life
1c)
tltt
Salvage
(Percent)
/r, )
n PPrEU
Depr. rates(Percent)
1c\
Curvetffi"
nvsr c9E
Remaining
Life
12 TRANSMISSION PLANT
13 350 16,97{75.0('t.30 R4 56.8(
14 352 19,291 60.0(-5.0(1.6s S2 48.0(
1 353 220,82t 45.0(-10.0(2.33 R2.5 33.1 (
16 354 17,121 70.0(-15.0(1.80 R4 41.0(
17 355 163,84{65.0(-15.0(1.38 R2.5 54.7t
18 356 120,20t 65.0(-10.0(1EO R2.5 50.2(
'19 357 2,831 60.0(1.64 R4 5',1.7(
20 358 2,33 50.0(2.02 S2 35.4(
2',!359 '1,95(65.0(1.66 R4 39.7(
22 Subtotal 565,38(
23
24 DISTRIBUTION PLANT
25 360 2,41t 75.0(1.34 R4 74.4(
26 361 18,20:60.0(-10.0(1,62 R2.5 47,3(
27 362 1',t5,92i 45.0(1.97 R1.5 34.2(
28 364 280,55(55.0(-2s.0(2.31 R2.5 41.1
29 365 187,95(50.0(-20.0(2.82 R3 32.7(
30 366 88,44t 50.0(-25_O(2.71 S2 37.6(
31 367 1 50,61;28.0(-20.0(5.6:S2 16.8(
32 368 207,66(44.0(-5.0(2.11 R2 33.0(
33 369 137,571 55.0(-40.0(2.7C R4 37.51
34 370.2 - tD 21,44i 15.0(7.6!s2.5 12.5(
35 370.3 - WA 26,511 35.0(3.3S s0.5 23.6(
36 373 16,96i 35.0(-25.0('t.91 R2.5 26.4t
37 373.4 22,16!35.0(-25.0(3.4€R2.5 26.8(
38 Subtotal 1,276,431
2c)
40 GENERAL PLANT
41 390.1 6,78(48.0(-5.0(1.67 S2 39.0(
42 391 .'r 8,081 5.0(21 .2t SO 3.3(
43 393 39r 25.0(4.58 SO 19.4(
44 394 3,01{20.0(4.78 SQ 10.2C
42 395 71!15.0('t 3.73 SQ 4.0(
4t 397 52,85!15.0(2.81 so 11.7C
47 398 5i 10.0(13.31 SQ 7.OC
4t Subtotal 71,90i
4S
5C MISC POWER
FERC FORM NO.1 (REV.12-03)Page 337.4
Name or Kesponoent
Avista Corporation
This Reoort ls:(1) 5]An Orisinat(2) nA Resubmission
uate oI F(eDon(Mo, Da, Yi)
0411'.U2014
Year/Period of Report
End of 20131Q4
DEPRECIATION AND AMORTIZA ION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
-rne
No.Account No.
/al
uEPr euraurg
Plant Base(ln Thousands)/h\
Avo. Service- Life
{e)
Ir9t
Salvage(Percent)/dt
^PPrsuDepr. rates
(Percent)/.1
Curvetlf"Remaining
fo)
2 392 3,81{15.0(20.0(1.83 L2.5 13.7C
3 396 3,262 15.0C 5.0(5.79 s0.5 11.8(
't4 Subtotal 7.07i
5
6
7
18
I
2C
21
22
23
24
25 rOTAL COMPANY 3,044,94!
26
27
28
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
This Page Intentionally Left Blank
Name oI Hespondent
Avista Corporation
This Re(1) E(2) T
oort ls:
]nn originat-lA Resubmission
Date of Report I Year/Period of Report
(Mo, Da, Yr) I eno ot 2}13te4
04111t2014
REGULATORY COMMISSION EXPENSES
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 yea/s amortization of amounts
deferred in previous years.
_tne
No.
Description
(Furnish name of reoulatorv commission or bodv the
dbcket or case numb-er and'a description of the iase)
(a)
Assessed by
Regulatory
Commission
(b)
EXpenses
of
Utility
(c)
TotalExoense forCuirent Year(b) + (c)
(d)
uererreqin Account
182.3 alBeginning of Year
(e)
1 Federal Energy Regulatory Commission
2 Charges include annual fee and license fees
3 for the Spokane River Project, the Cabinet
4 Gorge Project and the Noxon Rapids Project.2,451,57t 148,44C 2,600,011
5
6
7
8
9 Washington Utilities and Transportation
'10 Commission: includes annual fee and various
1'.l other electric dockets 957,40r 343,82!1.301 .231
12
13 lncludes annual fee and various other natural
14 gas dockets 293,54i 139,541 433,091
15
16 ldaho Public Utilities Commission
17 lncludes annual fee and various other electric
18 dockets 573,86(227,80t 801,66(
19
20 lncludes annual fee and various other natural
21 gas dockets 144,',13t 95,02i 239,'15(
22
23 Public Utility Commission of Oregon
24 lncludes annual fees and various other natural
25 gas dockets 492,551 658,22e 1,150,781
26
27 Not directly assigned electric 1,135,94i 1.135,94i
28 Not directly assigned natural gas 433,98S 433,98(
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
4e TOTAL 4,913,08'3,182,80:8,095,884
FERC FORM NO.1 (ED, 12-96)Page 350
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn Origlnat(2) nA Resubmission
Date of Report
(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 2O13lQ4
REGUISTORY COMMISSION EXPENSES (Continued)
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 (0, (S), 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.
EXPENSES INCURRED DURING YEAR AMORTIZEO DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
(i)
uonlra
Accounl
/i)
Amount
1k)
uelerreo lnAccount 182.3
End of Year/t)
Line
No.uepanment
(f)^sfrrJurlr(s)
/\mounI
(h)
1
2
3
ilectric 928 2,600,01t 4
5
6
7
8
9
10
Electric 928 1,301,23r 11
12
13
3as 928 433,091 't4
15
16
17
!lectric 928 80't,66(18
19
20
3as 928 239,1 5t 21
22
23
24
3as 928 1 ,1 50,784 25
26
Ilectric 928 1,134,94i 27
3as 928 433,98S 28
29
30
3'r
32
33
34
35
36
37
38
39
40
41
42
43
44
45
8,094,88t 46
FERC FORM NO.1 (ED.12-96)Page 351
Name oT Kespon0enl
Avista Corporation
This Reoort ls:(1) 5]An orisinat
(2') nA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
KESEAKUFI, IJEVELgPMEN I, ANU UEMUNS II(A II(-)N AU IIVI IIE\i
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.(ldentify
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. lndicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed lnternally: 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. lnternal combustion or gas turbine (7) Total Cost lncurred
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 lnstitute
(2) Transmission
Line
No.
Classification
(a)
Description
(b)
1 A 3 Electric - Distribution Smart Grid Demonstration Grant (Meters)
2
3
4
5
6
7
8
I
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
FERC FORM NO.1 (ED.12-87)Page 352
Name of Respondenl
Avista Corporation
lnrs
(1)
(2)
Keoon ls:
5.1Rn Originat
1A Resubmission
uate oI Kepon(Mo, Da, Yr)
04t1'U2014
Year/Period of Report
End of 20131Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continuec
(2) Research Support to Edison Electric lnstitute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost lncurred
3. lnclude 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 (0 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 1 88, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. lf 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.
Costs lncurred lnternally
Current Year(c)
Costs lncurred Externally AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(s)
Line
No.Current Year
Id)
Account
(e)
Amount(fl
712,431 652,076 107 1,364,50i 1
-688 108 -68{2
28,927 580 28,92i 3
5,906 3,526 587 9,431 4
2,0'11 77,850 588 79,86'5
98,939 920 98,93(6
63,235 45,272 921 108,50;7
3,850 97,434 923 101 ,281 8
830 't32,894 935 133,721 I
10
1'l
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
3'l
32
33
34
35
36
PageFERC FORM NO.1 (ED.12-87)
Name of Respondent
Avista Corporation
tnrs Keoon ts:(1) p(|An orisinal(2) 5A Resubmission
uate or Kepon(Mo, Da, Yr)
04t1112014
Year/Period of Report
End of 2O13lQ4
DISTRIBUTION OF SALARIES AND WAGES
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. ln determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Llne
No.
Classification
(a)
Direct PavrollDistributlon
th)
Allocation ofPavroll charoed for
C16arino AcEountsIc)
Total
Id)
3 Production 9,813,36t
4 Transmission 2,873,83t
5 Reqional Market
6 Distribution 6,807,67t
7 Customer Accounts 6,785,67i
8 Customer Service and lnformational 673.33:
I Sales 4,691
10 Administrative and General 't9,780,951
11 TOTAL Operation (Enter Total of lines 3 thru 10)46.739,52i
13 Production 3.199.0s(
14 Transmission 1,032,29i
15 Regional Markel
16 Distribution 4,1',to,26t
't7 Administrative and General
18 TOTAL Maintenance (Total of lines 1 3 thru 17)8,341,60i
20 Production (Enter Total of lines 3 and 13)13,012,4',t!
21 Transmission (Enter Total of lines 4 and '14)3,906,127
22 Regional Market (Enter Total of Llnes 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)10,917,93t
24 Customer Accounts (Transcribe from line 7)6,785,67i
25 Customer Service and Informational (Transcribe from line 8)673,33:
26 Sales (Transcribe from line 9)4,691
27 Administrative and General (Enter Total of lines 10 and 17)19.780,951
28 TOTAL Oper. and Maint. (Total of lines 20 lhru 27)55,081,129 12,214,215 67.295.344
3'l Prod uction-Man ufactured Gas
32 Production-Nat. Gas (lncluding Expl. and Dev.)
33 Other Gas Supply 760,85S
34 StoIage, LNG Terminaling and Processing 10,98!
35 Transmission
36 Distribution 3,829,25€
37 Customer Accounts 2,641,26i
38 Customer Service and lnformational 304,69i
39 Sales 1,23C
40 Administrative and General 7,385,88i
41 TOTAL Operation (Enter Total of lines 31 thru 40)14,934,17!
43 Prod uction-Manufactured Gas
44 Production-Natural Gas (lncluding Exploration and Development)
45 Other Gas Suoolv
46 Storage, LNG Terminaling and Processing
47 Transmission 1,046,252
FERC FORM NO.1 (ED.12-88)Page 354
Name of Respondent
Avista Corporation
lnrs KeDon ls:(1) 5.1Rn orisinal(2) pA Resubmission
uale or Kepon(Mo, Da, Yr)
04t1112014
Year/Period of Report
En6 e1 2013/Q4
DISTRIBUTION OF SAI.ARIES AND WAGES (Continued)
Line
No.
Classification
(a)
Direct PavrollDistribution
/hI
A[OCaUOn r
Pavroll charoe
Cl6arino Ac6ofc)
d forunts
Total
/.lt
48 Distribution 2,819,587
49 Administrative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)3,865,83!
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (lncluding Expl. and Dev.) (total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)760,85!
55 Storage, LNG Terminaling and Prooessing (Total of lines 31 thru 10,98!
56 Transmission (Lines 35 and 47\1,046,252
57 Distribution (Lines 36 and 48)6,648,84:
58 Customer Accounts (Line 37)2,641,26i
59 Customer Service and lnformational (Line 38)304,69i
60 Sales (Line 39)1,23(
61 Administrative and General (Lines 40 and 49)7,385,88i
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)18,800,014 4,'t93,954 22,993.968
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64)73,881,14:16,408,16!90,289,312
68 Electric Plant 23,565,517 4,494,568 28,060,085
69 Gas Plant 6,314,47i 1 ,718,033 8,032,50€
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70)29,879,99(6,212,60'.|,36,092,591
73 Electric Plant 1 ,958,817 5,786,393 7.745.21C
74 Gas Plant 81,43:I ,623,5't9 1,704,952
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75)2,040.25C .7,409,9't2 9,450,162
77 Other Accounts (Specify, provide details in footnote):
78 Stores Expense (163)1,959,483 -1,959,483
79 Preliminary Survey and lnvestigation ('183)-16,331 -15,33'l
80 Small Tool Expense 3,367,904 -3,367,904
81 Miscellaneous Deferred Debits (1 86)2,685,152 2,685,152
82 Non-ooeratino Exoenses (4'l 7)597,1 9!597,199
83 Activities (426)973,1 8i 973,187
84 Emolovee lncentive Plan (232380)8,098,154 -8,098,154
85 DSM Tariff Rider and Payroll Equialization Liability (242600,18,486,73C -16.676.525 1,810,205
86 lncentive / Stock Comoensation (238000)123,259 123,259
87
88
89
90
91
92
93
94
95 TOTAL Other Accounts 36.274,737 -30,102,066 6,172,671
96 TOTAL SALARIES AND WAGES 142,076,120 -71,384 142,004,736
FERC FORM NO. I (ED.12-88)Page 355
Name of Respondent
Avista Corporation
This Report ls:
(1) tr An Original
(2) D A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2013tQ4
COMMON UTILIW PLANTAND EXPENSES
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 lnstruction 13, Common Utili$ 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.
Acct. No.
901
902
903
60 ,228,80t
5,145,059
99 , 193 ,2]-1
46 ,829 ,149
10,755,983
2 ,480 , t42
9 ,273 ,499
453 ,018
2,074 ,594
33 ,6t9,657
46r.,883
0
270 ,526 ,052
54 ,296 , ]-58
324 , 822 ,220
7L,713 , 657
253, 108, 553
6.2,Common Plant in service and accumulated provision for depreciation
Acct . No. Description
303 InEangible
389 Land and Land Rights
390 Structures and Improvements
391 Office Furniture and Equipment.
392 Transportation Equipment
393 Stores Equipment
394 Tools, Shop c carage Equipment
395 Laboratsory Equipment.
396 Power Operat,ed EquipmenE
397 Communicatj.ons Equipmerrt
398 Miscel-l-aneous Equipment
399 Asset. Retirement. Cost
Tot,a1 Common Plant
Const. work in Progress
Totsa1 Utility Plant
Acc. Prov. for Dep. & Amort.
