2016Annual Report.pdf

THIS FILING IS
Item 1: EI An lnitial(Original)
Submission
OR E Resubmission No. _
i l,:i-ll:lVi:D
.tirri ',:',1 27 f ll l0t -t2
Form 1 Approved
OMB No.1902-0021
(Expires 1213112019)
Form 1-F Approved
OMB No.1902-0029
(Expires 1213112019)
Form 3-Q Approved
OMB No.'1902-0205
(Expires 1213112019)
4Vu-E
,l!-r-luli
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 under the Federal Power Act, Seclions 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 Legal Name of Respondent (Company)
Avista Corporation
Year/Period of Report
End of 20161Q4
FERC FORM No.1/3-Q (REV.0244)
FERC FORM NO. 1/3-Q:
IDENTIFICATION
01 Exact Legal Name ofRespondent
Avista Corporation
02 Year/Period of Report
End of 2O16lQ4
03 Previous Name and Date of Change (if name changed during year)
ll
04 Address of Principal Office at End of Period (Sfreel City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
06 Title of Contact Person
VP, Controller, Prin. Acctg
05 Name of Contact Person
Ryan L. Krasselt
07 Address of Contact Person (Stme( CiU, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
10 Date of Report
(Mo, Da, Yr)
03t31t2017
08 Telephone of Contact Person,lncluding
Arca Code
(s09) 49s-2273
09 This Report ls
(1) ffi An Original (2) n A Resubmission
ANNUAL CORPORATE OFFICER CERIIFICATION
The undersigned ofiicer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in lhis report are conect statements
of the business affairs of the respondent and the financial statements, and other linancial information contained in this report, conform in all material
respects to the Uniform System ofAccounts.
01 Name
Ryan L. Krasselt
02 Title
VP, Controller, Prin. Accto Ofiicer
SigpAture
V"*
Qvrn
t *r"r*S*
L. Krasselt
03
0313112017
04 Date Signed
(Mo, Da, Yr)
Title 18, U.S.C. 1001 makes it a crime for any person to knowingly and willingly to make to any Agency or Departmenl of the United States any
false, tictitious or fraudulenl stalements as to any matter within its jurisdiction.
FERC FORM No.113-Q (REV.02-04)Page I
Avista Corporation
(1)
(2\
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03R1t2017
Year/Period of Report
End of 20161Q4
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 101
2 Control Over Respondent 102 N/A
3 Corporations Controlled by Respondent 103
4 Officers 1M
5 Directors 105
b lnformation on Formula Rates 1 06(a)(b)
7 lmportant Changes During the Year 10&109
8 Comparative Balance Sheet 11G.113
9 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
't2 Notes to Financial Statements 122-123
,,1 3 Statement of Accum Comp lncome, Comp lncome, and Hedging Aclivities 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 Construclion Work in Progress-Eleckic 216
20 Accumulated Provision for Depreciation of Electric Utility Plant 219
2'l 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 2y
30 Capital Stock 25U251
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 Deferred lnvestment Tax Credits 266-267
FERC FORM NO.1 (ED.12-96)Page 2
Name
Avista Corporation
(1)
(2)
An
A Resubmission
Date of Report
(Mo, Da, Y0
03t31t2017
Year/Period of Report
End of 2O16tQ4
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)
3t Other Defened Credits 269
38 Accumulated Deferred lncome Taxes-Accelerated Amortization Property 272-273 N/A
39 Accumulated Defened lncome 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 310-31 1
46 Electric Operation and Maintenance Expenses 320-323
47 Purchased Power 326327
48 Transmission of Eleciricity 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 Elec{ric 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
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
61 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 41M11
FERC FORM NO. 1 (ED. 12-96)Page 3
Name of Respondent
Avista Corporation
This(1)
(2)
ReDort ls:
fiRn originat
llA Resubmission
Date of Reoort(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2016/Q4
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 42U27
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 4
Name of Respondent
Avista Corporation
This Report ls:
(1) E An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 2016tQ4
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.
R. Kaasselt, vice President, contaoller, and Principal Accounting Off5,cer
1{11 E. l,lission Avenue
Spokane, l{A 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.
State of washington, Incorporated uarch 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.
Electric service in the states of washington, Idaho, and Montana
Natural gas serwice in the states of wasington, 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{7)PAGE 101
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5l1Rn originat(2) 1-lA Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2016tQ4
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 Avista Capital, lnc.Parent company to the 100
2 Company's subsidiaries.
3
4 Avista Development, lnc.Maintains an investment 't 00 Subsidiary of
5 portfolio of real estate and Avista Capital
6 other investments.
7
8 Avista Energy, lnc.lnactive 100 Subsidiary of
I Avista Capital
10
11 Pentzer Corporation Parent company of Bay Area 100 Subsidiary of
12 Manufacturing and Pentzer Avista Capital
13 Venture Holdings.
14
'15 PentzerVenture Holdings ll, lnc.lnactive 100 Subsidiary of
16 Pentzer Corporation
17
18 Bay Area Manufacturing, lnc.Holding Company 100 Subsidiary of
19 Pentzer Corporation
20
21 Advanced Manufacturing and Development, lnc.Performs custom sheet metal 82.95 Subsidiary of
22 dba Metalfx manufacturing of electronic Bay Area
23 enclosures, parts and systems Manufacturing
24 for the computer, telecom and
25 medical industries. AM&D
26 also has a wood products
27 division.
FERC FORM NO.1 (ED.12-96)Page 103
Name of Respondenl
Avista Corporation
This Reoort ls:(1) fiAn Originat(2) [-lA Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2016/Q4
CORPORATIONS CONIROLLED 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 deflnition 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 Orvned
(c)
Footnote
Ref.
(d)
1
2 Avista Capital ll An affiliated business trust 100 Affliate of
3 formed by lhe Company Avista Corp.
4 lssued Pref. Trust Securities
5
6 Avista Northwest Resources, LLC Formed in 2009 to own 100 Affiliate of
7 an interest in a venture Avista Capital
8 fund investment
I
10 Steam Plant Square, LLC Commercial office and retail 85 Affiliate of
11 leasing.Avista Development
12
13 Courtyard Office Center, LLC Commercial office and relail 100 Affiliate of
't4 leasing.Avista Development
15
16 Steam Plant Brew Pub, LLC Restaurant operations 85 Affiliate of Steam
17 Plant Square, LLC
18
19 Salix Formed in 201 4 lo explore 100 Subsidiary of
20 markets that could be served Avista Capital
21 with Liquefied Natural Gas
22 mostly in Westem N. America
23
24 Alaska Energy and Resources Company (AERC)Parent company of Alaska 100 Subsidiary of
25 operations.Avista Corp
26
27 Alaska Electric Light and Power Company Utility operations based in 100 Subsidiary of
FERC FORM NO.1 (ED.12-96)Page 103.1
Name of S:
Avista Corporation (1)
(2)
Original (Mo, Da,
Resubmission 03t3112017
Year/Period of Report
End of 2016tQ4
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 Orvned
(c)
Footnole
Ref.
(d)
1 the City and Borough of AERC
2 Juneau, AK
3
4 AJT Mining Properties, lnc.lnactive mining company 100 Subsidiary of
5 holding certain properties in AERC
6 the City and Borough of
7 Juneau. AK
8
I Snettisham Electric Company Holds certain rights to 100 Subsidiary of
10 purchase the Snettisham AERC
1'l Hydroelectric project in the
12 City and Borough of
13 Juneau, AK
14
15
16
17
18
19
20
21
22
23
24
25
26
27
FERC FORM NO. 1 (ED. r2-96)Page 103.2
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
103.2 Line No.:
Spokane Energy was dissolved as o Ju v 7
FERC FORM NO.1 (ED. 12ATl Page 450.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]en orisinat(2) nA Resubmission
Date of ReDort(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2016tQ4
OFFICERS
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive office/' 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 poliry 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.