Net Utility Plant
2 Common Expenses allocaEed Eo Electric and Gas departments:
collection expenses
903.90-99A/R misc fees
Uncollectible accounts 4
Misc cust acct expenses
Cust svce & Info exp
supervision
cus! assist,ance expenses 1
Info & instruct expenses 1
Misc cust serv & info
904
905
907
908
909
9r_0
Description
Cust acct/col1ect
supervision
Meter reading expenses 5,068,453
Cust. rec and L5 ,794 ,773
Allocation to Allocated tso
Electric Dept, cas Dept
3s3, 954 3r.5,307
3 ,1_20 ,748 t,94? ,105
8,502,880 7,191,893
Basis of
Allocation
fof cust @ yr end
#of cust @ yr end
#of cusE @ yr end
net direct plant
#of cust @ yr end
#of cust @ yr end
#of cusc @ yr end
#of cust @ yr end
#of cust @ yr end
#of cust @ yr end
Total
669,271
0
792,408
449,363
0
039 ,624
690 ,037
380. 07L
U
s34,691
237 ,6s9
0
640 ,062
029 ,75L
201. 0L2
0
2 ,257 , 72L
2tL ,1 04
n
399 ,562
660 ,286
179. 059
FERC FORM NO. 1 (ED.12-87)Page 356
Name of Respondent
Avista Corporation
This Report ls:
(1) tr An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Y)
o4t11t2014
Year/Period of Report
End of 2013/Q4
COMMON UTILITY PLANT AND EXPENSES
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 lnstruction 1 3, 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.
expenses
Sales expense -supervisi-on 0911
9L2
913
9L6
920
92!
922
923
924
925
926
927
92A
Demo & selling expenses t2 ,022
Advertising expenses 0
Misc Eales expenses 0
Admin & gen salaries 32,171,135
Office supplies expenses 5,381, 525
Admin expenses tranf-credit 0
Out,side services
employed
Property lnsurance 1,66L,704
Injurj.es and damages 5,236,a80
Employee pensions 68,o53,926
& benefits
Franchise requirement 0
Regulatory commission f,775,399
expenses
929 DuplicaEe charges-credits 0
930.1 General advertising expenses 148
930 .2 Misc general expenses 3,345,310
93L Rents 1,057,504
935 Maint of general plant 10,389,580
403 Depreciation 14. 550, 888
404 Amort of LTD term plant 9,1-87,038
t4 , L3'.7 ,495
0
7 ,402
0
0
23 ,363 , 582
3,897 ,750
0
10,233,513
L,202,t76
4,664,270
49,279,u9
0
1,298,7]-6
0
Lll
2 ,446 ,759
785,666
7 ,650 , O5t
10, 605, 805
6 ,648,082
0
4 ,620
0
0
8,807 ,454
1,483,876
0
3, 903, 982
459 ,528
1, s72 ,610
!8,174,807
0
476,682
0
31
900, 1s1
281,838
2 ,139 ,529
3 ,954 ,082
2 ,538 , 956
#of cust @ yr end
#of cust @ yr end
#of cust @ yr end
#of cust @ yr end
four facEor
four facEor
four faclor
four factor
four factor
four factor
four factor
four factor
four factsor
four factor
four factor
four factor
four factor
four factor
four factor
four factor
Not,e 1: The four factor allocatsor is made up of 25 percent each of cusEomer counts, direct Iabor, direct
O&M & Net direct plant
4. Irett.ers of approval received from staffs of state Regrulatory Commissions in 1993
FERC FORM NO.1 (ED.12-87)Page 356.1
Name oI Hespondent
Avista Corporation
This
(1)
(2\
eDort ls:
[]An original
1A Resubmission
uale or i<epon(Mo, Da, Yr)
04t11t2014
YearPenoo or Kepon
End of 2O'l3lQ4
PURCHASES AND SALES OF ANCILI-ARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specifled in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
ln columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (0 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), (0, 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), (Q, and (g) report the total amount of all other types ancillary services purchased or sold during
the year. lnclude in a footnote and specify the amount for each type of other ancillary service provided.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
-inr
No
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of
Measure
(c)
Dollars
(d)
Number of Units
(e)
unfi ol
Measure
(f)
Dollars
(s)
Scheduling, System Control and Dispatch 63{MW 146,83(
Reaclive Supply and Voltage
Regulation and Frequency Response 59,29i MWh 7,53t 73,212 MW 654,511
Energy lmbalance 621 MW 1,925,512
Operating Reserve - Spinning 30{MWh 6,38(136,071 MWt''t,408,999
Operating Reserve - Supplemenl 30t MWh 6,38(11,125 MWh 85,667
Other '1,337,s1r MW 11,957 ,372 1,337 ,514 MW 11,957,372
Total (Lines 1 thru 7)1,s98,06(12,124,521 1,558,543 16,032,06't
FERC FORM NO. 1 (New 2-04)Page 398
Name of Respondent
Avista CorDoration
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
04t1112014
Year/Period of Report
2013tQ4
FOOTNOTE DATA
Interdepartmenta reserve service for Nati-ve
tmental reserve service for Native Load.
tmental reserve service for Nat ve Load.
fnterdepartmenEa spr-nnlng reserve servr-ce or Nat
:398 Line No.:7 Column: e
;398 Line No.:7 Column:
FERC FORM NO.1 (ED.1 450.1
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
tnrs x(1) I(2) l'
oon ls:
]An originat
lA Resubmission
uale oI Kepon(Mo, Da, YQ
o4t11t2014
Year/Period of Report
End of 2013/Q4
MONTHLY TMNSMISSION SYSTEM PEAK LOAD
('l) Report the monthly peak load on the respondent's transmission system. lf 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 O by month the system' monthly maximum megawatt load by statistical classifications. See General lnstruction for
the definition of each statistical classification.
NAME OF SYSTEM:
Line
No.Month
(a)
Monthly Peak
MW - Total
(b)
Day of
Monthly
Peak
(c)
Hour of
Monthly
Peak
(d)
Firm Network
Service for Self
(e)
Firm Network
Service lor
Others
(0
Long-Term Firm
Pointto-point
Reservations
(s)
Other Long-
Term Firm
Service
(h)
Short-Term Firm
Pointto-point
Reservation
(D
Other
Service
(i)
January 2,14t 1 80(1,49i 31 16:lt 180 277
February 1,931 2(1 90(1,39(26(16:12(418
March 1,97i 1 90(1,441 25!16:It 112 703
4 Total for Quarter I 6,04t 4,32:821 48(4i 412 't,398
April 1,961 1(90(1,'t 1 21 18:1l 45t 17
May 2,05 170C 1,25t 22:l 181 l!391 218
June 2,27 2t 170t 1,35(23!18(497 50
Total for Quarter 2 6,29i 3.72i 671 54,6t 1,34'l 285
July 2,45,170C 1,58i 29t 18 3(lot 87
1 August 2,31t 1 170C 1,461 26t 18(3(40(94
1 September 1,92 1 170C 1,38:24t 171 2t 11 2E
1 Total for Ouarler 3 6,68i 4,42t 80(53r 8r 92t 216
1 October 1,85r 3(80(1,29t 271 161 1t 121 261
1 November 2,Ul 21 80(1,40:31(16i 1t 171 118
1 December 2,35i 1 80(1,65i 36r 16:1!171 363
1 Total for Quarter 4 6,25,4,35(94t 49:E 46:742
1i Total Year to
Date/Year 25,281 16,82t 3,25(2,oil 241 3,13t 2,641
FERC FORM NO. 1/3-Q (NEW. 07-04)Page 400
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]en orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 20131Q4
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line
No.
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 2'.1 DISPOSITION OF ENERGY
Seneration (Excluding Station Use):22 Sales to Ultimate Consumers (lncluding
lnterdepartmental Sales)
8,909,40S
Steam 1,521,53(
Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 311.)Hydro-Conventional 3,645,83i
Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
4,409,58t
Other 1,861,74:
Less Energy for Pumping 25 Energy Furnished Without Charge
Net Generation (Enter Total of llnes 3
through 8)
7,029,10!26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
12,20i
1 Purchases 6,911,07'27 Total Energy Losses 606,45(
11 Power Exchanges:28 IOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL L|NE 20)
13,937,65i
1 Received 554,65r
1 Delivered 557,171
1 Net Exchanges (Line 12 minus line 13)-2,521
1t Transmission For Other (Wheeling)
1 Received 2,977,70t
17 Delivered 2,977,7Ot
1 Net Transmission for Other (Line '16 minus
line 17)
.tc Transmission By Othec Losses
2C TOTAL (Enter Total of lines 9, 1 0, 14, 1 I
and 19)
13,937,65i
FERC FORM NO.1 (ED.12-90)Page 401a
Name of Respondent
Avista Corporation
I nts l(eoon ts:(1) []Rn Orisinat(2) J-lA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
MONTHLY PEAKS AND OUTPUT
1. Report the monthly peak load and energy output. lf 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, lnclude 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 (0 the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM:
-rne
No.Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(c)
MONTHLY PEAK
Megawatts (See lnstr. 4)
(d)
Day of Month
(e)
Hour
(f)
2l January 319,33:356,419 1.574 21 1 800
3(February 256,83€457,520 1,40t 21 1 900
31 March 307,82(492.443 1,394 19 0800
3i April ,346,67f 606,1 25 1,284 23 0800
JI May ,329,38t 591,874 1,304 10 1 700
3r June ,142,424 424,485 1,406 28 't700
3I July ,078,80:268,224 1,571 2 1700
3(August 000,40t 213,044 1,473 14 1600
3;September 886,374 200,650 1,38t 12 1 700
3t October 989,94i 261,232 't,271 30 0800
?(November 1,088,75(288,147 1,41t 21 1 800
4(December 1 .1 90.892 249,422 1,669 I 1 800
41 TOTAL 13,937,652 4,409,585
FERC FORM NO.1 (ED.12-90)Page 401b
Name of Respondent
Avista Corporation
This ReDort ls:(1) fiAn Originat(2) 3A Resubmission
uale or Hepon(Mo, Da, Yr)
o4t't1t2014
YeaflPenoo oI Kepon
End of 2013/Q4
STEAM-ELECTRIC GENERATI NG PI-ANT 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{urbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. lf any employees attend
more than one plant, report on line 1 1 the approximate average number of employees assignable to each plant. 6. lf 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. lf more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name: Coyofe SPrings 2
(b)
Plant
Name: Spokane N.E.
(c)
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear Gas Turbine Gas Turbine
2 Iype of Constr (Conventional, Outdoor, Boiler, etc)Not Apolicable Not Applicable
3 Year Orioinallv Constructed 2003 1 978
4 Year Last Unit was lnstalled 2003 1978
5 lotal lnstalled Cap (Max Gen Name Plate Ratings-MW)287.04 61.80
6 Net Peak Demand on Plant - MW (60 minutes)309 49
7 Plant Hours Connected to Load 73',t6 5
I Net Continuous Plant Capability (Megawatts)284 65
9 When Not Limited bv Condenser Water 284 0
10 When Limited by Condenser Water 284 0
11 \veraqe Number of Emplovees 13
12 Net Generation, Exclusive of Plant Use - KWh 1 796280000 222000
13 ]ost of Plant: Land and Land Riqhts 0 157277
14 Structures and lmprovements 1 1 376063 74/.320
15 Equipment Costs 16't014832 14071514
16 Asset Retirement Costs 351 68i 0
17 Total Cost 17274257i 14973111
18 Sost per KW of lnstalled Capacity (line 17l5) lncluding 601.890t 242.2833
'!9 >roduction Expenses: Oper, Supv, & Engr 1 296595 24213
20 Fuel 5636666t 13131
21 Coolants and Water (Nuclear Plants Only)0
22 Steam Expenses 0
23 Steam From Other Sources 0
24 Steam Transferred (Cr)0
25 Electric Expenses 1719047 35644
26 Misc Steam (or Nuclear) Power Expenses 1 86321 14935
27 Rents 6693 0
28 Allowances 0
29 Maintenance Supervision and Engineering 81 334t M1
30 Maintenance of Structures 4572e 620
3'1 Maintenance of Boiler (or reactor) Plant 0
32 Maintenance of Electric Plant 1 368944 260556
33 Maintenance of Misc Steam (or Nuclear) Plant 59263 31844
34 Total Production Exoenses 61 862604 381 384
35 Expenses per Net KWh 0.0344 1.7179
36 :uel: Kind (Coal, Gas, Oil, or Nuclear)Gas Gas
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/N uclear-indicate)MCF MCF
38 Quantity (Units) of Fuel Burned 12307078 0 31 32 0 0
39 Avo Heat Cont - Fuel Burned (btu/indicate if nuclear)1 020000 0 1 020000 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 4.580 1.000 0.000 4.192 0.000 0.000
41 Average Cost of Fuel per Unit Burned 4.580 0.000 0.000 4.192 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 4.490 ).000 0.000 4.'.110 0.000 0.000
43 Averaoe Cost of Fuel Burned oer KWh Net Gen 0.031 0.000 0.000 0.059 0.000 0.000
44 Average BTU per KWh Net Generation 6988.000 0.000 0.000 14390.000 0.000 0.000
FERC FORM NO. r (REV. 12-03)Page 402
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn orlsinat(2) l-.lA Resubmission
Date of Report(Mo, Da, Yr)
04t1112014
Year/Period of Report
End of 20131Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
9. ltems 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 lC 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." lndicate 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{urbine equipment, report each as a separate plant. However, if a gas{urbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas{urbine with the steam plant. 12. ll a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs aftributed 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.
Plant
Name: Keflle Fal/s
(d)
Plant
Name: Colstnp
(e)
Plant
Name: Rathdrum
(f)
Line
No.
Steam Steam Gas Turbine 1
Conventional Conventional Not Aoolicable 2
1 983 1 984 1 995 3
1 983 1 985 1 995 4
50.70 233.40 166.50 5
51 230 169 6
7152 8532 255 7
54 222 167 8
54 222 0 9
54 222 0 10
25 145 1 11
294379000 1227151000 33688000 12
2200714 1 289095 621682 13
25050783 102377273 3441419 14
686961 79 200812917 59314059 '15
450687 1 34589 0 16
96398363 30461 3874 633771 60 17
'1901 .3484 1 305.'t 151 380.6436 18
70260 21 1 681 17129 19
7916177 17275865 1473796 20
0 0 0 21
738364 3459834 0 22
0 0 0 23
0 0 0 24
945687 72140 167520 25
459098 2286638 1 70340 26
0 33093 0 27
0 0 0 28
72162 366389 597 29
59747 621023 969 30
1704204 4396751 0 31
325820 846926 1 91 789 32
228612 570742 17584 33
12520131 30141082 2039724 34
0.0425 0.0246 0.0605 35
Wood Gas Coal oil Gas 36
TON MCF TON BBL MCF 37
478948 4047 0 768825 1 648 0 3733240 0 0 38
8600000 1 020000 0 1 6970000 5880000 0 1 020000 0 0 39
16.492 4.269 0.000 22.179 135.940 0.000 4.216 0.000 0.000 40
16.492 4.269 0.000 22.179 135.940 0.000 4.216 0.000 0.000 41
1.920 4.1 86 0.000 '1.307 23.120 0.000 4.133 0.000 0.000 42
0.027 0.055 0.000 0.014 0.000 0.000 0.044 0.000 0.000 43
1 4007.000 0.000 0.000 '10640.000 0.000 0.000 1 0585.000 0.000 0.000 44
FERC FORM NO. 1 (REV.12-03)Page 403
Name oI Hesponoenl
Avista Corporation
This Reoort ls:(1) 5]Rn orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
o4t1112014
Year/Period of Report
End of 2O13lQ4
STEAM-ELECTRIC GENERATING PI-ANT STATISTICS (Large Plants) (Contin ued)
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{urbine and internal combustion plants of 1 0,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. lf any employees attend
more than one plant, report on line I 1 the approximate average number of employees assignable to each plant. 6. lf 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. lf more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name'. Boulder Park
(b)
Plant
Name:
1 (ind of Plant (lnternal Comb, Gas Turb, Nuclear lnternal Comf
2 l-ype of Constr (Conventional, Outdoor, Boiler, etc)Conventiona
3 fear Orioinallv Constructed 2002
4 fear Last Unit was lnstalled 2002
5 Total Installed Cap (Max Gen Name Plate Ratinqs-MW)24.6C 0.00
6 tlet Peak Demand on Plant - MW (60 minutes)2a 0
7 :lant Hours Connected to Load 1228 0
I tlet Continuous Plant Capability (Meqawatts)24 0
9 When Not Limited by Condenser Water 0
10 When Limited by Condenser Water c 0
11 \verage Number of Employees 1 0
12 rlet Generation, Exclusive of Plant Use - KWh 25921 00C 0
13 Sost of Plant: Land and Land Riohts 1 8562e 0
14 Structures and lmprovements 1204874 0
't5 Eouioment Costs 3144486e 0
16 Asset Retirement Costs c 0
17 Total Cost 32835369 0
'18 lost per KW of lnstalled Capacity (line 17l5) lncludins 1334.7711 0
19 )roduction Expenses: Oper, Supv, & Engr 't1703 0
20 Fuel 1 026805 0
21 Coolants and Water (Nuclear Plants Only)c 0
22 Steam Expenses c 0
23 Steam From Other Sources c 0
24 Steam Transferred (Cr)c 0
25 Electric Expenses 1 55988 0
26 Misc Steam (or Nuclear) Power Expenses 396'16 0
27 Rents c 0
28 Allowances c 0
29 Maintenance Suoervision and Enoineerino 264 0
30 Maintenance of Structures 496 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 163441 0
33 Maintenance of Misc Steam (or Nuclear) Plant 66608 0
34 Total Production Expenses 1465921 0
35 Expenses per Net KWh 0.0566 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)GaS
37 Unit (Coal-tons/Oil-banel/Gas-mcf/N uclear-indicate)MCF
38 Quantity (Units) of Fuel Burned 237308 0 0 0 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)'t020000 0 0 0 0 0
40 Avs Cost of Fuel/unit, as Delvd f.o.b. durinq year 4.327 0.000 0.000 0.000 0.000 0.000
4'.l Average Cost of Fuel per Unit Burned 4.327 t.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Mlllion BTU 4.242 ).000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.040 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 9338.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO. I (REV.12-03)Page 402.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) E:]An Original(2) aA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Contin ued)
9. ltems 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 lC 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." lndicate 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. l'f 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.
Plant
Name:
(d)
Plant
Name:
(e)
Plant
Name:
Line
No.
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
0 0 0 8
0 0 0 9
0 0 0 10
0 0 0 11
0 0 0 12
0 0 0 13
0 0 0 14
0 0 0 15
0 0 0 16
0 0 0 17
0 0 0 18
0 0 0 19
0 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000 35
36
37
0 0 0 0 0 0 0 0 0 38
0 0 0 0 0 0 0 0 0 39
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44
FERC FORM NO.1 (REV.12-03)Page 403.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) [.lAn orisinal(2) 1A Resubmission
Date of Report(Mo, Da, Yr)
04t1112014
Year/Period of Report
End of 20131Q4
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. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. lf any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. lf 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 50 1 and 547 (Line 42) as show on Line 20. 8. lf more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Line
No.
Item
(a)
Plant
Name:
Plant
Name:
(c)
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear
2 fype of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was lnstalled
5 Total lnstalled Cap (Max Gen Name Plate Ratings-MW)0.00 0.00
6 Net Peak Demand on Plant - MW (60 minutes)0 0
7 Plant Hours Connected to Load 0 0
I Net Continuous Plant Capability (Megawatts)c 0
I When Not Limited by Condenser Water 0 0
0 When Limited bv Condenser Water 0 0
1 Average Number of Employees 0 0
2 Net Generation, Exclusive of Plant Use - KWh 0 0
3 Cost of Plant: Land and Land Rights 0 0
4 Structures and lmprovements 0 0
5 Equipment Costs 0 0
6 Asset Retirement Costs 0 0
7 Total Cost 0 0
8 Cost per KW of lnstalled Capacity (line 17l5) lncluding 0 0
9 Production Expenses: Oper, Supv, & Enqr 0
20 Fuel 0
21 Coolants and Water (Nuclear Plants Onlv)0
22 Steam Expenses 0
23 Steam From Other Sources 0
24 Steam Transferred (Cr)0
25 Electric Expenses 0
26 Misc Steam (or Nuclear) Power Expenses 0
27 Rents 0
28 Allowances 0
29 Maintenance Supervision and Engineering 0
30 Maintenance of Structures 0
31 Maintenance of Boiler (or reactor) Plant 0
32 Maintenance of Electric Plant 0 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 0
35 Expenses per Net KWh 0.0000 0.0000
36 =uel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
38 Quantity (Units) of Fuel Burned 0 0 0 0 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)0 0 0 0 0 0
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 Averaoe Cost of Fuel Burned oer KWh Net Gen 0.000 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO.1 (REV. 12-03)Page 402.2
Name of Respondent
Avista Corporation
This Rer(1) E(2') tr
ort ls:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
0411112014
Year/Period of Report
End of 2O13lQ4
STEAM-ELECTRIC GENERATI NG PLANT STATISTICS (Large Plants) (Contin ued)
9. ltems under Cost of Plant are based on U. S. of A. Accounts. Produclion expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For lC 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." lndicate 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{urbine equipment, report each as a separate plant. However, if a gas{urbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. lt 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.
Plant
Name:
Plant
Name:
(e)
Plant
Name:
(0
Line
No.
1
2
3
4
0.00 0.00 0.00 5
0 0 0 6
0 0 0 7
0 0 0 I
0 0 0 I
0 0 0 10
0 0 0 11
0 0 0 12
0 0 0 13
0 0 0 14
0 0 0 15
0 0 0 16
0 0 0 17
0 0 0 18
0 0 0 19
0 0 0 20
0 0 0 21
0 0 0 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0 26
0 0 0 27
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0 32
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000 35
36
37
0 0 0 0 0 0 0 0 0 38
0 0 0 0 0 0 0 0 0 39
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 44
FERC FORM NO. 1 (REV.12-03)Page 403.2
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
o4t1'U2014
Year/Period of Report
20131Q4
FOOTNOTE DATA
Port and General Electric.
402 Line No.: -1 Column: c
ak load service
ated bv PPL Montana LLC-
Line No.: -1 Column: f
@ 402.1 Line No.: -1 Column: b
designed for peak load servlce
:403 Line No.: -1 Column: e
FERC FORM NO.1 1 450.'l
This Page Intentionally Left Blank
Name of Respondenl
Avista Corporation
This Reoort ls:(1) fiAn Originat(2) 3A Resubmission
Date of Report(Mo, Da, Yr)
04111t2014
Year/Period of Report
End of 2013/Q4
HYDROELECTRIC GENERATING PI-ANT STATISTICS (Large Plants)
1. Large plants are hydro plants of '10,000 Kw or more of installed capacity (name plate ratings)
2. lf 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. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specifying period.
4. lf a group of employees attends more than one generating plant, report on line 1 1 the approximate average number of employees assignable to each
olant.
Line
No.
Item
(a)
FERC Licensed Project No. 2S4S
Plant Name: Monroe Street(b\
iERC Licensed Project No. 2S4S
)lant Name: Upper Falls
(c)
1 Kind of Plant (Run-of-River or Storage)Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor)Conventiona Conventional
3 Year Originally Constructed 1 89C 1922
4 Year Last Unit was lnstalled 1992 1922
5 Total installed cap (Gen name plate Rating in MW)14.8C 10.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)17 't2
7 Plant Hours Connect to Load 8,651 8,40'l
I (a) Under Most Favorable Oper Conditions 15 10
10 (b) Under the Most Adverse Oper Conditions '15 10
11 Average Number of Employees 4 4
12 Net Generation, Exclusive of Plant Use - Kwh '104,654,00c 68,384,000
14 Land and Land Rights c 1,081,854
15 Structures and lmprovements 8,443,779 962,432
15 Reservoirs, Dams, and Waterways 9,977,635 7,674,'.146
17 Equipment Costs 12,749,437 5,561,235
18 Roads, Railroads, and Bridqes 50,448 320,283
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)31,221,299 15,599,950
21 Cost per KW of lnstalled Capacity (line 20 / 5)2,'.t09.5472 1,559.9950
23 Operation Supervision and Engineerinq c 438
24 Water for Power c 0
25 Hydraulic Expenses 0 36
26 Electric Expenses 604,700 595.859
27 Misc Hydraulic Power Generation Expenses 26,632 41,490
28 Rents 0 0
29 Maintenance Supervision and Engineering 145 40,403
30 Maintenance of Structures 2,258 623,254
31 Maintenance of Reservoirs, Dams, and Waterways 26,523 273,151
32 Maintenance of Electric Plant 48,731 104,916
33 Maintenance of Misc Hydraulic Plant 9,76€7,678
34 Total Production Expenses (total 23 thru 33)7'.t',75!1,687,225
35 Expenses per net KWh 0.006!0.0247
FERC FORM NO.1 (REV.12-03)Page 406
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn originat(2) aA Resubmission
Date of Report(Mo, Da, Yr)
04t1112014
Year/Period of Report
End of 20131Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
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.
FERC Licensed Project No. ZS4S
Plant Name: Nine Mile Falls(d)
FERC Licensed Project No. 2545
Plant Name: Post Falls
(e)
FERC Licensed Project No. 2058
Plant Name: Cabinet Gorge
/fl
Line
No.
Run-of-River Storagr Storag€1
Conventional Conventiona Outdoor 2
1 908 1 90(1952 3
1 994 1 98(1 953 4
26.40 14.8(265.0t 5
19 1 26S 6
8,1 32 7,00!8,40S 7
18 1 29!9
18 1 25!10
4 ,|11
82p22,000 84,904,00(1.042.427.O9C 't2
33.429 3,570,'r 1 11,550,02i 14
3,957,442 1 .486.71!12,163,27e 15
13,652,590 11,852,72e 31,936,304 16
12,604,124 3,175,57t 47,987,742 't7
625,'181 1,098,564 18
0 19
30,872,766 20.085.13t 1M,735,91 20
1 ,1 69.4230 1 ,357.1 03!395.229!21
17,269 4,62!1 07,1 9€23
0 24
6,393 7,194 25
652,1 06 656,38(1,271,43C 26
50,'141 51 ,914 188,001 27
0 28
3,296 23:14,481 29
32,504 11 ,144 117,552 30
51,021 52,293 32,60t 31
258,814 263,38(338,35i 32
6,604 1,76€39,31:33
1,078,148 1.0/.1.73i 2,116,128 u
0.0130 0.012:0.002c 35
FERC FORM NO.1 (REV.12-03)Page 407
Name of Respondent
Avista Corporation
This ReDort ls:(1) 5]nn Original(2) l--lA Resubmission
uare or Kepon(Mo, Da, Yr)
04t't1t2014
Year/Period of Report
End of 2013/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
'1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. lf 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, lf licensed project, give project number.
3, lf net peak demand for 60 minutes is not available, give that which is available specifying period.
4. lf a group of employees attends more than one generating plant, report on line 1 1 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 20SB
Plant Name: Noxon Rapids
rb)
FERC Licensed Project No. 2545
Plant Name: Long Lake
1c)
1 Kind of Plant (Run-of-River or Storage)Storage Storage
2 Plant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Constructed 1 95e 1 915
4 Year Last Unit was lnstalled 1977 1924
5 Total installed cap (Gen name plate Rating in MW)487.80 70.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)524 89
7 Plant Hours Connect to Load 4,93€6,585
I (a) Under Most Favorable Oper Conditions 622 90
10 (b) Under the Most Adverse Oper Conditions 58't 90
11 Average Number of Employees 11 5
12 Net Generation, Exclusive of Plant Use - Kwh 1,581,223,00t 504,779,000
14 Land and Land Riqhts 35,630,88!2,089,177
15 Structures and lmprovements 15,226,041 2,715,316
16 Reservoirs, Dams, and WateMays 33,810,81 1 17,475,672
17 Equipment Costs 106,014,53(12,188,460
'18 Roads, Railroads, and Bridges 246,561 0
19 Asset Retirement Costs 0
20 TOTAL cost (Total of 14 thru 19)190.928,82€34,468,625
21 Cost per KW of lnstalled Capacity (line 20 / 5)391.408C 492.4089
23 Operation Supervision and Enqineerinq 117,823 28,080
24 Water for Power 0
25 Hydraulic Expenses 't01 ,31 C 14,544
26 Electric Expenses 1.338.30€818,592
27 Misc Hydraulic Power Generation Exoenses '152,695 58,753
28 Rents 0
29 Maintenance Supervision and Engineering 16,251 8,901
30 Maintenance of Structures 88.773 47,032
31 Maintenance of Reservoirs, Dams, and Watenruays 132.54e 1 ,093,1 90
32 Maintenance of Electric Plant 2,343,81C 262,203
33 Maintenance of Misc Hydraulic Plant 111,13€38,465
34 Total Production Expenses (total 23 thru 33)4.402.649 2,369,760
35 Expenses per net KWh 0.002€0.0047
FERC FORM NO. 1 (REV.12-03)Page 406.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) $Rn Originat
(21 EA Resubmission
Date of Report(Mo, Da, Y0
0/.I11t2014
Year/Period of Report
End of 2013/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
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.