Lrne
No.
Itfle
(a)
Name oT Lrmcer
o)
Satarvfor Yedr(c)
1 Chairman of the Board, President S. L. Morris
2 and Chief Executive Officer
3
4 Senior Mce President, Chief Financial Officer,M. T. Thies
5 and Treasurer
6
7 Sr Vice President, General Counsel, Chief Compliance M. M. Durkin
I Officer, and Corporate Secretary (effective 511612016)
I
10 Senior Vice President and Chief Human Resources Officer,K. S. Feltes
11 (effective 5/16/2016)
12
13 Senior Vice President and Environmental D. P. Vermillion
14 Compliance Officer, President of Avista Utilities
15
16 Senior Mce President, responsible for Energy J. R. Thackston
17 Resources
18
't9 Vice President, Controller, and R. L. Krasselt
20 Principal Accounting fficer
21
22 Vice President, Chief lnformation Officer, and J. M. Kensok
23 Chief Security Officer
24
25 Vice President and Chief Counsel for Regulatory D. J. Meyer
26 and Govemmental Affairs
27
28 Vice President, responsible for State and Federal K. O. Norwood
29 Regulation
30
31 Vice President, responsible for Customer Solutions K. J. Christie
32
33 Vice President, responsible for Energy Delivery H. L. Rosentrater
34
35 Vice President and Chief Strategy Officer E. D. Schlect
36
37 Vice President, and R. D. Woodworth
38 President, Avista Development (retired 811 12016)
39
40
41
42
43
44
FERC FORM NO. r (ED.12-96)Page 104
Name of Respondent
Avista Corporation
This Reoort ls:(1) fiRn Originat
(2) ;A Resubmission
Date of Report(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 2016/Q4
DIRECTORS
1 . Report below the information called for conceming each director of the respondent who held office at any time during the year. lnclude in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
LII IENo.Name (and Trtle) ot Lltreclor less Address
)
1 Scott L. Monis*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 3727, Spokane,WA 99220 - 3727
7
8 Donald C. Burke 16 lvy Court, Langhome, PA 19047
I
10 John F. Kelly**851 Georgia Ave., Winler Park, FL 33143
11
12 Heidi B. Stanley P.O. Box 2884, Spokane, WA 99220
13
14 R. John Taylor*111 Main Street, Lewiston, lD 83501
15
16 Marc F. Racicot 28013 Swan Cove Dr., Big Fork, MT 5991 1
17
18 Rebecca A. Klein 61 1 S. Congress Ave., Suite 125, Austin, fX78704
19
20 Janet D. \Mdmann 26 Sanford Ln., Lafayette, CA 94549
21
22 Scott H. Maw (effective 81112016)2401 Utah Ave. S., Suite 800, Seattle, WA 98134
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. I (ED. 12-95)Page 105
Name of Respondent
Avista Corporation
This Reoort ls:
(1) E] An Original
(2) fl A Resubmission
Date of Reoort(Mo, Da, Yi)
03131t2017
Year/Period of Report
gn6 e1 2016/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceedinq
Does the respondent have formula rates?fl ves
XNo
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
o
10
11
12
13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO.1 (NEW.1248)Page 106
Avista Corporation (1)
(2)
An Original
A Resubmission
Dale of Reoort(Mo, Da, Yi)
o3t31t2017
Year/Period of Report
gn6 6 2016/Q4
INFORMATION ON FORMULA RATES
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
b
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
35
37
38
39
40
4',!
42
43
44
45
46
FERC FORM NO.1 (NEW. 12-08)Page 106a
S:
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reoorl
(Mo, Da, Yi)
03t31t2017
Year/Period of Report
En6 d 2016/Q4
INFORMATION ON FORMULA RATES
Formula Rate Variances
1. lf a respondent does not submit such filings then indicale in a footnote to the applicable Form 1 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 faclors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.
4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
Line
No.Page No(s)Schedule Column Line No
1
2
3
4
5
6
7
I
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
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40
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42
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44
FERC FORM NO.1 (NEW. 12-08)Page l06b
Name of Respondent
Avista Corporation
This Report ls:(1) E An Original
(2) [ A Resubmission
Date ot Report
03t31t2017
Year/Period of Report
End of 20161Q4
IMPORTANT CHANGES DURING THE QUARTER/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 othenvise, 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
orcurred 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 ratlo to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a
cash management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
PAGE lOS INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION
FERC FORM NO. I (ED. 12-96)Page 108
Name of Respondent
Avista Concoration
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
IMPORTANT CHANGES DURING THE QUARTERIYEAR (Continued)
1. None
2. None
3. None
4. None
5. None
6. Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0
million. A two-year option was exercised by the Company in May 2016 to extend the maturity of the facility
agreement to April 2021.
Balances outstanding (including letters of credit) under the Company's revolving committed lines of credit were
as follows as of December 31, 2016 and December 31,2015 (dollars in thousands):
December 31, December 31,
2016 20t5
Balance outstanding at end of period
Letters of credit outstanding at end of period
$120,000
$34,353
$ 105,000
$44,595
In August 2016, Avista Corp. entered into a term loan agreement with a commercial bank in the amount of
$70.0 million with a maturity date of December 30,2016. Loans under this agreement were unsecured and had a
variable annual interest rate. The Company borrowed the entire $70.0 million available under this agreement,
which was used to repay a portion of the $90.0 million in first mortgage bonds that matured in August2016.
This term loan was subsequently repaid in full in December using the proceeds from the first mortgage bonds
issued in December 2016 (discussed below).
In December2016, Avista Corp.issued and sold $175.0 million of 3.54 percent first mortgage bonds due in
2051 pursuant to a bond purchase agreement with institutional investors in the private placement market. The
total net proceeds from the sale of the bonds were used to repay the $70.0 million term loan discussed above and
to repay a portion of the borrowings outstanding under the Company's $400.0 million committed line of credit.
In connection with the execution of the bond purchase agreement, the Company cash-settled seven interest rate
swap derivatives (notional aggregate amount of $125.0 million) and paid a total of $54.0 million. The debt
issuance was approved by regulatory commissions as follows: UTC (Docket No. UE-151822 Order 0l) IPUC
(Case No. AVU-U- I 5-01 Order No. 3340 I ) and the OPUC (Docket UF 4294 Order No. I 5-305).
7. None
8. Average annual wage increases were 2.5%ofor non-exempt employees effective February 22,2016. Average
annualwage increases were 3.0o/ofor exempt employees effective February 22,2016. Officers received average
increases of 5.7%o effective February 22,2016. Certain bargaining unit employees received increases of 3.0%o
effective March 26, 2016.
9. Reference is made to Note l6 of the Notes to Financial Statements.
FERC FORM NO.1 (ED.12.96)Page 109.'l
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016/Q4
IMPORTANT CHANGES DURING THE QUARTERI/EAR (Contlnued)
10. None
I l. Reserved
12. See page 123 of this report.
I 3. On May I 6, 20 I 6 Marian Durkin was named Corporate Secretary, in addition to her current role as Senior
Vice President, General Counsel and Chief Compliance Officer. The former Corporate Secretary, Karen Feltes,
will retain her previous responsibilities as Senior Vice President and Chief Human Resources Officer and
continue to serve as the lead executive for the Board of Directors Compensation and Organization Committee.