FERC Licensed Project No. 2S4S
Plant Name: Litfle Falls
(d'r
FERC Licensed Project No. 0
Plant Name:
1e)
FERC Licensed Project No. 0
Plant Name:
/fl
Line
No.
Run-of-River
Conventional 2
1910 3
191 1 4
32.00 0.00 0.00 5
36 0 0 b
6,651 0 0 7
36 0 0 9
36 0 0 10
4 0 0 11
176,539,000 0 0 12
4,325,371 0 0 14
1.081.881 15
5,058,551 0 16
9,209,759 17
0 0 18
0 19
19,675,562 20
614.8613 0.000c 0.000c 21
22 0 0 23
0 0 0 24
10,475 0 0 25
628,565 0 0 26
20,217 0 0 27
810,477 0 0 28
3,256 0 0 29
42,207 0 0 30
68,1 35 0 0 31
202,527 0 0 32
5,421 0 0 33
1,791,302 0 34
0.0101 0.000(0.0000 35
FERC FORM NO. 1 (REV.12-03)Page 407.1
Name of Respondent
Avista Corporation
tnrs Keoon ts:(1) []en origlnat(2) [-lA Resubmission
uale oI Kepon(Mo, Da, Yr)
04t11t2014
YearPenoo or Kepon
End of 20131Q4
GENERATING PLANT STATISTICS (Small Plants)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventlonal 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. lf licensed project,
give project number in footnote.
_rne
No.
Name of Plant
(a)
Year
Orio.ConEt.
(b)
tnsralteo uaDactr\tlame Plate Ratiri
(ln MW)
(c)
NEI FEAKDemandMW(60,9in.)
Net Generation
ExcludinoPlant UsE
(e)
Cost of Plant
(fl
1 Kettle Falls CT 2002 7.20 8.C 5,632,00(9,178,26:
2
3
4
5
6
7
8
I
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
M
45
46
FERC FORM NO.1 (REV.12-03)Page 410
Name of Respondent
Avista Corporation
I hrs Reoort ls:(1) fiRn Originat(2\ [--lA Resubmission
uate ol Kepon(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
End of 20131Q4
GE IERATING PLANT STA flSTlCS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 1 1 ,
Page 403. 4. lf net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. lf 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 (lncl Asset
Retire. Costs) Per MW
(s)
Operation
Exc'|. Fuel
(h)
Productron Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
(t)
Line
No.ruel
(D
rvrarrl(gilalt(;e
0)
1,274,755 124,033 282,782 27,36e Nat Gas 42i 1
2
3
4
5
6
7
I
9
10
11
12
13
14
15
16
17
'18
19
20
21
22
23
24
25
26
27
28
29
30
3'1
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO.1 (REV.12-03)Page 41'l
Name of Respondent
Avista Corporation
This Reoort ls:(1) E]Rn Orlginat(2) 1_1A Resubmission
Date of Report(Mo, Da, Yr)
04t1112014
Year/Period of Report
End of 20131Q4
TRANSMISSION LINE STATISTICS
1 . Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 1 32
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. lndicate 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 lf 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). ln 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.
Line
No.
UESIGNA I I(JN VULIAL,tr, IAVI(lndicate wtierdbther than
6O nwnla 3 nh:cal
Type of
Supporting
Structure
(e)
LENU t tl fl-Ote milesl(ln the Lase.ofunderoround lrnesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
9n SIrUCIUreof LineDesionated
fo
UII DlI UUTUI ESof AnotherLine
(s)
1 Group Sum 60.0(60.0(1.0t
2
3 Group Sum 115.0(1 15.0(1,544.0(
4
5 Beacon Sub #4 BPA Bell Sub 230.0(230.0(Steel Tower r.0(,|
o Beacon Sub BPA Bell Sub 230.0(230.0(I Type 5.0(
7 Beacon Sub #5 3PA Bell Sub 230.0(230.0(Steel Pole 4.0(1
I Beacon Sub #5 BPA Bell Sub 230.0(230.0(I Type 2.0(
I Beacon 3abinet Goroe Plant 230.0(230.0(Steel Tower 1.0(1
0 Beacon Sabinet Gorge Plant 230.0(230.0(Steel Pole 27.0t
1 Beacon 3abinet Goroe Plant 230.0(230.0(I Type 53.0(
2 Beacon Sub -olo Sub 230.0r 230.00 Steel Tower 1.0(
3 Beacon Sub lolo Sub 230,0(230.00 I Type 102.0(
4 Benewah Shawnee 230.0r 230.0(Steel Pole 60.0(
5 Noxon Planl )ine Creek Sub 230.0(230.0r Steel Pole 30.0(
b Noxon Plant )ine Creek Sub 230.0r 230,00 I Type 14.0(
7 Cabinet Gorqe Plant \oxon 230.0(230.00 I Type 19.0(
8 Benewah Sw. Station rine Creek Sub 230.0(230.00 3teel Tower
9 Benewah Sw- Station rine Creek Sub 230.0(230.00 I Type 43.0(
20 Divide Creek -olo Sub 230.0(230.00 iteel Tower
21 Divide Creek -olo Sub 230.0(230.00 I Type 43.0(
22 N. Lewiston Walla Walla 230.0(230.00 'l Type 43.0(
23 N. Lewiston Walla Walla 230.0(230.00 iteel Pole 4.0(
24 N. Lewiston Shawnee 230.0(230.00 iteel Pole 7.0(
25 N. Lewiston Shawnee 230.0(230.00 'l Type 27,0(
26 Walla Walla Wanapum 230.0(230.00 \lum
2i Walla Walla Wanapum 230.0(230.00 { Type 78.0(1
28 BPA (Libby)Noxon Plant 230.0(230.00 Steel Tower 1.0(
2(BPA/Hot Sorinos #1 Noxon Plant 230.0(230.00 iteel Tower 1.0(1
3(BPA/Hot Springs #2 Noxon Plant (dead)230.01 230.00 iteel Tower 2.0c
3'1 BPtuHot Sorinos #2 Noxon Plant 230,0(230,00 I Type 68.0(1
5t BPA Line West Side Sub 230.0i 230.00 Steel Pole 2.0(
JJ Hatwai N. Lewiston Sub 230.0r 230,00 H Type 7.0(1
34 Divide Creek lmnaha 230.0i 230.00 I Type 20.0(
3:Colstrip Plant Broadview 500.0i 500.00
3€TOTAL 2,207.0(3.00 32
FERC FORM NO. 1 (ED.12-87)Page
Name of Respondent
Avista Corporation
This ReDort ls:(1) 5]Rn orisinal(2) -A Resubmission
uate oI Kepon(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 20131Q4
TRANSMISSION LINE STATISTICS (Continued)
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. lf 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. lf such propefi 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 butwhich 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 (t) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
cos I oF LINE (lnclude tn uolumn u) Lano,
Land rights, and clearing rightof-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
_tne
No.
Land
0)
]onstruction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses
1 36,03r 498,43(634,46r I
2
10,156,25 1 30,753,98(140,910,23:154,571 699,49{854,061 2
4
272 ACSS 5
272 ACSS 17,91 1,316,67(1,334,59 8,8'r I 1.82t 10,64:6
272 ACSS 7
272 ACSS 30,32r 3,275,35;3,305,68('t ,1 6:1,16:I
272 ACSS I
590 ACSS 10
590 ACSR 1,1 s6,19t 36,554,27:37,710,46!64i 26,981 27.62 11
272 ACSS 12
272 Mclt4AL 456,16:8,532,441 8.988,60{861 5,61(6,48:13
590 ACSS 570.20',48,024,93'48,595,1 3{43:11,46',11,90(14
272 ACSR 15
E4 Mcf\4AL 1,097,67r 18,087,78t 19,'185,46;2.62(259,69 262,31 16
r54 MoMAL 184,21 1,637,s0(1,821,71 282 18,72'19,00:17
154 MoMAL 18
154 Mo[4AL 320,36r 2,611,38r 2,931,74i 36,57(8,841 45,41 19
272 MclrrtAl 20
272 Mclt/AL 86,221 4,488.64:4,574,87(2,921 58,58{61,501 21
272 McMAL 22
272 MoIVAL 623,98,6,996,68r 7,620,66{771 1,932 2,71 23
272 ACSR 24
272 ACSR 872,151 10,043,831 10,915,981 4t 5,01i 5,06(25
272MaMAL 26
272 MoMAL 70,78'2,7n 341 2,848,121 11417e 28,90t 143,08,27
272 ACSR 28
272 ACSR 19,521 '19,521 3,37S 1,61{4.99,29
272 MoMAL 30
272 McMAL 307,63:4,059,40(4.367.031 109,71 S 8,651 1 18.37(31
272 ACSR 36,46:594,65i 631,1 1 3,411 3,41t 32
590 ACSR 106,58'2,600,73t 2,707,311 2,171 2,17i 33
272 Mcl\4AL 205,26i 1,322,28i 1,527,541 282 28i 34
595,78{30,535,85r 31,131,64:40,07€248,561 89,84r 378,48,35
17,030,21 314,731,717 331,761,93i 476,17t 1,392,67;89,84,1,958,69 36
FERC FORM NO. 1 (ED.12-87)Page 423
Name oI Kesponoenl
Avista Corporation
This ReDort ls:(1) 5]en orisinat(2) -A Resubmission
uate oI Kepon(Mo, Da, Y0
04t1112014
YeailFenoo or Kepon
End of 2013/Q4
TRANSMISSION LINES ADDED DURING YEAR
1. Report below the information called for concerning Transmission lines added or altered during the year. lt 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. lf actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
Line
No.
LINE DESIGNA]ION LII IELength
tnMiles
(c)
SUPPOR IING S IHUU IUKE UII{UUI I l; PEIT l, I I{UU I UIi
From
(a)
To
(b)
Type
(d)
AVEI AUENumbeiper
Miles
(e)
Present
(0
Ultimate
(s)
1 No new transmission lines added ln 2013
1
11
1i
1:
1t
1
1(
1
1t
1(
2(
21
Zt
2:;
2/
2!
2t
2i
2t
2l
3(
31
5z
5r
3t
3t
3(
3;
3t
3(
4(
41
42
4:
44 TOTAL
FERC FORM NO.1 (REV.12-03)Page
Name of Respondent
Avista Corporation
This R(1) t(2) r
eoort ls:
1]An orisinal-lA Resubmission
Date of Report
(Mo, Da, Yr)
04t11t20't4
Year/Period of Report
End of 20131Q4
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. lnclude 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. lf 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.
CONDUCT()RS Voltage
KV
(Operating)
LINE UOS I Line
No.Size
/h)
Specification
(i)
Confiouration
and Spacing
(i)
Land and
Land Rightsfl)
Poles, Towers
and Fixtures
/m)
Conductors
and Devices/n)
Asset
Retire. Costs1o)
Total
(o)
1
2
?
4
E
6
8
c
1C
11
1
I
14
1
1
1i
1
1!
2t
2',l
2i
2i
2t
2!
2t
21
2t
2S
3(
31
5t
5i
34
AE
3€
3i
3t
2C
4C
4'.!
42
43
44
FERC FORM NO.1 (REV.12-03)Page 425
Name of Respondent
Avista Corporation (1) E(2) T
ron ls:
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2013/Q4
SUBSTATIONS
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. lndicate 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).
_tne
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 STATE OF WASHINGTON
2
3 Airway Heights Distr. Unattended 115.0(13.80
4 Barker Road Distr. Unattended 1 15.0(13.80
5 Beacon Trnsm. & Distr Unatt 230.0(115.00 13.8(
o Boulder Trnsm. Unattended 230.0(1 15.00 13.8(
7 Chester Distr. Unattended 't15.0(13.80
I Chewelah 1'1SKv Distr. Unattended 1 15.0(13.80
I Colbert Distr. Unattended 't15.0(13.80
10 College & Walnut Distr. Unattended 't 15.0(13.80
11 Colville 115Kv Distr. Unattended 1 15.0(13.80
12 Critchfield Distr. Unattended 1 15.0(13.80
13 Deer Park Dist. Unattended 't 15.0(13.80
14 Dry Creek Transm. Unattended 230.0('t15.00 13.8C
15 Dry Gulch Distr. Unattended 't 15.0(13.80
16 East Colfax Distr. Unattended 't15.0(13.80
17 East Farms Distr. Unattended 1 15.0(13.80
18 Fort Wright Distr. Unattended 1 15.0(13.80
19 Francis and Cedar Distr. Unattended 115.0(13.80
20 Gifford Distr. Unattended 1 t 5.0(34.00
21 Glenrose Distr. Unattended 115.0(13.80
22 Greenwood Distr. Unattended 115.0('13.8C
23 Hallett & White Distr. Unattended 1 't5.0(13.8C
24 lndian Trail Dlst. Unattended 1 15.0(13.8C
25 lndustrial Park Dist. Unattended 115.0(13.8C
26 Kettle Falls Distr. Unattended 115.0(13.8C
27 Lee & Reynolds Distr. Unattended 115.0(13.8C
28 Liberty Lake Distr. Unattended 't 15.0(13.80
29 Little Falls 115/34Kv Distr. Unattended 1 15.0(34.0C
30 Lyons & Standard Distr. Unattended 1 15.0(13.80
31 Mead Distr. Unattended 1 15.0(13.80
32 Metro Distr. Unattended 115.0(13.80
33 Milan Distr. Unattended 1't 5.0(13.80
34 Millwood Dist. Unattended 115.0(13.80
35 Ninth & Central Distr. Unaftended 115.0(13.80
36 Northeast Distr. Unattended 1 15.0(13.80
37 Northwest Distr. Unattended 1 15.0(13.80
38 Opportunity Dist. Unattended 1 15.0(13.80
39 Othello Distr. Unattended 115.0(13.80
40 Post Street Distr. Unattended 115.0(13.8(
FERC FORM NO. 1 (ED.12-96)Page 426
Name of Respondent
Avista Corporation
lhts Reoort ls:(1) fiRn originat(2\ [-lA Resubmission
uate or Kepon(Mo, Da, Yr)
04t11t2014
Year/Penoo or Kepon
End of 20131Q4
SUTSTATlONS (Continued)
5. Show in columns (l), O, 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.
Capacity of Substation
(ln Service) (ln MVa)
(fl
NUmoer or
Transformers
ln Service
(o)
Number of
Spare
Transformers
(h)
CONVERSION APPAMTUS AND SPECIAL EOUIPMENT Line
No.Type of Equipment
1i)
Number of Units
(i)
Total Capacity(ln MVa)
1k)
2
24 2 Frcd Oil&Air Fan&Cat 3€4(3
12 1 Two Stage Far 1 2C 4
536 4 Two Stage Far 56(5
300 2 Two Stage Far 50(6
24 2 Frcd Oil & Air Far 4C 7
12 1 Two Stage Far 1 2(E
't2 1 Frcd Oil & Air Far 1 2C 9
36 2 Two Stage Far 6(10
32 3 Frcd Oil & Air Far 4t 1
12 1 Two Stage Far 1 2t 12
12 1 Two Stage Far 1 2(13
150 1 Two Stage Fan & Capr 223 25C 14
24 2 Frcd Oil & Air Far 4C 15
12 ,|FrOil/Air Far 2C 16
12 1 Two Stage Far 2t 17
24 Fr Oil/Air/2StgFar 4(16
36 Two Stage Far 6(19
12 1 20
12 1 Frcd Oil & Air Far 2t 21
12 1 Two Stage Far 2(22
12 1 Two Stg Far 2(23
12 1 Two Stage Far 1 2(24
24 2 Two Stg/PVFrcd Oi 1t 4(25
12 1 Frcd Oil & Air Far 1 2(26
12 1 Two Stage Far 1 2(27
24 2 Two Stage Far 4(?,8
1 1 29
3e 2 Two Stage Far 5(30
1 1 Two Stage Far 1 3(31
24 2 Two Stage Far 4(32
24 2 Frcd Oil & Air Far 4(33
24 2 2 Two Stage Far 4(34
24 2 1 Frcd & Two Stage Far 4(35
24 2 Two Stage Far 4(36
24 2 Two Stage Far 4(37
12 1 Two Stage Far 1 2(3E
24 FrOil/AirFar 4(39
36 Frcd Oil & Wt Far 6(40
FERC FORM NO.1 (ED.12-96)Page
Name of Respondent
Avista Corporation
tnrs HeDon ts:(1) []An Originat(2) l-lA Resubmission
uale oI Kepon(Mo, Da, Yr)
04t1112014
Year/Period of Report
End of 2O13lQ4
SUBSTATIONS
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. lndicate 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).
_tne
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Pound Lane Distr. Unattended 1 15.0('13.8C
2 Ross Park Distr. Unattended 1 15.0(13.80
3 Roxboro Distr. Unattended 1 15.0(24.00
4 Shawnee Trans. Unattended 230.0(1 15.00 13.8C
5 Silver Lake Distr. Unattended 1 15.0('t3.80
6 Southeast Distr. Unattended 1 15.0(13.80
7 South Othello Distr. Unattended 1 15.0(13.80
8 South Pullman Distr. Unattended '1 15.0(13.80
9 Sunset Distr. Unattended 't 15.0(13.80
10 Terre View Dist. Unattended 1i5.0(13.80
11 Third & Hatch Distr. Unattended 1 15.0C 13.80
12 Turner Dist. Unattended 1 15.0('13.80
13 Waikiki Distr. Unattended '1 15.0(13.80
14 West Side Trans. Unattended 230.0(1 't5.00 13.8(
15 Other: 28 substa less than 10MVA Distr. Unattended
16
17 STATE OF IDAHO
18 Appleway Dist. Unattended 1 15.0(13.80
19 Avondale Dist. Unattended ''l 15.0(13.80
20 Benewah Trans. Unattended 230.0(I 15.00 13.8(
21 Big Creek Distr. Unattended 1 15.0(13.80
22 Blue Creek Distr. Unattended 1 15.0(13.8(
23 Bunker Hill Limited Distr. Unattended 1 '15.0(13.80
24 Cabinet Gorge (Switchyard)Trans. Unattended 230.0('t't5.0(13.8C
25 Clark Fork Distr. Unattended 1 15.0(21.8C
26 Coeur d'Alene 1Sth Ave Distr. Unattended '1 15.0(13.8(
27 Cottonwood Distr. Unattended 115.0(24.9t
28 Dalton Distr. Unattended 't 15.0(13.8C
29 Grangeville Distr. Unattended 1 15.0(13.8C
30 Holbrook Distr. Unattended 115.0(13.8C
31 Huetter Distr. Unattended I 15.0(13.8C
32 ldaho Road Distr Unattended 1 15.0(13.8C
33 Juliaetta Distr. Unattended 'l 15.0(13.8C
34 Kamiah Dist. Unattended 1 15.0(13.8C
35 Kooskia Distr. Unattended I 15.0(13.8C
36 Lolo Tran & Dist Unaftnd 230.0(1 15.0C 13.8(
37 Moscow Distr. Unattended 1 15.0(13.8C
38 Moscow 230Kv Tran & Dist Unattnd 230.0(115.0C 13.8(
39 North Moscow Disk. Unattended 1'15.0(13.8C
40 North Lewiston 230kV Trans Unattended 230.0(1 15.00 13.8(
FERC FORM NO.1 (ED.12-96)Page 426.1
Name of Respondent
Avista Corporation
tnrs Keoon ls:(1) fiRn originat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
04t11t2014
Year/Period of Report
End of 2013/Q4
SUBSI ATIONS (Contlnued)
5. Show in columns (l), O, 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.
Capacity of Substation Number of
Transformers
ln Service
(o)
NUmDer oI
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.(ln Service) (ln MVa)
(fl
Type of Equipment
(i)
Number of Units
ri)
Total Capacity
(ln MVa)(k)
24 2 Two Stage Far 4(1
3(2 Two Stage Far $t 2
24 2 Two Stage Far 4(3
'150 1 Two Stage Far 25t 4
1 I Frcd Oil & Air Far 2t 5
30 2 Two Stage Far 5(6
12 ,|Two Stage Far 1 2(7
30 2 Two Stage Far 5(E
33 2 Two Stage Fan & Capr 5C EI I
12 1 Two Stage Far 1 2(10
54 3 Two Stg Fan & Cal 10:9(
36 2 Two Stg Far 6(12
24 2 Two Stage Far 4l 13
254 2 14
166 34 15
16
17
36 2 Two Stage Far 6(18
12 1 Two Stage Far 1 2t 't9
75 1 Two Stage Fan & Capr 221 121 20
18 2 Portable Far 2i 21
2A 1 22
1 1 Frcd Air Far ,|1(23
7!1 Two Stage Far 1 12t 24
1 1 Frcd Air Far 1 1 25
3€Two Stage Far 6(26
1 1 Two Stage Far 1 2(27
24 FrcOil/Air2StgFar 4(28
2a FrcdOil/Air/Pt Fan&C 1 3t 29
1 1 Two Stage Far 1 2(30
1 1 Two Stage Far 1 2(31
1 1 Two Stage Far 1 2(32
I 1 Frcd Oil & Air Far 1 2(33
1 ,|Two Stage Far 1 2(34
1 Frcd Air Far 2(35
262 Frcd Oil/Air/Two Stg 1 27(36
24 Froil/Air/2Stg Far 4(37
162 Two Stage Fan & Caps 4t 262 38
1 1 Two Stage Far 1 2(39
25C 1 1 Capacito(4t 40
FERC FORM NO.I (ED.12-96)Page 427.1
Name of Respondent
Avista Corporation
I nts Ke(1) E(2\ T
rofi ts:
An Original
A Resubmission
uale or Hepon(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
End of 20131Q4
SUBSTATIONS
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. lndicate 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).
-tne
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 North Lewiston Distr. Unattended 1 15.0(13.8C
2 Oden Distr. Unattended 1 15.0(21.8C
3 Oldtown Distr. Unattended 1 15.0(21,8C
4 Orofino Distr. Unattended 1 15.0(13.8C
5 Osburn Distr. Unattended 1 15.0(13.8C
6 Pine Creek Tran & Dist Unattnd 230.0(115.0C 13.8C
7 Pleasant View Distr. Unattended 1 15.0(13.8C
8 Plummer Dist Unattended 1 15.0(13.8C
I Post Falls Distr. Unattended 1 15.0(13.8C
10 Potlatch Distr. Unattended 1 15.0(13.8C
11 Prarie Distr. Unattended 1 15.0(13.8C
12 Priest River Distr. Unattended 1'15.0(20.8C
13 Rathdrum Trans & Disk Unattd 230.0('t 15.0c 13.8C
14 Sagle Dist. Unaftended 1 15.0(20.80
15 Sandpoint Distr. Unattended 1 't 5.0(20.8C
16 South Lewiston Distr. Unattended 115.0(13.8C
17 Sweetwater Distr. Unattended 1 15.0(24.90
18 St. Maries Distr. Unattended 115.0(23.90
19 Tenth & Stewarl Distr. Unattended 1 15.0(13.80
20 Wallace Distr. Unattended 1 15.0(13.80
21 Other: 13 substa less than 10 MVA Distr. Unattended
22
23 STATE OF MONTANA
24 1 substation less than 10 MVA Distr. Unattended
25
26 SUBSTA. @ GENERATING PLANTS
27 STATE OF WASHINGTON
28 Boulder Park Trans. Attended 1 15.0(13.80
29 Kettle Falls Trans. Attended 1 15.0(13.80
30 Long Lake Trans. Attended 115.0(4.00
31 Nine Mile Trans. Attended 115.0(13.80
32 Little Falls Trans. Attended 115.0(4.00
33 Northeast Trans. Attended 115.0(13.80
34 Post Street Trans. Attended 13.8(4.00
35
36 STATE OF IDAHO
37 Cabinet Gorge (HED)Trans. Attended 230.0(13.80
38 Post Falls Trans. Aftended 115.0(2.34
39 Rathdrum Trans. Aftended 115.0(13.8(
40 STATE OF MONTANA
FERC FORM NO. 1 (ED.12-96)Page 426.2
Name ot Kespon0ent
Avista Corporation
I nrs
(1)
(2)
x
on ls:
An Original
A Resubmission
uale oI Kepon(Mo, Da, Yr)
44h112014
YearPenoo or Kepon
End of 20131Q4
SUBS'ATIONS (Continued)
5. Show in columns (l), O, 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 othenruise 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.
Capacity of Substation Number of
Transformers
ln Service
(o)
NUmOer oI
Spare
Transformers
ft)
CONVERSION APPAMTUS AND SPECIAL EQUIPMENT Line
No.(ln Service) (ln MVa)
(fl
Type of Equipment
(i)
Number of Units
0)
Total Capacity
(ln MVa)
(k)
1 1
1 Frcd Air Far 't 2
1 2 Frcd Air Far 22 3
2C 2 Frcd Oil & Air Far 1 2t 4
12 Portable Far 1 1!5
zot Two Stg Fan/Capacitc 4a 27(6
12 Two Stage Far 2C 7
12 Two Stage Far 1 2(I
1 Two Stage Far 3(I
15 2 Portable Far 10
12 1 Frcd Oil & Air Far 2C 11
1 1 Frcd Air Far 12
474 4 Frcd Oil & Air Far 5(49(13
't2 1 Two Stage Far 2C 14
3C 3 Frcd Air Far 3t 15
27 4 Port Fan/FrcdOil/Air 2C 16
12 1 Frcd Oil & Air Far 2C t7
24 2 Two Stage Far 4C 1E
3C 2 Frcd Oil/Air/Two Stg 5C 19
1C 3 20
70 1 21
22
23
5 1 24
25
26
?t
36 1 Two Stage Far 1 5(ZE
34 1 1 Two Stage Far 1 Or 29
80 4 30
12 1 31
24 2 Frcd Oil & Air Far 4(32
36 1 Two Stage Far 1 6(33
2E 2 34
35
36
30c 6 1 Frcd Oil and Air Far 37
1 2 Frcd Air/Oil/Air Far 21 3E
114 2 1 Two Stage Far 19(39
40
FERC FORM NO.1 (ED.12-95)Page 427.2
Name of Respondent
Avista Corporation
lnts Keoon IS:(1) fien Originat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
04t',t112014
Year/Period of Report
End of 20131Q4
SUBSTATIONS
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. lndicate 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).
-tne
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Noxon Trans. Attended 230.0c 13.8(
2
3 STATE OF OREGON
4 Coyote Springs ll Trans. Attended 500.0(13.8(18.0C
5
b SUMMARY:
7 Washington:
8 4 subs Trans. Unattended
9 75 subs Distr, Unattended
10 1 subs Tran & Dist Unattnd
11 7 subs Trans. Attended
12 ldaho:
13 3 subs Trans. Unattended
14 48 subs Distr. Unattended
15 4 subs Tran & Dist Unattnd
16 3 subs Trans. Aftended
17 Montana: '1 sub Trans. Attended
18 1 sub Distr. Unattended
19 Oregon: 1 sub Trans. Unattended
20 System: 148 subs
21
22
23
24
25
26
27
28
29
3o
31
32
33
34
35
36
37
38
39
40
FERC FORM NO.1 (ED.12-96)Page 426.3
Name of Respondent
Avista Corporation
lnrs Keoon Is:(1) []nn orisinat(2) l-lA Resubmission
Date of Report(Mo, Da, Yr)
o4t't1120't4
Year/Period of Report
End of 20131Q4
SUBS:ATIONS (Continued)
5. Show in columns (l), O, 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.
Capacity of Substation
(ln Service) (ln MVa)
(fl
NumDer oI
Transformers
ln Service
(o)
NUmber ol
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)(k)
435 c 1 Two Stage Far 634 1
2
3
213 1 Two Stage far 2EE 4
5
6
7
85C 8
1184 I
53€'10
257 1
12
400 13
668 14
1 160 15
430 16
435 17
5 1E
z',t3 19
61 38 ZO
21
22
23
?4
25
26
27
28
29
30
31
32
33
34
35
36
3l
38
39
40
FERC FORM NO.1 (ED.12-96)Page 427.3
Name of Respondent
Avista Corporation
This Reoort ls:(1) fiRn Original(2) nA Resubmission
Date of Report(Mo, Da, Yr)
o4t11t2014
Year/Period of Report
End of 20131Q4
TRANSACTTONS WITH ASSOCTATED (AFFTLTATED) COMPANTES
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 sbrvice 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.