On June 30,2016, Avista Corp.'s Board of Directors decided to increase the number of board members from l0
to I 1 and elected Scott H. Maw to fill the vacancy and serve as a director on the board effective August 1,2016.
On July 31,2016, Roger Woodworth, Vice President of Avista Corp. retired.
14. Proprietary capital is not less than 30 percent.
FERC FORM NO.1 (ED.12-96)Page 109.2
Name of Respondent
Avista Corporation
This Report ls:
(1) E An Original
(2) ll AResubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 2o16tQ4
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12t31
(d)
'l UTILITY PLANT
2 Utility Plant (101-106, 1 14)200-201 5,3M,257,392 4,923,194,978
3 Construction Work in Progress (107)200-201 144,751 ,274 190,108,665
4 TOTAL Utility Plant (Enter Total of lines 2 and 3)5,449,008,66€5,1 13,303,643
5 (Less) Accum. Prov. for Depr. Amort. Depl. (108, 1 '10, 111, 115)200-201 1 ,770 ,511 ,42C 1,680,907,938
b Net Utility Plant (Enter Total of line 4 less 5)3,678,497,24e 3,432,395,705
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1)202-203 c 0
8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2)c 0
o Nuclear Fuel Assemblies in Reactor (120.3)0 0
10 Spent Nuclear Fuel (120.4)0 0
11 Nuclear Fuel Under Capital Leases (120.6)0 0
12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5)202-203 0 0
13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12)0 0
14 Net Utility Plant (Enter Total of lines 6 and 13)3,678,497,246 3,432,395,705
15 Utility Plant Adjustments (116)0 0
16 Gas Stored Underground - Noncurrent (1 17)6,992,076 6,992,076
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property (121)3,058,415 2,740,379
19 (Less) Accum. Prov. for Depr. and Amort. (122)211,651 201,768
20 lnvestments in Associated Companies (123)11,547,000 1't,547,000
21 lnvestment in Subsidiary Companies (123.1)224-225 16'1,804,156 157,s15,280
22 (For Cost of Account 123.1, See Footnote Page 224, line 42)
23 Noncurrent Portion of Allowances 228-229 0 0
24 Other lnvestments (124)6,945,185 23,760,324
25 Sinking Funds (125)0 0
26 Depreciation Fund (126)0 0
27 Amortization Fund - Federal (127)0 0
28 Other Special Funds (128)13,61 1,799 20,755,670
29 Special Funds (Non Maior Only) (129)0 0
30 Long-Term Portion of Derivative Assets (175)5,356,765 22,687
31 Long-Term Portion of Derivative Assets - Hedges (176)c 0
32 TOTAL Other Property and lnvestments (Lines 18-21 and 23-31)202,111,66S 216,139,572
33 CURRENT AND ACCRUED ASSETSvCash and Working Funds (Non-major Only) (130)c 0
35 Cash (131)1,373,66i 2,074,149
36 Special Deposits (132-134)7,540,762 14,430,708
37 Working Fund (135)1,138,883 691,896
38 Temporary Cash lnvestments (136)22.854 2U,231
39 Notes Receivable ( 141)c 0
40 Customer Accounts Receivable ( 1 42)172,903,052 160,488,098
41 Other Accounts Receivable (143)4,163,02€5,500,743
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (1r14)4,961,48€4,469,344
43 Notes Receivable from Associated Companies (145)c 0
44 Accounts Receivable from Assoc. Companies (146)462,03€469,096
45 Fuel Stock (151)227 3,566,367 3,293,585
46 Fuel Stock Expenses Undistributed (152)227 c 0
47 Residuals (Elec) and Extracted Products (153)227 c 0
48 Plant Materials and Operating Supplies (154)227 37,423,657 33,931,771
49 Merchandise (155)227 0 0
50 Other Materials and Supplies (156)227 0 0
51 Nuclear Materials Held for Sale (157)202-2031227 0 0
52 Allowances (158.1 and 158.2)22$229 0 0
FERC FORM NO. 1 (REV.12-03)Page 110
Name of Respondent
Avista'Corporation
This Report ls:
(1) tr An Original
(2) tl A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2o16tQ4
COMPARATIVE BAIANCE SHEET (ASSETS AND OTHER DEBlTSlcontinued)
Line
No.Title of Account
(a)
Ref.
Page No
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12t31
(d)
53 (Less) Noncurrent Portion of Allowances c 0
54 Stores Expense Undistributed (1 63)227 -8€0
55 Gas Stored Underground - Current (164.1)8,029,02C 12,774,487
56 Liquefied Natural Gas Stored and Held for Processing (1U.2-1U.3)c 0
57 Prepayments (165)14,459,234 10,580,934
58 Advances for Gas (1 66-1 67)c 0
59 lnterest and Dividends Receivable (171)107,608 39,738
60 Rents Receivable (172\1,429,562 1,749,949
61 Accrued Utility Revenues (173)c 0
62 Miscellaneous Current and Accrued Assets ('174)537,127 527,051
63 Derivative lnstrument Assets (175)10,6M,43e 706,117
64 (Less) Long-Term Portion of Derivative lnstrument Assets (175)5,356,765 22,687
65 Derivative lnstrument Assets - Hedges (176)c 0
66 (Less) Long-Term Portion of Derivative lnstrument Assets - Hedges (176 c 0
67 Total Current and Accrued Assets (Lines 34 through 66)253,482,95a 242,970,522
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181)1 1,690,512 11,527,001
70 Extraordinary Property Losses (1 82.1 )230a 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2)230b 0 0
72 Other Regulatory Assets (182.3)232 622,4U,411 573,031,070
73 Prelim. Survey and lnvestigation Charges (Electric) (183)0 467,080
74 Preliminary Natural Gas Survey and lnvestigation Charges 183.1)0 0
75 Other Preliminary Survey and lnvestigation Charges (183.2)0 0
76 Clearing Accounts (184)13,933 527
77 Temporary Facilities (1 85)0 0
78 Miscellaneous Defened Debits (186)233 43,850,403 26,759,597
79 Def. Losses from Disposition of Utility Plt. (187)0 0
80 Research, Devel. and Demonstration Expend. (188)352-353 0 0
8'l Unamortized Loss on Reaquired Debt (189)13,699,992 15,520,432
82 Accumulated Deferred lncome Taxes [phone]il,707 1 36,036,1 1 9
83 Unrecovered Purchased Gas Costs (191)-30,819,635 -17,880,236uTotal Defened Debits (lines 69 through 83)808,254,323 745,461,590
85 TOTAL ASSETS (lines 14-16,32,67, and &4)4,949,338,269 4,643,959,465
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, y0
o3t31DO17
Year/Period of Report
end of 2016tQ4
coMPARAT|VE BALANCE SHEET (LtABtLtTtES AND OTHER CREDTTS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Cunent Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12t31
(d)
1 PROPRIETARY CAPITAL
2 Common Stock lssued (201)250-251 1,052,578,75e 984,603,843
3 Preferred Stock lssued (2M)250-251 c 0
4 Capital Stock Subscribed (202, 205)c 0
5 Stock Liability for Conversion (203, 206)c 0
6 Premium on Capital Stock (207)c 0
7 Other Paid-ln Capital (208-211)253 -9,506,47€-9,506,476
I lnstallments Received on Capital Stock (212)252 0 0
I (Less) Discount on Capital Stock (213)254 0 0