Line
No.Description of the Non-Power Good or Service
(a)
Name of
Associated/Affi I iated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
2 NONE
3
4
5
6
7
8
I
10
't1
12
13
14
15
16
17
18
19
21 NONE
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)
FERC FORM NO. 1-F (New)
Page
Avu-e
Avista Corp.
2013
IDAHO
State Electric Annual Report
(rc 61-405)
s-lNh
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Report is:
JFI Rn orisinat
I n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Report
End of 2013 lA4
STATEMENT OF UTILTTY OPERATING INCOME.IDAHO
lnstructions
1. For each account below, report the amount attributable to the state of ldaho based on ldaho iurisdictional Results of Operations.
2. Provide any necessary important notes regarding this statement of utility operating income in a footnote in the available space at the bottom of this page
Lin€
No Account
(a)
Refer to
Fom 1
Page
(b)
TOTAL SYSTEM. IDAHO
Current Year
(c)
Prior Year
(d)
1 UTILITY OPERATING INCOME
2 Coeratino Revenues (400)30G.301 455.520.663 450.171.O70
3 Coeratino Exoenses
4 Cperation Exoenses (401 32U323 295 611 027 313 684 985
5 Maintenance ExDenses (402)320-323 19.652.814 20.099.052
6 DeDreciation ExDense (403)336-337 34.901.456 33.505.585
7 Depreciation Expense for Asset Retirement Costs (403.1 336-337IAm^rti7.fi^n L Flenlafinn nf I ltilitv trhnt /1fl2-1n5\336-337 3 303/23 3.047.756
I Amortization of Utilitv Plant Acouisition Adiustment (406)336-337 67.304 67.304
10 Amort. of ProDertv Losses. Unre@v Plant and Reoulatorv Studv Costs (407)
11 Amortization of Conversion Expenses (407)
12 Reoulatorv Debits (407.3)5.300.546 1.870.742\
13 lLess) Requlatorv Credits (407.4)(4.551.546'(5.824.027\
14 Taxes Other Than lncome Taxes (408.1 262-263 16.302.615 14,639,363
15 nmme Taxes - Federal (409.1 262-263 13,022,062 6 730 137
16 - Other (409.1 262-263
17 Provrsron for Deferred lncome Taxes (410.1 234.272-277 8.580.886 10.655.054
18 lless) Provision for Deferred lncome Taxes-Ct. (411.1 234.272-277
'19 lnvestment Tax Credit Adiustment - Net (41 1 4)266 (85 270'(85.353)
20 lLess) Gains from Disoosition of Utilitv Plant (41 1.6)
21 Losses from Disoosition Of Ljtilitv Plenl (411 7\
22 'Less) Gains from Disoosition of Allowances (411 8)
23 Losses from Disposition of Allowances (41 1 .9)
24 qccretion Exoense U11.10\
25 TOTAL Utilitv Ooeratino Exoenses (Total of line 4 throuoh 24)392 1 05.31 7 394.649.11A
26 \et Utilitv ODeratino lncome (Total line 2 less 25)63.415.346 s5,521.956
E.lD.1 14-1'15IDAHO STATE ELECTRIC ANNUAL REPORT (lC 61405}
Name of Respondent
Avista Corporation
This Report is:
I Rn originat
[] n Resubmission
Date of Report
mn/dd/Wyy
04-11-20',t4
Year / Period of Report
End of 20'13 lQ4
STATEMENT OF UTILITY OPERATING INCOME .IDAHO
lnstructions
or in a separate schedule.
3. Explain in a footnote if the previous year's figures are different from those reported in prior reports
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY Line
No.Current Year
(e)
Prior Year
(f)
Current Year
(o)
Prior Year
(h)
Current Year
il)
Prior Year
(i)
1
352.695.900 354.298,765 '102,824.763 95,872.305 2
3
216 407 227 237.642.238 79.203.800 76.042.747 4
17.',\12.701 17.657.900 2.540.113 2.441.152 5
29.855.837 28.775.543 5,045,619 4,730.O42 6
7
2 715 242 2.s02.863 588.1 4 1 544.893 8
67.304 67.304 I
0
1
5.300 546 1.870.742',2
(4.551.546',(5.824.027'3
13.593.242 12,291.725 2.709,373 2.347,638 4
9,556,909 6,585,305 3 465 153 144.832 5
6
8.265.280 8.217.502 315.606 2.437.552 7
8
(69.274 (68,6251 1 5 9961 ('t6,728 I
20
21
22
23
24
298.253.508 305.976.986 93.851.809 88.672.128 25
54.442.392 48.321.779 8.972.954 7.200.177 26
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61405)E.lD.1 14-1 1s
Name of Respondent
Avista Corporation
This Report is:
I Rn originat
I n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Report
End of 2013 I 04
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION. AMORTIZATION AND DEPLETION.IDAHO
lnstructions
1 . Report below the original cost of utility plant in service necessary to furnish utility service to customers in the state of ldaho, and the
accumulated provisions for depreciation, amortization, and depletion attributable to that plant rn service.
2. Report in column (c) the amount for electric function, in column (d) the amount for gas function, in columns (e), (0, and (g) report other (specify),
Line
No Account
(a)
Total Company
End of Current Year
(b)
Electric
(c)
1 LJtility Plant
2 ln Service
2 Plant in Service (Classified)1 383 5'13.433 1 118373 119
4 rropertv Under CaDital Leases 332.598
5 Plant Purchased or Sold
6 30moleted Construction not Classified
7 xperimental Plant Unclassified
8 Total (Total lines 3 throrroh 7)1.383.846.032 I .1 1 8.373.1 1 I
q -eased to Others
'10 -{eld for Future Use 389 592 1 99 007
1 lonstruction Work in Proqress 53.1 64.926 34.972 117
12 qcquisition Adiustments
'13 Total Utilitv Plant (Total lines 8 throuoh 12)1.437 .400.549 1.153.544.243
14 qccumulated Provision for DeDreciation. Amortization. and Deoletion 497 092 365 411 617 433
l5 \et Utility Plant (Line 13 less line 14)940 308.184 741.926.810
16 )etail of Accumulated Provision for Depreciation, Amortization, and Depletion
17 n Service
18 )enreciation 487.534.528 408 629.637
19 \mortization and Depletion of Producino Natural Gas Lands / Land Riohts
20 \mortization of Underoround Storaoe Lands / Land Riohts
21 \mortization of Other Utilitv Plant I 557 838 2 947 796
22 Total (Total lines'lS lhrouoh 21)497.092,365 411.617 .433
23 -eased to Others
?4 )enreciatior
25 \mortizalion and Denletion
zo fotal Leased to Others
27 leld for Future Use
28 )epreciation
29 \mortization
30 Total Held for Future Use
31 Abandonment of Leases (Natural Gas)
32 Amortization of Plant Acorrisition Adirslment
33 Total Accumulated Provision (Total lines 22.26. 30. 31.32\497,092,365 411 617 433
(1) A small portion of the Company's electric distribution plant is located in Montana. For jurisdictional reporting purposes, those amounts are
included as ldaho plant.
IDAHO STATE ELECTRIC ANNUAL REPORT (lC 61.405)E.tD.200-201
Name of Respondent
Avista Corporation
This Report is:
I Rn originat
I n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Report
End of 2013 I Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION .IDAHO
lnstructions
and in column (h) common function.
3. ln order to accurately reflect utility plant in service necessary to furnish utility service to customers in the state of ldaho, electric and gas
plant not directly assigned is allocated to the state of ldaho as appropriate and included in column (c) and (d).
Gas
(d)
Other (Specify)
(e)
Other (Specify)
(f)
Other (Specify)
(o)
Common
(h)
Line
No.
2
182.785.848 82,354.467 3
273.693 58 905 4
5
6
7
183.059.540 82.413.372 I
I
1 90 585 10
2.037.639 1 6.1 55. 1 70 11
12
185 287 764 98.568.542 13
62.108.4s3 23.366.480 14
123.179.312 75.202.062 15
16
17
61.747.525 17.157 .365 18
19
20
360,927 6 209 114 21
62.1 08.453 23.366.480 22
23
24
25
t6
27
28
29
30
31
32
62 1 08 453 23.355.480 33
|DAHO STATE ELECTRTC ANNUAL REPORT (tC 61.405)E.1D.20G.201
Name of Respondent
Avista Corporation
This Report is:
I nn originat
[] n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Report
End of 2013 I Q4
ELECTRIC PLANT lN SERVICE - IDAHO (Account 1O1.1O2.103 and {06)
lnstructions
1 . Report below the original cost of electric plant in service necessary to furnish electric utility service to customers in the state of ldaho.
lnclude electric plant not directly assigned as allocated to the state of ldaho.
2. ln 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',l06, Completed Construction Not Classified-Electric.
3. lncludeincolumn(c)or(d),asappropriate,correctionsofadditionsandretirementsforthecurrentorprecedingyear.
4. For revisions to the amount of initial asset retirement costs capitalized, include by primary plant account increases in column (c), additions, and
reductions in column (e), adjustments.
5. Enclose in parentheses credit ad.Justments of plant accounts to indicate the negative effect of such amounts.
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 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. lnclude also in column (d) distributions of
Line
No.Account
(a)
Balance
Beginning of Year
(b)
Additions
(c)
1 1 INTANGIBLE PLANT
2 301 Oroanization
3 302 Franchises and Consents 1s.412.821
4 303 MiscellaneouslntanqiblePlant 968,1 80 143 665
5 TOTAL lntanoible Plant (Total of lines 2 3 and 4)15 381 001 143 665
6 2. PRODUCTION PLANT
7 A. Steam Production PlantI310 Land and Land Riohts 1 2?O 556
I 31 t Structures and lmorovements 44 164 73',1 437 953
0 312 Boiler Plant Eouioment 59.954.557 948.739
1 313 Enqines and Enoine-Driven Generators 2.369
2 314 Turbooenerator tlnits 18,309,426 441 504
3 315 Accessorv Electric Eouioment I 154 177 150
4 316 Miscellaneous Power Plant Eouioment 5.577.882 146.124
5 317 Asset Retirement Costs for Sleam Production
6 TOTAL Steam Production Plant (Total of lines 8 throuoh 15)138.383.698 1.974.470
7 Nuclear Production Plant
8 320 Land and Land Riohts
o 321 Structures and lmorovements
20 322 Reactor Plant EouiDment
21 323 TurboqeneratorUnits
22 324 Arcessorv Electric Eouioment
23 325 Miscellaneous Power Plant Eouioment
24 326 Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Total of lines 18 throuoh 24)
zb Hvdraulic Production Plant
27 330 Land and Land Riqhts 20.277.O84 2 277
28 331 Structures and lmnrovements 15,489,540 1.379.347
29 332 Reservoirs. Dams and Watenravs 43.434.613 6.019.815
30 333 Water Wheels. Turbines. and Generators 57.049.264 64
31 334 Accessory Electric Equipment 1 1.900.978 42.556
32 335 Miscellaneous Power Plant Eorrioment 2 843 756 1.168.1 25
33 336 Roads. Railroads. and Bridoes 707.063
34 337 Asset Retirement Costs for Hvdraulic Production
35 IOTAL Hydraulic Production Plant (Total of lines 27 throuqh 34)151.702,298 I612.184
36 ). Other Production Plant
37 340 Land and Land Riohts 316.7't 8
38 341 Structllres end lmnrovemEnts 5.801,888 207 232
39 342 Fuel Holders Products andAccessories 7 407 025 1.764
40 343 Prime Movers 8.288.627 )20 g',t1
41 344 Generators 70.491.776 2,226.306
42 345 Accessory Electric Equipment 5,987,488 1 946944
43 346 Miscellaneous Power Plant Eouinment 601 662 I 15.943
44 347 Asset Retirement Costs for Other Production
45 TOTAL Other Production Plant (Total of lines 37 throuoh 44)98,895.1 84 4719 100
46 TOTAL Production Plant (Total of lines 16, 25, 35, and 45)388 981 180 15.305 754
(1) A small portion of the Company's electric distribution plant is located in Montana. For jurisdictional reporting purposes, those amounts are
included as ldaho plant.
IDAHO STATE ELECTRIC ANNUAL REPORT (lC 61.405)E.1o.204-205
Name of Respondent
Avista Corporation
This Report is:
I en originat
I n Resubmission
Date of Report
mm/dd/yyyy
o4-11-2014
Year / Period of Report
End of 2013 lA4
ELECTRIC PLANT IN S ERVICE - IDAHO (Accounl 1O1.1O2.103 and lOG)
lnstructions
these tentative classifications in columns (c) and (d), including the reversals of the prior year's tentative account distributions of these amounts. Careful
observance of these 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. Showincolumn(f)reclassificationsortransferswithinutilityplantaccounts. lncludealsoincolumn(0theadditionsorreductionsof primaryaccount
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 (0 to primary
account classifi cations.
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 account comprising the reported balance and changes in Account 1 02, state the property purchased or sold, name of vendor or purchase, and
dateoftransaction. lfproposedjournal entrieshavebeenfiledasrequiredbytheUniformSystemofAccounts,givealsothedateofsuchfiling.
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance
End of Year
(s)
Line
No.
1
2
fi9.288 15.333.533 t
45.882 1 5 887',1,050,076 4
45.882 (95.175 16 383 609 5
6
7
(5,755 1 ?14 AO1 8
41.909 (203,067'44357 708 9
142 235 Q89.452'60.431 .609 10
't?'2.357 11
215.162 (94, 1 88',18,441,580 12
93,035 I 247 362 13
(28.695 5.695.311 14
15
439.306 (528.134'1 39,390,728 16
17
18
19
20
21
22
23
?4
25
to
8,207 20.287,568 27
40.461 $83.202'16,145,224 2A
76.280 8,624,429'45.753.719 29
(317.809'56.731.519 30
7 248 1.046.446 12.982.732 31
81.123 (7?1 24rJ'3 209 518 32
107,853 814.916 33
34
205.112 a 144 174',1 55,925, '196 35
36
1.629',3 1 5,089 37
23.474 (149,1 661 5,836,480 38
I38 104',7.370 685 39
(186.651 8.322.887 40
5 985 (358.7331 72.353,364 41
655.692 (1 96,804 7 081 936 42
123,301 (74.O74',520.230 43
44
808.452 1,005.161 101 ,800,671 45
1.452.870 5717 469',3S7 'l 16 595 46
IDAHO STATE ELECTRIC ANNUAL REPORT (lC 61.405)E.!D.204-205
Name of Respondent
Avista Corporation
This Report is:
I Rn originat
I n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Report
End of 2013 I Q4
ELECTRIC PLANT lN SERVICE - IDAHO lAccount 1O1- 1O2.103 and 106) (Continuedl
Line
No.Account
(al
Balance
Beginning of Year
(b)
Additions
(c)
47 3. TRANSMISSION PLANT
48 350 Land and Land Riqhts 6.777.719 286.208
49 352 Structures and lmprovements 5.984,820 2 110 451
50 ?6? Sfafi^n Fnr rinmenl 74.606.438 5.462.355
51 354 Towers and Fixtures 5.991.313 566
52 355 Poles and Fixtures 54.163,777 8.300,044
53 356 Overhead Conductors and Devices 40 856.989 3.440.414
54 357 [JnderoroundConduit 911.660
55 358 Underoround Conductors and Devices 815.292 1.288
56 359 Roads and Trails 655,099 77.6',13
57 359 '1 Asset Relirement Costs for Transmission Plant
58 IOTAL Transmission Plant (Total of lines 48 throuoh 57)1 90.763.1 07 19.679.343
59 . DISTRIBUTION PLANT
60 360 Land and Land Riohts 2.945,504 199,769
61 36'1 Structures and lmorovemenls 5 209.636 255.487
62 362 Station Eouioment 37.985.386 1.782.976
63 363 Storaoe Batterv Eouioment
84 364 Poles Towers and Fixhrres 99,53s,026 6.144.443
65 365 Overhead Conductors and Devices 55.798.625 3.593.142
66 366 UnderoroundConduit 31.714.875 1.002.353
67 367 Underoround Conductors and Devices 50 862 518 3 945 241
68 368 Line Transformers 65 106 601 2.302 155
69 369 Services 47 .451.194 '1.556.363
70 370 Meters 21.174.718 16.793
71 371 lnstallations on Customer Premises
72 372 Leased ProDerW on Customer Premises
73 373 Street Liohtino and Sional Svstems 't 4.393.968 612.',t42
74 374 Asset Retirement Costs for Distribution Plant
75 fOTAL Distribution Plant (Total of lines 60 throuoh 74)443.178.051 21.4',t0.864
76 REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 380 Land and Land Riohts
78 381 Structures and lmorovements
79 382 Comouter Hardware
80 383 Computer Software
81 384 CommunicetionEouioment
82 385 Miscellaneous Reoional Transmission and Market ODeration Plant
83 386 Asset Retirement Costs for Reoional Transmission and Ooeration Plant
84 TOTAL Transmission and Market Ooeration Plant (Total lines 77 throuqh 83)
85 ;. GENERAL PLANT
86 389 Land and Land Riohts 369.796
a7 390 Structures and lmorovements 3,297,953 67.197
88 391 Office Furniture and Eouioment 1.863.523 88.978
89 392 Transoortation Eouioment 5.216.350 1.340.317
90 393 Stores EouiDment 136,793
91 394 Tools Sho6 and Garaoe Forrinment s22.859 25.917
92 395 LaboratorvEouioment 303.883 1.956
93 396 Power Ooerated Eouioment 13.348.205 967,296
94 397 CommunicationEouioment 14.737.123 1 662.334
95 398 MiscellaneousEouioment 1 1.608 8.603
96 SUBTOTAL (Total of lines 86 throuoh 95)40.208.1 03 4,1 62.598
97 399 Other Tanoible Prooertv
98 399. 1 Asset Retirement Costs for General Plant
99 TOTAL General Plant (Total of lines 96 97 and 98)40.208.1 03 4.162,598
100 TOTAL (Accounts 101 and 106)1 .O79.511.442 60.702.224
101 102 Electrac Plant Purchased
102 '102 (Less) Electric Plent Sold
103 103 Exoerimental Plant Unclassified
104 IOTAL Electric Plant in Service (Total of lines 100 throuoh '1 03)1 .07 I .51 1 .442 60,702,224
IDAHO STATE ELECTRIC ANNUAL REPORT 0C 61.{0s)E.tD.206-207
Name of Respondent
Avista Corporation
This Report is:
I Rn originat
f] n Resubmission
Date of Report
mm/dd/Wyy
04-11-2014
Year / Period of Report
End of 2013 I Q4
ELECTRIC PLANT lN SERVICE - IDAHO (Account 101. 102. 103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance
End of Year
(o)
Line
No,
47
(165,641)6,898.286 48
1't .817 1.367.671 6,716,183 49
s96 007 Q.605.612 76867 174 50
(30.821 5.961.0s8 51
s53.396 (4.876.027 57,034.398 52
452.532 1.998.876',1 627 41.844,372 53
76.383 988 043 54
(5.034'8l'1.546 55
(53.966 678.746 56
57
1 613 752 11.027 .265 1 627 197 799 806 58
59
3.145.273 60
11.654 1 5,453.468 61
194 407 67 850 39 637 805 b2
63
631.925 (4 105.047.540 64
't 7 5091 69,409,276 65
(31 8781 32749 106 66
120.372 I 54.687 388 67
33.500 68.375.256 68
(7,638 1 49,0'15,196 69
22 255 983 21 447 472 70
71
72
42 6,50.2 14.963.462 73
74
981.505 67.849 255.983 463.931.242 75
76
77
7A
79
80
81
a2
83
84
85
( 155 369.541 86
9.611 (24,692 3.330.847 87
111.326 (37 932\1,803.243 88
188.524 (44 583 6,323,560 89
(2.503 134 290 90
78.O97 (1 1.660 859.029 91
77.832 (4,562 223.445 92
221 r]55 (62.709 14 031 737 93
183.642 fi62.796 (6.967 16.046.052 94
3 185 20.023 95
870 090 (351.777 (6 967',43 141 467 96
s7
98
870.090 (351.777 (6.967 43.141.867 99
4.964 099 17.123.837 247 389 1 'l 18373 119 '100
101
102
103
4.964.099 17.123.837 247.389 1.1 '18 373.1 19 104
IDAHO STATE ELECTRTC ANNUAL REPORT (tC 6,t405)
Name of Respondent
Avista Corporation
This Report is:
I Rn originat
I n Resubmission
Date of Report
mm/dd/yyyy
o4-11-2014
Year / Period of Report
End of 2013 lA4
ELECTRIC OPERATING REVENUES - IDAHO
lnstructions
1. Report below operating revenues attributable to the state of ldaho for each prescribed account in accordance with jurisdictional Results of
Operations. Report the portion of total operating revenue and megawatt hours which pertains to unbilled revenue and MWH pertaining unbilled
revenue in the lines provided.
2. Report number of customers (columns (0 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.
3. lf increases or decreases from previous period (columns (c), (e), and (g)) are not derived from previously reported figures, explain any inconsistencies
in a footnote in the available space atthe bottom ofthe page, or in a separate schedule.
Line
No.Account
(a)
ELECTRIC OPERA'rING REVENUE
Current Year
(b)
Prior Year
(c)
1 Sales of Electricitv
2 440 Residential Sales 106.574.267 102,933.167
3 442 Commercial and lndustrial Sales (3)
A Small (or Commercial)84.339.477 84.744.247
5 Laroe (or lndustrial)54.113.135 63,1 50.34 1
6 444 Public Street and Hiohwav Liqhtino 2.386.168 2.440.129
7 445 Other Sales to Public Authorities
8 446 Sales to Railroads and Railwavs
I 448 lnterdeDartmentalSales 220.366 209.881
'10 TOTAL Sales to Ultimate Customers 247.633,413 253 477 765
11 447 Sales for Resale 49 914.256 51.786.744
1?TOTAL Sales of Electricitv 297.547.669 305.264.509
13 449 'l (Less) Provision for Rate Refunris Q.047.837
14 TOTAL Revenues Net of Provision for Refunds 29s 499 832 305.264 509
15 Other Ooeratino Revenues
16 450 ForfeitedDrscounts
17 451 MiscellaneousService Revenlres 220.851 201,468
18 453 Sales of Water and Water Power 150.495 164.033
19 454 Rent from Electric Propertv 990.611 989.469
20 455 lnterdeoartmental Rents
21 456 Other Electric Revenues '4\ 46.948.922 43.608.408
2?456.1 Revenues from Transmission of Electricitv for Others 8.885.189 4.070.878
23 457.1 Reoional Control Servic€ Revenues
24 457.2 Miscellaneous Revenues
25
2b TOTAL Other ODeratino Revenues 57.1 96.068 49,034,256
27 TOTAL Electric ODeratino Revenues 352 695 900 354.298.765
E.tD.30G301IDAHO STATE ELECTRIC ANNUAL REPORT 0C 61.f05)
Name of Respondent
Avista Corporation
This Report is:
I nn originat
I n Resubmission
Date of Report
mn/dd/yyyy
04-1 1-2014
Year / Period of Report
End of 2013 I Q4
ELECTRIC OPERATING REVENUES . IDAHO
lnstructions
4. Disclose amounts of $250,000 or greater in a footnote at the bottom of the page or in a separate schedule for accounts 451 , 456, and 457 .2.
5. Commercial and lndustrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or lndustrial)
regularlyusedbytherespondentifsuchbasisofclassificationisnotgenerallygreaterthanl000Kwofdemand. (SeeAccount442oftheUniform
System of Accounts. Explain basis of classification in a footnote.)
6. See pages 108-109 in the FERC Form 1, lmportant Changes During Period, for important new territory added and important rate increases or
decreases.
7. lncludeunmeteredsales. Providedetailsof suchSalesinafootnoteintheavailablespaceatthebottomofthispageorinaseparateschedule.
MEGAWATT HOURS SOLD AVG. NO. OF CUSTOMERS PER MONTH Line
No.Current Year
(d)
Previous Year
(e)
Current Year
(f)
Previous Year
(q)
1
1.205.554 1.165.138 107.458 106.528 2
3
1 001 750 996.974 16.830 16 7?7 4
1.O18.417 'I 185 320 454 468 5
9.083 9.061 147 143 o
7
8
2.535 2,396 44 44 I(2) 3.237.349 3.3s8.889 124.933 123.910 10
1,543,355 1 .971.476 11
4 780 704 5,330.365 124.933 123,910 12
13
4.780,704 5.330.365 124.933 123.910 14
(1) lncludes $ (199,639) ofunbilled revenues.
(2) lncludes (6,463) MWH relating to unbilled revenues.
(3) Segregation of Commercial and lndustrial made on basis of utiltzation of energy and not on size of account.
(4) lncludes $ 43,473 associated with a special contract for wheeling over the distribution system on file with the IPUC, recorded
in sub-account 455700
rDAHO STATE ELECTRTC ANNUAL REPORT (rC 61.005)E.tD.300-301
Name of Respondent
Avista Corporation
This Report is:
I nn originat
! n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Reporl
End of 2013 I Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES. IDAHO
lnstructions
1. For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state ol
ldaho.
2. lf the amount for previous year is not derived from previously reported figures, explain in a footnote.
Lin€
No.Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
1 1. POWER PRODUCTION EXPENSES
2 A Sieem Power Generation
3
4 500 Ooeration Suoervision and Enoineerino 98.144 142.008
6 501 Fuel 8,623,310 9,784,98'l
6 502 Steam Expenses 1 461 392 1 402073
7 503 Steam from Other Sources
a 504 (Less) Steam Transferred-Cr.
9 505 Electric Exoenses 354,306 316 246
10 506 Miscellaneous Steam Power Expenses 1 003 191 828 089
11 507 Rents 11.520 7.669
12 509 Allowances
13 IOTAL Operation (Total of lines 4 throuoh 12)1 551 863 12 441 066
14 Mainl
15 510 Maintenance Suoervision and Enoineerino 1 59.326 173.851
16 511 Maintenance of Structures 236.976 212.438
17 512 Maintenance of Boiler Plant 2 123 742 1 695 417
18 513 Meintenance of Electric Plant 408.233 204.416
.,t o 514 Maintenance of Miscellaneous Steam Plant 278.255 197,743
20 TOTAL Maintenance (Total of Lines 15 throuqh 19)3.206.532 2 483 86s
21 TOTAL Steam Power Generation Exoenses (Total lines 13 & 20')14 758.395 14.964.93'l
22 B. Nuclear Power Generation
23 peration
24 517 Ooeration Suoervision and Enoineerino
25 518 Fuel
519 Coolants and Water
27 520 Steam Exoenses
28 521 Steam from Other Sources
29 522 (Less) Steam Transferred-Cr.
30 523 Electric Expenses
31 524 Miscellaneous Nuclear Power Exoenses
32 525 Rents
33 IOTAL Operation (Total of lines 24 throuoh 32)
34 Mainlenano.e
35 528 Maintenance Suoervision and Enoineerino
35 529 Maintenance of Structures
37 530 Maintenance of Reactor Plant Eorrinment
38 53'1 Maintenance of Electric Plant
39 532 Maintenance of Miscellaneous Nuclear Plant
40 IOTAL Maintenance (Total of lines 35 throuoh 39)
41 IOTAL Nuclear Power Generation Exoenses (Total lines 33 & 40)
42 Hvdraulic Power Generation
43 Jperation
44 535 Ooeration Suoervision and Fnoineerino 664,505 840.868
45 536 Water for Power 453.746 411.845
46 537 Hvdraulic Exoenses 2.637 .771 2.767.437
47 538 Electric Expenses 2.312.953 2 204.138
48 539 Miscellaneous Hvdraulic Power Generation Exoenses 249.248 217.048
49 540 Rents 2.392.794 2.370.453
50 IOTAL Operation (Total of lines 44 throuoh 49)8.711 .O17 8811789
51 Maintenance
52 541 Maintenance Suoervision and Enoineerino 191 181 204.061
53 542 Maintenance of Structures 341.117 212,090
54 543 Maintenance of Reservoirs. Dams. and Waterwavs 620,243 474 378
55 544 Maintenance of Electric Plani 1.447.324 981.380
56 545 Marntenance of Miscellaneous Hvdraulic Plant 201.261 169.793
57 IOTAL Maintenance (Total of lines 53 throuoh 57)2,801,126 2 041 702
58 IOTAL Hydraulic Power Generation Expenses (Total of lines 50 & 58)11 5',t2 143 10.853.491
59
IDAHO STATE ELECTRIC ANNUAL REPORT (lC 51.405)E.tD.320
Name of Respondent
Avista Corporation
This Report is:
I Rn originat
! n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Report
End of 2013 I Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES. IDAHO
lnstr
1.