10 (Less) Capital Stock Expense (214)254b -32,208,771 -29,238,213
11 Retained Earnings (21 5, 21 5.1, 216)118-119 582,1 56,946 536,82'1,476
12 Unappropriated Undistributed Subsidiary Earnings (216.1)'t18-119 -1,143,222 -5,881,619
13 (Less) Reaquired Capital Stock (217)25G251 0 0
't4 Noncorporate Proprietorsh ip (Non-major only) (2 1 8)0 0
15 Accumulated Other Comprehensive Income (219)122(a\(b)-7,567,509 -6,649,771
16 Total Proprietary Capital (lines 2 through 15)1,648,727,266 1,528,625,666
17 LONG.TERM DEBT
18 Bonds (221 )256-257 1,621,700,000 1,536,700,000
19 (Less) Reaquired Bonds (222)256-257 83,700,000 83,700,000
20 Advances from Associated Companies (223)256-257 51,547,000 51,547,000
21 Other Long-Term Debt (224)256-257 0 0
22 Unamortized Premium on Long-Term Debt (225)168,783 177,666
23 (Less) Unamortized Discounl on Long-Term Debt-Debit (226)960,522 1,134,563
24 Total Long-Term Debt (lines 18 through 23)1,588,755,261 1 ,503,590,103
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227)2,402,917 3,274,583
27 Accumulated Provision for Property lnsurance (228.1)0 0
28 Accumulated Provision for lnjuries and Damages (228.2)260,000 239,910
29 Accumulated Provision for Pensions and Benefits (228.3)226,551 ,767 201,453,549
30 Accumulated Miscellaneous Operating Provisions (228.4)c 0
31 Accumulated Provision for Rate Refunds (229)6,600,08€1't,476,706
32 Long-Term Portion of Derivative lnstrument Liabilities 41,994,092 52,248,M5
33 Long-Term Portion of Derivative lnstrument Liabilities - Hedges c 0vAsset Retirement Obligations (230)15,514,534 15,996,704
35 Total Other Noncurrent Liabilities (lines 26 through 34)293,323,39€284,689,897
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231)120,000,00c 105,000,000
38 Accounts Payable (232)111,124,132 109,244,954
39 Notes Payable to Associated Companies (233)5,634,684 22,177,680
40 Accounts Payable to Associated Companies (234)37.621 18,798
4'.!Customer Deposits (235)3,808,551 3,273,927
42 Taxes Accrued (236)262-263 -16,431 ,293 7,186,818
43 lnterest Accrued (237)14,676,249 14,179,517
44 Dividends Declared (238)c 0
45 Matured Long-Term Debt (239)c 0
FERC FORM NO.1 (rev.12-03)Page 112
Name of Respondent
Avista Corporation
This Report is:
(1) tr An Original
(2) n A Resubmission
Date of Report
(mo, da, yr)
o3t31t2017
Year/Period of Report
end of 20161Q4
COMPARATIVE BALANCE SHEET (LlABlLlTlES AND OTHER CREDlT6intinued)
Line
No.Title of Account
(a)
Ref.
Page No
(b)
Current Year
End of Quarterffear
Balance
(c)
Prior Year
End Balance
12t31
(d)
46 Matured lnterest (240)c 0
47 Tax Collections Payable (241)1,431,933 1,759,040
48 Miscellaneous Current and Accrued Liabilities (242)58,068,093 57,577,117
49 Obligations Under Capital Leases-Current (243)871,667 871,667
50 Derivative lnstrument Liabilities (244)55,076,777 85,797,553
51 (Less) Long-Term Portion of Derivative lnstrument Liabilities 41,994,092 52,248,445
52 Derivative lnstrument Liabilities - Hedges (245)c 0
53 (Less) Long-Term Portion of Derivative lnstrument Liabilities-Hedges c 0
54 Total Current and Accrued Liabilities (lines 37 through 53)312,30432e 354,838,626
55 DEFERRED CREDITS
56 Customer Advances for Construction (252)2,266,861 2,161,687
57 Accumulated Deferred lnvestment Tax Credits (255)266-267 31,501,931 12,639,187
58 Deferred Gains from Disposition of Utility Plant (256)c 0
59 Other Deferred Credits (253)269 15,262,11e 39,790,303
60 Other Regulatory Liabilities (254)278 77,740,26e 40,976/U
61 Unamortized Gain on Reaquired Debt (257)1,836,97C 1,966,507
62 Accum. Deferred I ncome Taxes-Accel. Amort.(281 )272-277 c 0
63 Accum. Deferred lncome Taxes-Other Property (282)731.162.121 646,870,366
il Accum. Defened lncome Taxes-Other (283)246,457,751 227,810,639
65 Total Deferred Credits (lines 56 through 64)1J06,228,02C 972,215,173
bb TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24,35,54 and 65)4,949,338,269 4,643,959,465
FERC FORM NO.1 (rev. 12431 Page 113
S:
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
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 (j) the quarter to date amounts for gas utility, and in column (l)
the quarler 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 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. 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 412 and 413 above.
Line
No.
Title of Account
(a)
(Ref.)
Page No.
(b)
Total
Cunent Year to
Date Balance for
Quarterffear
(c)
Total
Prior Year to
Date Balance for
Quarterffear
(d)
Cunent 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301 1,476,215,123 1,530,543,739
3 Operating Expenses
4 Operation Expenses (401)320-323 858,140,856 980,245,446
5 Maintenance Expenses (402)320-323 68,632,689 64,022,756
6 Depreciation Expense (403)336-337 130,221,417 122,488,709
7 Depreciation Expense for Asset Retirement Costs (403.1)336-337
I Amort. & Depl. of Utility Plant (404405)336-337 26,ss4,225 21,il4,0u
I Amort. of Utility Plant Acq. Adj. (406)336-337 99,047 99,047
10 Amort. Property Losses, Unrecov Plant and Regulalory Study Costs (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3)2,541,927 1,615,427
'13 (Less) Regulatory Credits (407.4)1,790,145 12,818,909
14 Taxes Other Than lncome Taxes (408.1 )262-263 96,218,096 95,109,798
15 lncome Taxes - Federal (409.1 )262-263 -37,366,331 5,601,404
16 Other (409.1)262-263 379,481 91 9,149
17 Provision for Defened lncome Taxes (410.1)2v,272-277 102,646,826 65,371,809
18 (Less) Provision fur Defened lncome Taxes-Cr. (41 1.1)2y,272-277 1,622,706 2,423,024
19 lnvestment Tax Credit Adj. - Net (41 1.4)zbb 18,862,745 481,680
20 (Less) Gains from Disp. of Utility Plant (41 1.6)
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allot'trances (41 I .8)
23 Losses from Disposition of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24)1,263,518,127 1,342,261,296
26 Net Util Oper lnc (Enter Tot line 2 less 25) Carry to P9117 ,line 27 212,696,996 188,282,M3
FERC FORM NO. 1/3-Q (REV.02-04)Page 114
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn Originat(2) f]A Resubmission
Date of Report
(Mo, Da, Yr)
o3t3112417
Year/Period of Report
End of 20161Q4
STATEMENT OF INCOME FOR THE YEAR
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. lt any notes appearing in the report to stokholders are applicable to the Statement of lncome, such notes may be included atpage 122.
1 3. 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 efiect of such changes.