2.
uctions
For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
ldaho.
lf the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
60 l. Other Power Generation
61 )peration
62 6dA f)npralinn Sr r^a^rici^n en.{ Fhdineerind 485 451 451 338
63 547 Fuel 38.4s'1.938 22 412.775
64 548 GenerationExoenses 747.321 592.556
65 549 Miscellaneous Other Power Generation Expenses 161,154 216.690
65 550 Rents (9 443 17 723
67 fOTAL ODeration (Total of lines 62 throuoh 66)39.836.421 23.691.082
68 Vlaintenance
69 551 Maintenance Suoervision and Enqineerinq 376.059 653.278
70 552 Maintenance of Structures 17,745 4 343
71 553 Maintenance of Generatino and Electric Plant 634 353 2696 525
72 554 Maintenance of Miscellaneous Other Power Generation Plant 63.606 56.407
73 TOTAL Maintenance (Total of lines 69 throuqh 72)1,151,763 3.410.553
74 I-OTAL Other Power Generation Expenses 40 988 '184 27,101.635
75 Other Power SuoDlv Exoenses
76 555 Purchased Power 77.616.282 95.516.653
77 556 System Control and Load Dispatchinq 336.252 302.502
7A 557 Other Exoenses 35 958 358 50 030 562
79 IOTAL Other Power Suoolv Exo€nses (Total of llnes 76 throuoh 78)113.9't0.892 145.849.817
80 TOTAL Power Production Exoenses (Total of lines 21. 4'1.59.74. &79\18t.t69.6t4 1 98.769.874
81 . TRANSMISSION EXPENSES
82 Onar.li6n
83 560 ODeration Suoervision and Enoineerino 862.10'l 757.626
84 561 Load Disoatchino 845.373 753.317
85 561 1 Load Disoatch-Reliabilitv
86 561 .2 Load DisDatch-Monitor and Ooeration Transmission Svstem
87 561.3 Load Disoatch-Transmission Service and Schedulino
88 561.4 Schedulino. Svstem Control and DisDatch Services
89 561.5 Reliabilrty, Plannanq and Standards Development
90 561.6 Transmission Service Studies
91 561.7 Generation lnterconnection Studies
92 561.8 Reliabilitv. Plannino and Standards Development Services
93 562 Station Expenses '159 405 146,840
94 563 Overhead Lines Exoenses 142 434 164 079
95 564 Underoround Lines ExDenses
96 565 Transmission of Electricitv bv Others 6.240.354 6.'t41.310
97 566 MiscellaneousTrensmission Exoenses 685,564 625,372
98 567 Rents 35 445 40 562
99 I-OTAL Ooeration (Total of lines 83 throuoh 98)9.01 1.076 8.629.'106
100 Maintenance
101 568 Maintenance Suoervision and Enqineerinq 380.611 743 120
102 569 Maintenance of Structures 129.271 155.654
103 569.1 Maintenance of Computer Hardware
104 569.2 Maintenance of Computer Software
't 05 569.3 Maintenance of Communication Eouioment
106 569.4 Maintenance of Miscellaneous Reoional Transmission Plant
107 570 Maintenanm of Station Forrioment 471.096 393,877
108 57'l Maintenance of Overhead Lines 513 471 626.O44
'109 572 Maintenance of Underoround Lines 7.368 2.931
110 573 Maintenance of Miscellaneous Transmissaon Plant 17.070 32.843
111 TOTAL MaintenancE (Total of lines 101 throuoh 110)I 518 887 1 955 469
112 TOTAL Transmission Exoenses (Total of lines 99 and 111 I O.529.963 10.584.575
IDAHO STATE ELEGTRIC ANNUAL REPORT (IC 61405)E.tD.321
Name of Respondent
Avista Corporation
This Report is:
I nn originat
f] n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Report
End of 2013 I Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
lnstructions
1. For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
ldaho.
2. lf the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
113 ]. REGIONAL MARKET EXPENSES
114 Jperation
115 575 1 ODeration Suoervision
116 575.2 Dav-Ahead and Real-Time Market Facilitation
117 575.3 Transmission Riohts Market Facilitation
118 575.4 Caoacitv Market Facalitation
'l 19 575.5 Ancillary Services Market Facilitation
120 575.6 Market Monitorino and Comoliance
121 575.7 Market Facilitation, Monitorino. and Comoliance Services
122 575.8 Rents
123 Total Ooeration (Total lines 115 throuoh 122)
124 \ilainlenanee
125 576.1 Maintenance of Structures and lmorovements
126 576.2 Maintenance of Computer Hardware
127 576.3 Maintenance of ComDuter Software
128 576.4 Maintenance of Communication Eouipment
129 576.5 Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenanc€ (Total lines 125 throrroh 129)
13'l IOTAL Reoional Market ExDenses (Total lines 123 & 130)
132 DISTRIBUTION EXPENSES
133 )peration
134 580 Operation Supervision and Enoineerino 854,796 754.053
135 581 Load Disoatchino
136 582 Station Expenses 271 943 254 492
137 583 Overhead Line Exoenses 937.791 894.238
138 584 Underoround Line Exoenses 480.809 447 )49
39 585 Street Liohtino and Sional Svstem ExDenses a4 172 134 544
40 586 Meter Exoenses 509.905 51 't.301
4 587 CustomerlnstallationsExoenses 316.946 302.094
4?588 MiscellaneousExoenses 2,1'13,806 2,625,200
43 589 Rents 56 128 120.791
44 I-OTAL Ooeration (Total of lines 1 34 throuoh 143)5.626.296 6.047.962
45 Maintenance
46 590 Maintenance Supervision and Enoineerinq 566,556 597 528
47 591 Maintenance of Structures 149.489 203.685
48 592 Maintenance of Station Eouioment 321.925 250,486
4g 593 Maintenance of Overhead Lines 3 324 776 2 974 733
50 594 Maintenance of [Jnderoround Lines 412 756 368.272
51 595 Maintenance of Line Transformers 202.927 247.084
52 596 Maintenance of Street Liohtino and Sional Svstems 254.600 218,118
53 597 Maintenance of Meters 17 181 24.769
54 598 Maintenance of Miscellaneous Distribution Planl 1 16.900 120,960
55 TOTAL Maintenance (Total lines 146 throuoh 154)5.367.1 1 0 5.005,635
56 TOTAL Distribution Expenses (Total of lines 144 and 1 55)10,993,406 1 1 053 597
57 5, CUSTOMER ACCOUNTS EXPENSES
58 Oncrrtinn
59 9Ol Sr rneruision 121.640 198,872
60 902 Meter Readinq Expenses 419 222 402.147
61 903 Customer Records and Collection Exoenses 3.051.598 2.801.378
62 904 UncollectableAccounts 871.409 732.862
o.,905 Miscellaneous Customer Acrounts Expenses 81,672 78 962
64 TOTAL Customer Accounts Exoenses (Totel of line 1 59 throrroh 163)4 545 541 4.214.221
|DAHO STATE ELECTRTC ANNUAL REPORT (tC 61405)E.lD.322
Name of Respondent
Avista Corporation
This Report is:
I Rn originat
I n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Report
End of 2013 lA4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES . IDAHO
lnstructions
1. For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
ldaho.
2. lf the amount for previous year is not derived from previously reported figures, explain in a footnote.
Lin(
No.Account
(a)
Amount for
Current Year
(b)
Amount for
Prevlous Year
(c)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 907 Suoervision
168 908 Customer Assistance Exoenses 4.861.767 6 830 135
't 69 909 lnformational and lnstructional Expenses 358.445 390.1 20
174 9'10 Miscellaneous Customer Service and lnformational Expenses 69.078 60.645
171 TOTAL Customer Service and lnformational Exoenses (Total lines 167 throuoh 170)5.289.290 7.280.901
172 7. SALES EXPENSES
17 Cperation
174 911 Suoervision
175 912 Demonstratino and Sellino Exoenses 2,544 2.735
176 913 Advertisino Exoenses
177 916 Miscellaneous Sales Exoenses
178 TOTAL Sales Exoenses (Total of lines lT4lhrouoh 177 2.544 2.735
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 )oeration
18'1 920 Administrative and General Salaries 8.O47.127 10 290.220
142 921 Office Supplies and Exoenses 1.271.569 1.342.667
183 922 (Less) Administrative Exoenses Transferred-Credit (32.987',,e1.716\
184 923 Outside Services Emoloved 3 369 654 3 835 186
185 924 Propertv lnsurance 468.381 437.430
186 925 lniuries and Demades 993.770 795.256
187 926 Emolovee Pensions and Benefits 392.701 426.919
188 927 FranchiseReouirements 5.747 5 747
189 928 Requlatory Commission Exoenses 2.102.155 2.101 .988
190 929 (Less) Duolicate Charoes-Cr
191 930. 1 General Advertisino Exoenses
't92 930.2 Miscellaneous General Exoenses 1.004.708 1 080 2s1
93 931 Rents 299.462 339.6'l 1
94 IOTAL Ooeration {Totel of lines 181 throuoh 193)17.922.287 20,633.559
95 Vlaintenance
96 935 Maintenance of General Plant 3,067,283 2,760,676
97 TOTAL Administrative and General Exoenses (Total of lines 194 and '196)20,989,570 23.394.235
98 TOTAL Elec Op and Maint Expns (Total lines 80, 1 12. 131, 1 56,'164, 17 1. 178. 197 233,5 1 9,928 255,300,1 38
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61405)
Name of Respondent
Avista Corporation
This Report is:
I Rn originat
I n Resubmission
Date of Report
mm/dd/yyyy
o4-11-2014
Year / Period of Report
Endof 2013/Q4
TRANSMISSION LINE STATISTICS . IDAHO
lnstructions
'1. Report information concerning transmission lines physically located in the state of ldaho, including the cost of lines, and expenses for the
year. List each transmission line having nominal voltage of 132 kilovolts or greater.
Transmission lines below this voltage should be grouped and totals reported for each group.
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 the State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 1 2"1 , Nonutility Property.
5. lndicate 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. lf 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 (0 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 mst of which is reported for another line. Report
pole miles of line on leased or partly-owned structures in column (g). ln a footnote in the available space at the bottom of this page or in a separate
Line
No.
DESIGNATION
VOLTAGE (KV)
lndicate where other than
An.v.b a ^h^<a
Type of
Supporting
Structure
(e)
LENGTH (Pole Miles)
For undemround lines, reDort citcuit miles Number
of
Circuits
(h)
On Structure
of Line Designated
(0
On Structures
of Another Line
G)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
1 3rouo Sum - 11skv 115 00 115.00 609 00
2
3 leacon labinet Goroe Plant 230.00 230.00 Steel Pole 9.00 1
4 Jeacon labinet Goroe Plant 230.00 230.00 Steel P 500
5 Jeacrn iahinat Garac Planf 230.00 230 00 H Tvoe 53.00 1
6 )ivide Creek -olo Sub 230.00 230.00 Steel Tower 1
7 )ivide Creek -olo Sub 230.00 230.00 H Tvoe 43.00 1
8 {oxon Plant )ine Creek Sub 230 00 230 00 H Tvne 15 00 1
I {oxon Plant )ine Creek Sub 230.00 230.00 Steel Pole 15.00 1
10 ;abinet Goroe Plant \,loxon 230.00 230.00 H Tvoe 2.00 1
11 lenewah Sw. Station )ine Creek Sub 230 00 230 00 Tower 1
12 Jenewah Sw. Station )ine Creek Sub 230.00 230.00 H Tvoe 43.00 ,|
't3 Jeacon Sub -olo Sub 230.00 230.00 H Tvoe 81 00 1
't4 {orth Lewiston r1/alla Walla 230 00 230.00 H Tvoe 800 1
15 {orth Lewiston ihawnee 230.00 230.00 H Tvoe 1.00 I
16 latwai tl. Lewiston Sub 230.00 230.00 H Tvoe 7.00 1
17
18
19
20
21
22
23
24
25
2b
27
28
29
30
31
32
33
34
35
36
E.!D.422-423IDAHO STATE ELECTRTC ANNUAL REPORT (tC 61405)
Name of Respondent
Avista Corporation
This Report is:
[l Rn orisinat
f] n Resubmission
Date of Report
mm/dd/yyyy
04-11-2014
Year / Period of Report
End of 2013 I Q4
I l<ANsillTlilittlN LtNh !i I A I lS I t(;S - ILIAHI'
lnstructions
schedule, explain the basis ofsuch occupancy and state whetherthese expenseswith respectto such structures are included in the expenses reported
for the line designated.
7. Oo 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 have include lower-voltage lines with higher-voltage lines. lf two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (0 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. lf 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 details of such matters as percent ownership by respondent in the line, name of oowner, basis of sharing expenses of the line, and and how
expenses borne by the respondent are accounts for, and accounts affected. Specify whether lessor, @-owner, or other party is an associated company.
9. Designate any kansmission 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) through (l) on the book cost at end of year associated with the physical lines reported.
Size of
Conductor
and Material
(i)
COST OF LINE
lnclude in @lumn 0 land, land rights, and cleaing ightaf-way
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
(i)
Construction
and Other Costs
(k)
Total Cost
fl\
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses
(p)
4.223 281 58.054.131 62.277.412 58.626 542.878 60't.504 1
2
1590 ACSS 3
1590 ACSS 4
1590 ACSR 1.O42 786 20.791.309 2't.834.095 642 1 1.603 12.246 5
1272McMAL 6
1?72 MaMAI 86.228 4.488,642 4 574 870 2 921 58 588 61 s09 7
954 McMAL I
1272 ACSR 692.A47 1 1.014.809 1 't.707.656 't.94s 252.996 254.941 9
954 McMAL 138.010 460.204 598.214 282 892 1.174 0
954 MCMAL 1
954 McMAL 320,360 2 61 1.383 2.93',t.743 35.570 8.843 45.414 2
1272McMAL 363 604 7.096.773 7.460.377 864 2.O32 2.896 3
1272McMAl 25.818 1.321.341 1.347 .159 297 563 861 4
1272 ACSR 10.015 319,300 329 31 5 48 48 5
159O ACSR 106 581 2.600.738 2.707.319 2.172 2.172 6
7
8I
20
21
2?
23
24
25
26
27
28
29
30
31
32
33
34
35
36
IDAHO STATE ELECTRTC ANNUAL REPORT (tC 61405)E.lD.422-423
This Page Intentionally Left Blank