14. Explain in a footnote if the previous yea/s/quarte/s figures are different from that reported in prior reports.
15. lf the columns are insufiicient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
ELECTRIC UTILITY GAS UTILITY OTHER UILIry
Line
No.cunent Year to Date
(in dollars)
(s)
Previous Year to Date
(in dollars)
(h)
current Year to L,ate
(in dollars)
(i)
Prevrous Year to Date
(in dollars)
o
L;urTent Year t0 uate
(in dollars)
(k)
Prcvrous Year t0 Date
(in dollars)
o
1
1,004,897,624 1,006,140,061 47',1,317,499 524,403,678 2
3
523,294,682 567,238,063 334,8/,6,174 413,007,383 4
53,468,423 50J48,482 15,164,266 13,874,274 5
101,769,331 95,895,1 30 28,452,086 26,593,579 6
7
20,106,387 16,5'19,997 6,447,838 5,024,007 8
99,047 99,047 o
10
11
2,573,428 2,650,525 -31,501 -1,03'1 ,098 12
1 ,781,7'.t3 12,',t46,367 8,432 672,il2 13
74,172,165 72,133,173 22,0d.5,931 22,976,625 14
-34,063,947 10,884,U7 -3,302,384 -5,283,443 '15
365,911 936,622 13,570 -17,473 16
79,435,289 il,107,931 23,211,537 11,263,878 17
'1,397,052 2,599,365 225,6il -176,v1 18
18,887,909 511,740 -25,164 -30,060 19
20
21
22
23
24
836,929,860 856,379,825 426,588,267 485,881,471 25
167,967,7U 149,760,236 44,729,232 38,522,207 26
FERC FORM NO. 1 (ED.12-96)Page 11S
Name
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Penod of Report
End of 20161Q4
STATEMENT OF INCOME FOR THE YEAR r
Line
No.
Title of Account
(a)
(Ref.)
Page No
(b)
TOTAL ourTent 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Pnor 3 Montns
Ended
Quarterly Only
No 4th Ouarter
(0
Current Year
(c)
Previous Year
(d)
27 Net Utility Operatino lncome (Canied foruard from paqe 114)212,696,996 188,282,443
28 Other lncome and Deduclions
29 Other lncome
30 Nonutilty Operatiru lncome
31 Revenues From Merchandising, Jobbing and Contrac{ Work (415)
32 (Less) Costs and Exp. of Merchandising, Job. & Contnct Work (416)
33 Revenues From Nonutility Operations (417)
u (Less) Expenses of Nonutility Operations (41 7.1 )11,653,482 9,s66,840
35 Nonoperating Rental lncome (418)-939 -939
36 Equity in Eamings of Subsidiary Companies (418.1)11S 6,288,876 11,164,785
37 lnterest and Dividend lncome (419)2,719,465 645,403
38 Allowance for Other Funds Used Durinq Construction (419.1)7,298,983 7,961,552
39 Miscellaneous Nonoperating lncome (421)795,424
40 Gain on Disposition of Propeny (421.1)240,298 142,552
41 TOTAL Other lncome (Enter Total of lines 31 thru 40)4,893,201 11,141 ,937
42 Other lncome Deductions
43 Loss on Disposition of Property (421.2)
44 Miscellaneous Amortization (425)
45 Donations (426.1)2,837,1U 3,208,021
46 Life lnsurance (426.2)2,589,'t59 3,079,994
47 Penalties (426.3)$4,096 70,316
48 Exp. for Certain Civic, Political & Related Activities (426.4)1,788,417 1,625,650
49 Other Deductions (426.5)1 ,915,238 1,386,500
50 TOTAL Other lncome Deductions (Total of lines 43 thru 49)9,065,882 9,370,481
51 Taxes Applic. to Other lncorne and Deductions
52 Taxes Other Than lncome Taxes (408.2)262-263 192,113 202,511
53 lncome Taxes-Federal (409.2)262-263 10,041,967 -715,329
il lncome Taxes-Other (409.2)262-263 +,y.,874 486,632
55 Provision for Defened lnc. Taxes (410.2)234,272-277 1,585,996 1,006,935
56 (Less) Provision for Defened lncome Taxes-Cr. (41 1.2)2v,272-277 322,781 5,704,7v
57 lnvestment Tax Credit Adj.-Net (411.5)
58 (Less) lnvestment Tax Credits (420)
59 TOTAL Taxes on Other lncome and Deductions (Total of lines 52-58)-9,421,513 6,097,249
60 Net Other lncome and Deduc{ions fTotal of lines 41, 50, 59)5,248,832 7,868,705
61 lnterest Chaqes
62 lnterest on Long-Term Debt (427)74,527,233 69,747,769
63 Amort. of Debt Disc. and Expense (428)458,080 419,914
il Amortization of Loss on Reaquired Debt (428.1)2,941,399 3,004,198
65 (Less) Amort. of Premium on Debt-Credil (429)8,883 8,883
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67 lnterest on Debt to Assoc. Companies (430)766,389 605,274
68 O,ther lnterest Expense (431)4,386,030 2,636,227
69 (Less) Allowance for Bonoured Funds Used During Construction{r. (432)2,352,527 3,480,392
70 Net lnterest Charges (Total of lines 62 thru 69)80,717,721 72,924,107
71 lncome Before Extraordinary ltems (Total of lines 27, 60 and 70)137,228,107 123,227,041
72 Extraodinary ltens
73 Extraordinary lncome (4314)
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 ltens After Taxes (line 75 less line 76)
78 Net lncome (Total of line 71 and 77)137,228,107 123,227,041
FERC FORM NO. r (ED. 12-96)Page 117
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This
(1)
(2)
An
ls:
Original
A Resubmission
Date of Reoort(Mo, Da, Yi)
o3R1t2017
Year/Period of Report
End of 2016tQ4
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
Account Affected
(b)
Cunent
Quarlerl/ear
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period 517393,il7 492,987,406
2 Changes
Adjustments to Retained Eamings (Account 439)
4
5
6
7
8
I TOTAL Credits to Retained Earnings (Accl. 439)
10 Repurchases from common stock ( 1,488,991)
11
12
13
14
't5 TOTAL Debits to Retained Earnings (Acct. 439)( 1 ,488,991)
16 Balance Transferred from lncome (Account 433 less Account 418.1)130,939,23'l 112,062,256
17 Appropriations of Retained Earnings (Acct. 436)
18 Excess Earnings 4,M'.1,571 ( 5,158,174)
19
20
2'l
22 TOTAL Appropriations of Retained Earnings (Acct. 436)-4,441,571 ( 5,158,174)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 -87,1il,241 ( 82,396,801)
32
33u
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438)-87,1U,241 ( 82,396,801)
37 Transfers from Acct 216.1, Unapprop. Undiskib. Subsidiary Earnings 1,550,480 1,387,851
38 Balancc - End of Period Clotal 1 ,9,15,16 ,22,29,36,37\558,287,446 517,393,547
APPROPRIATED RETAINED EARNINGS (Account 215)
39 23,869,500 19,427,929
40
FERC FORM NO. 1/3-Q (REV.02-04)Page 118
Name Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
(Mo Da
03t3112017
Year/Period of Report
20161Q4End of
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
llem
(a)
Contra Primary
Account Affec'ted
(b)
Current
Quarter^/ear
Year to Dale
Balance
(c)
Previous
Quarterffear
Year to Date
Balance
(d)
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215)23,869,500 19,427,929
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.'l)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47 TOTALApprop. Retained Earnings (Acct.215, 215.1) (Total 45,46)23,869,500 19,427,929
48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (total 38, 47') (2'16.1)582,156,946 536,821,476
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit)-5,881,618 ( 15,658,s53)
50 Equity in Earnings for Year (Credit) (Account 418.1)6,288,876 11,164,785
51 (Less) Dividends Received (Debit)
52 -1,550,480 ( 1,387,850)
53 Balance-End of Year (Total lines 49 thru 52)-1,143,222 ( 5,881,618)
FERC FORM NO. 1r3-Q (REV.02-04)Page 1i9
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn Orisinat(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2016/Q4
STATEMENT OF CASH FLOWS
(1) Codes to be used:(a) Net Proceeds or Payrnents;(b)Bonds, debentures and other long-term debt; (c) lnclude commercial paper; and (d) ldentiry separately such items as
investments, fixed assets, intangibles, etc.
Equivalents at End of Period" with related amounts on the Balance Sheet.
in those activities. Sho$, in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General lnstrction 20; instead provide a reconciliation of the
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
Quarlerffear
(b)
Previous Year to Date
Quarterf/ear
(c)
1 Net Cash Flow from Operating Activities:
2 Net lncome (Line 78(c) on page 1'17)137,228,107 123,227,041
5 Noncash Charges (Credits) to lncome:
4 Depreciation and Depletion 't55,162,338 138,235,780
5 Amortization of Deferred Power and Natural Gas Costs 16,834,990 21,3s7,796
6 Amortization of Debt Expense 3,390,597 3,4',t5,229
7 Amortization of lnvestment in Exchange Power 2,450,031 2,450,031
8 Deferred lncome Taxes (Net)102,361,230 53,931,'t02
I lnvestment Tax Credit Adjustment (Net)18,862,744 481,680
10 Net (lncrease) Decrease in Receivables -16,916,930 -3,884,715
11 Net (lncrease) Decrease in lnventory 980,885 12,267,853
12 Net (lncrease) Decrease in Allowances lnventory
13 Net lncrease (Decrease) in Payables and Accrued Expenses -26,',t52,468 6,880,543
14 Net (lncrease) Decrease in Other Regulatory Assets -38,029,474 4,114,779
15 Net lncrease (Decrease) in Other Regulatory Liabilities 2,936,022 2,007,7U
16 (Less) Allowance for Other Funds Used During Construc{ion 7,298,983 7,%1,552
17 (Less) Undistributed Earnings from Subsidiary Companies 6,288,876 11,164,785
18 Other (provide details in footnote):
19 Allowance for Doubtful Accounts 6,000,000 5,749,995
20 Changes in Other Non-Current Assets and Liabilities 4,190,684 5,891,691
21 Cash Paid for Settlement of lnterest Rate Swaps -53,966,197
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)337,756,882 353,153,455
23
24 Cash Flows from lnvestment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel)-390,690,230 -381,174,406
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33v Cash Outflows for Plant (Total of lines 26 thru 33)-390,690,230 -381 ,174,406
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncunent Assets (d)1,288,524 272,897
38 Federal and State Grant Payments Received 512,000 2,730J66
39 lnvestments in and Advances to Assoc. and Subsidiary Companies -16,517,1 10 12,185,571
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of lnvestments in (and Advances to)
42 Associated and Subsidiary Companies
43 Cash Paid for Acquisition -94,643
44 Purchase of lnvestment Securities (a)
45 Proceeds from Sales of lnvestment Securities (a)
%,012,'.t82 4,382,761
FERC FORM NO. 1 (ED. 12-96)Page 120
Name of Respondent
Avista Corporation
This Reoorl ls:(1) fiAn Originat(2) flA Resubmission
Date of Reoort(Mo, Da, Yi)
03t3112017
Year/Period of Report
End of 2016/Q4
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. Sho\,\, 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)
current Year to L,ate
Quarterffear
(b)
Previous Year to Date
Quarter/Year
(c)
46 Loans Made or Purchased
47 Collections on Loans
48 Restricted Cash -25,425 s2,2U
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 Acrrued Expenses
53 Other (provide details in footnote):
54 Changes in Other Property and Investments -8,915,799 -7,992,961
55 Dividends Received from Subsidiaries 2,000,000 2,000,000
56 Net Cash Provided by (Used in) lnvesting Activities
57 Total of lines 34 thru 55)412,348,040 -372,135,660
58
59 Cash Flows from Financing Activities:
60 Proceeds from lssuance of:
61 Long-Term Debt (b)245,000,000 100,000,000
62 Preferred Stock
63 Common Stock 6,952,672 1,559,840
64 O(her (provide details in footnote):
65
66 Net lncrease in Short-Term Debt (c)15,000,000
67 other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Iotal 61 thru 69)326,952,672 101,559,840
71
72 Payments for Retirement of:
73 Long-term Debt (b)-160,871,667 -734,802
74 Preferred Stock
75 Common Stock -2.919.781
76 Other (provide details in footnote):-3,072,4i
77 Debt lssuance Costs -1,698,045 -593.969
78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Preferred Slock
81 Dividends on Common Stock -87,154,241 -82,396,801
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81)74,156,286 3,937,239u
85 Net lncrease (Decrease) in Cash and Cash Equivalenls
86 (Total of lines 22,57 and 83)434,872 -15,044,966
87
88 Cash and Cash Equivalents at Beginning of Period 2,970,276 18,015,242
89
90 Cash and Cash Equivalents at End of period 2,535,404 2,970,276
FERC FORM NO. 1 (ED. 12-96)Page 121
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
120 1
Power an natural gas erra
Change in speclal deposits
Change in other current assets
Non-cash stock compensation
Amortization of Spokane Energy contract
Change in Coyote Sprlngs 2 O&M LTSA
Preliminary survey and investigation costsGain on sale of property and equj-pment
Other
1-, 4oB, gg1
L0 ,'7 72, 388(3, 635, 861 )
'7 , gg0 ,7 05
l4 , 694, 31 4
4 ,7 05, 259
461 ,080(240 ,29'7 )
9 547
120 Line No.: 18 Column: c
Power and natural gas deferrals
Change in special deposits
Change in other current assets
Non-cash stock compensationAmortization of Spokane Energy contract
Change in Coyote Springs 2 O&M LISAPrelimi-nary survey and investigation costsGain on sale of property and equipment
Other
(13,301,265',)
2, 956, 640
6, 973, 619g, 4gg , 494
(2,260 , 667)(301,2141
(742,5521
2 587
Payment o n tax thhol ngs for120 Line No.:76 Column: b
share-based a t awards
Excess tax ts
Payment of minimum withholdings
for share based payment awards
Cash paj-d for settlement of interestrate swaps
3 012 433
f 180,431
(1,831 ,61 9l
(9,326,000)
120 Line No.:76 Column: c
FERC FORM NO.1 ED.1 450.1
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
I hts l-<epon ls:(1) E An Original
(2) ! A Resubmission
lJate ot Repoft
03t31t2017
Year/Period ot Report
End of 2O16tQ4
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 utilig. Give also a brief explanation of any dividends in arrears
on cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts '189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give
an explanation, providing the rate treatment given these items. See General lnstruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. 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 1 14-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes signiflcant 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
aoolicable and furnish the data reouired bv the above instructions. such notes mav be included herein.
PAGE l22INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO. I (ED. 12-96)Page 122
Name of Respondent
Avista Comoration
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t20't7
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nuture of Business
Avista Corp. (the Company) is primarily an electric and natural gas utility with certain other business ventures. Avista Corp. provides
electric distribution and transmission, and natural gas distribution services in parts of eastem Washinglon and northern Idaho. Avista
Corp. also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Corp. has electric
generating facilities in Washinglon, Idaho, Oregon and Montana. Avista Corp. also supplies electricity to a small number of customers
in Montan4 most of whom are employees who operate Avista Corp.'s Noxon Rapids generating facility.
AERC is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is AEI-&P, which comprises Avista Corp.'s
regulated utility operations in Alaska. AERC was acquired by Avista Corp. on July l, 2014 and there are no AERC eamings included
in the overall results of Avista Corp. prior to that date. See Note 3 for information regarding the acquisition of AERC.
Avista Capital, a wholly owned non-regulated subsidiary of Avista Corp., is the parent company of all of the subsidiary companies
except AERC (and its subsidiaries). During the first half of 2014 and prior, Avista Capital's subsidiaries included Ecova, which was an
80.2 percent owned subsidiary prior to its disposition on June 30,2014. See Note 4 for information regarding the disposition of Ecova.
Basis 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 forth in its applicable Uniform System
ofAccounts and published accounting releases, which is a comprehensive basis ofaccounting other than accounting principles
generally accepted in the United States of America (U.S. GAAP). As required by the FERC, the Company accounts for its investment
in majority-owned subsidiaries on the equity method rather than consolidating the assets, liabilities, revenues, and expenses of these
subsidiaries, as required by U.S. GAAP. The accompanying financial statements include the Company's proportionate share of utility
plant and related operations resulting from its interests in jointly owned plants. In addition, under the requirements of the FERC, there
are differences from U.S. GAAP in the presentation of (1) current portion of long-term debt (2) assets and liabilities for cost of
removal of assets, (3) assets held for sale, (4) regulatory assets and liabilities, (5) defened income taxes associated with accounts other
than utility propefty, plant and equipment, (6) comprehensive income, (7) unamortized debt issuance costs and (8) operating revenues
and resource costs associated with settled energy contracts that are "booked out" (not physically delivered).
Use of Estimates
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that
affect the amounts reported for assets and liabilities and the disclosure ofcontingent assets and liabilities at the date ofthe financial
statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include:
o determining the market value of enerry commodity derivative assets and liabilities,
. pension and other postretirement benefit plan obligations,
. contingent liabilities,
o goodwill impairment testing,
. recoverability ofregulatory assets, and
r unbilled revenues.
Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the financial
FERC FORM NO.1 (ED.12.88)Page 123.1
Name of Respondent
Avista Corporation
This Report is:
(1)X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
statements and thus actual results could differ from the amounts reported and disclosed herein.
System ofAccoun$
The accounting records of the Company's utility operations are maintained in accordance with the uniform system of accounts
prescribed by the FERC and adopted by the state regulatory commissions in Washington, Idaho, Montana and Oregon.
Regulotion
The Company is subject to state regulation in Washington, Idaho, Montana and Oregon. The Company is also subject to federal
regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its
operations.
Operating Revenues
Operating revenues related to the sale ofenergy are recorded when service is rendered or enerry is delivered to customers. The
determination of the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis
throughout the month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter
reading is estimated and the corresponding unbilled revenue is estimated and recorded. Our estimate of unbilled revenue is based on:
o the number of customers,
. culTent rates,
. meter reading dates,
. actual native load for electricity,
. actual throughput for natural gas, and
r electric line losses and natural gas system losses.
Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading
and customer billing occurs.
Accounts receivable includes unbilled energy revenues of the following amounts as of December 3l (dollars in thousands):
2016 2015
Unbil led accounts receivable $ 69,544 $ 59,40s
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 :
2016 2015
Ratio ofdepreciation to average depreciable property
The average service lives for the following broad categories of utility plant in service are (in years):
Electric thermal/other production
Hydroelectric production
Electric transmission
3.t1%3.09%
Avista Corp.
4t
78
57
FERC FORM NO.1 (ED.12€8)Page 123.2
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0313112017
Year/Period of Report
20161Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Electric distribution
Natural gas distribution property
Other shorter-lived general plant
Taxes Other Than Incomc 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 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. Taxes
other than income taxes consisted of the following items for the years ended December 3l (dollars in thousands):
2016 2015
35
45
9
Utilify related taxes
Property taxes
Other taxes
Total
$s6,286 $
38,505
1,619
57,716
3s,948
I,648
$ 96,410 $ 95,312
Allowancefor Funds Used During Construction
AFUDC represents the cost of both the debt and equity funds used to finance utiliry plant additions during the construction period. As
prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant. The debt component of AFUDC is
credited against total interest expense in the Statements of Income in the line item "capitalized interest." The equity component of
AFUDC is included in the Statement of Income in the line item "other income-net." The Company is permitted, under established
regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its inclusion in rate base and the
provision for depreciation after the related utility plant is placed in service. Cash inflow related to AFUDC does not occur until the
related utility plant is placed in service and included in rate base. The effective AFUDC rate was the following for the years ended
December 3l :
20t6 201 5
Effective AFUDC rate 7.29%7.32%
Income Tsxes
Deferred income tax assets represent future income tax deductions the Company expects to utilize in future tax returns to reduce
taxable income. Deferred income tax liabilities represent future taxable income the Company expects to recognize in future tax returns.
Deferred tax assets and liabilities arise when there are temporary differences resulting from differing treatment of items for tax and
accounting purposes (such as depreciation). A deferred income tax asset or liability is determined based on the enacted tax rates that
will be in effect when the temporary 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 deferred income tax asset and liability accounts from the beginning to the end ofthe 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
unless a regulatory order specifies defenal of the effect of the change in tax rates over a longer period of time. The Company
establishes a valuation allowance when it is more likely than not that all, or a portion, of a deferred tax asset will not be realized.
Deferred income tax liabilities and regulatory assets are established for income tax benefits flowed through to customers. The
Company did not incur any penalties on income tax positions in 2016 or 2015. The Company would recognize interest accrued related
to income tax positions as interest expense and any penalties incurred as income deductions.
FERG FORM NO. 1 ED.1 123.3
Name of Respondent
Avista Comoration
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
S to c k- B as e d C o mp e ns ati o n
The Company currently issues three types of stock-based compensation awards - restricted shares, market-based awards and
performance-based awards. Historically, these stock compensation awards have not been material to the Company's overall financial
results. Compensation cost relating to share-based payment transactions is recognized in the Company's financial statements based on
the fair value of the equity or liability instruments issued and recorded over the requisite service period.
The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the
Statements of Income of the following amounts for the years ended December 31 (dollars in thousands):
20t6 2015
Stock-based compensation expense
Income tax benefits ( I )
$7,891 $ 6,914
4,3s9 2.420
(l) Incometaxbenefitsfor20l6include$l.6millionassociatedwithexcesstaxbenefitsonsettledshare-basedemployeepayments.
The excess tax benefits were recognized in the Statement of Income for 2016 due to the adoption of ASU 2076-09, effective
January 1,2016. See Note 2 for further discussion.
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 retum on equity target
in order for the Chief Executive Officer's restricted shares to vest. Restricted stock is valued at the close of market of the Company's
common stock on the grant date.
Total Shareholder Return (TSR) awards are market-based awards and Cumulative Eamings Per Share (CEPS) awards are performance
awards. CEPS awards were first granted in2014. Both types of awards vest after a period of three years and are payable in cash or
Avista Corp. corrrmon stock at the end of the three-year period. The method of settlement is at the discretion of the Company and
historically the Company has settled these awards through issuance of Avista Corp. common stock and intends to continue this
practice. Both types of awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances,
and are subject to meeting specific market or performance conditions. Based on the level of attainment of the market or performance
conditions, the amount of cash paid or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend
equivalent rights are accumulated and paid out only on shares that eventually vest and have met the market and performance
conditions.
For both the TSR awards and the CEPS awards, the Company accounts for them as equiry awards and compensation cost for these
awards is recognized over the requisite service period, provided that the requisite service period is rendered. For TSR awards, ifthe
market condition is not met at the end of the three-year service period, there will be no change in the cumulative amount of
compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS
awards, at the end of the three-year service period, if the intemal performance metric of cumulative earnings per share is not met, all
compensation cost for these awards is reversed as these awards are not considered vested.
The fair value of each TSR award is estimated on the date of grant using a statistical model that incorporates the probability of meeting
the market targets based on historical retums relative to a peer group. The estimated fair value of the equity component of CEPS
awards was estimated on the date of grant as the share price of Avista Corp. common stock on the date of grant, less the net present
value ofthe estimated dividends over the three-year period.
The following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other
pertinent information related to the Company's stock compensation awards for the years ended December 31:
20t6 2015
FERC FORM NO.1 (ED.12.88)Paqe 123.4
Name of Respondent
Avista Corporation
This Report is:
(1)X An Originale) A Resubmission
Date of Report
(Mo, Da, Yr)
0313112017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Restricted Shares
Shares granted during the year
Shares vested during the year
Unvested shares at end ofyear
Unrecognized compensation expense at end ofyear (in thousands)
TSR Awards
TSR shares granted during the year
TSR shares vested during the year
TSR shares eamed based on market metrics
Unvested TSR shares at end ofyear
Unrecognized compensation expense (in thousands)
CEPS Awards
CEPS shares granted duringthe year
CEPS shares vested during the year
CEPS shares earned based on market metrics
Unvested CEPS shares at end ofyear
Unrecognized compensation expense (in thousands)
$
$
$
116,435
(l I 1,665)
132,887
222,228
3,409 $
58,610
(52,38s)
109,806
1,953 $
57,521
(55,835)
90,460
110,452
1,671 $
s8,302
(60,379))
106,091
1,705
116,435
(l 71,334))
222,734
223,697
3,219
58,259
I I 1,887
1,840
Outstanding TSR and CEPS share awards include a dividend component that is paid in cash. This component of the share grants is
accounted for as a liability award. These liability awards are revalued on a quarterly basis taking into account the number of awards
outstanding, historical dividend rate, the change in the value of the Company's common stock relative to an external benchmark (TSR
awards only) and the amount of CEPS earned to date compared to estimated CEPS over the performance period (CEPS awards only).
Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid. As of
December 31,2016 and 2015, the Company had recognized cumulative compensation expense and a liability of $1.5 million,
respectively, related to the dividend component on the outstanding and unvested share grants.
Cssh and Cash Equivalents
For the purposes of the Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or
less when purchased to be cash equivalents.
Allowance for D oubtful Accourrts
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
Utilig Plant in Service
The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of
property and improvements, is capitalized. The cost of depreciable units of properly retired plus the cost of removal less salvage is
charged to accumulated depreciation.
Assel Retire me nt O blig afio ns
The Company records the fair value of a liability for an ARO in the period in which it is incurred. When the liability is initially
FERC FORM NO. 1 (ED.12-88}Paqe 123.5
Name of Respondent
Avista Comoration
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
recorded, the associated costs of the ARO are capitalized as part of the carrying amount of the related long-lived asset. The liability is
accreted to its present value each period and the related capitalized costs are depreciated over the useful life ofthe related asset. In
addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new
information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived asset. Upon
retirement of the asset, the Company either settles the ARO for its recorded amount or incurs a gain or loss. The Company records
regulatory assets and liabilities for the difference between asset retirement costs currently recovered in rates and AROs recorded since
asset retirement costs are recovered through rates charged to customers (see Note 7 for further discussion of the Company's asset
retirement obligations).
Goodwill
Goodwill arising from acquisitions represents the future economic benefit arising from other assets acquired in a business combination
that are not individually identified and separately recognized. The Company evaluates goodwill for impairment using a qualitative
analysis (Step 0) for AEL&P and a combination of discounted cash flow models and a market approach for the other subsidiaries on at
least an annual basis or more frequently if impairment indicators arise. The Company completed its annual evaluation of goodwill for
potential impairment as ofNovember 30, 2016 and determined that goodwill was not impaired at that time. While, the Company does
not have any goodwill amounts recorded on its FERC balance sheets, it does have goodwill at its subsidiaries and the amounts for
goodwill are reflected in the investment in subsidiary companies.
The following amounts were recorded as goodwill at the subsidiary companies and reflected through the investment in subsidiary
companies on the FERC balance sheets (dollars in thousands):
AEL&P Other
Accumulated
Impairment
Losses Total
Balance as of the December 3'l ,2015
Balance as of the December 31 ,2016
$ s2,426 $ 12,979 $ (7,733) $ s7,672
$ 52,426 $ 12,979 $ (7,733) $ 57,672
Accumulated impairment losses are attributable to the other businesses.
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Balance Sheets measured at estimated fair value.
The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset energy commodity derivative assets or liabilities
with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and losses on
energy commodity transactions until the period of delivery. Realized benefits and costs result in adjustments to retail rates through
PGAs, the ERM in Washington, the PCA mechanism in Idaho, and periodic general rates cases. The resulting regulatory assets have
been concluded to be probable ofrecovery through future rates.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated
fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual
basis until they are settled or realized unless there is a decline in the fair value ofthe contract that is determined to be
other-than-temporary.
For interest rate swap derivatives, Avista Corp. records all mark-to-market gains and losses in each accounting period as assets and
liabilities, as well as offsetting regulatory assets and liabilities, such that there is no income statement impact. The interest rate swap
derivatives are risk management tools similar to energy commodity derivatives. Upon settlement of interest rate swap derivatives, the
regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company records
FERC FORM NO.1 (ED.12-88)Paqe 123.6
Name of Respondent
Avista Comoration
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
an offset of interest rate swap derivative assets and liabilities with regulatory assets and liabilities, based on the prior practice of the
commissions to provide recovery through the ratemaking process.
As of December 3 1 , 20 I 6, the Company has multiple master netting agreements with a variety of entities that allow for
cross-commodity netting of derivative agreements with the same counte[party (i.e. power derivatives can be netted with natural gas
derivatives). In addition, some master netting agreements allow for the netting of commodity derivatives and interest rate swap
derivatives for the same counterparty. The Company does not have any agreements which allow for cross-affiliate netting among
multiple affiliated legal entities. The Company nets all derivative instruments when allowed by the agreement for presentation in the
Balance Sheets.
Fair Value Measurements
Fair value represents the price thatwould be received when selling an asset or paid to transfer a liability (an exit price) in an orderly
transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred
compensation assets, as well as derivatives related to interest rate swap derivatives and foreig currency exchange derivatives, are
reported at estimated fair value on the Balance Sheets. See Note 14 for the Company's fair value disclosures.
Regulatory Defened Charges ond Credits
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,
o 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. The Company also has decoupling revenue deferrals, which began in 2015. Decoupling revenue deferrals are
recognized in the Statements oflncome during the period they occur (i.e. duringthe period ofrevenue shortfall or excess due to
fluctuations in customer usage), subject to certain limitations, and a regulatory asset/liability is established which will be surcharged or
rebated to customers in future periods. GAAP requires that for any altemative regulatory revenue program, like decoupling, the
revenue must be expected to be collected from customers within 24 months ofthe defenal to qualifr for recognition in the current
period Statement of Income. Any amounts included in the Company's decoupling program that are not expected to be collected from
customers within 24 months are not recorded in the financial statements until the period in which revenue recognition criteria are met.
This could ultimately result in decoupling revenue being recognized in a future period.
If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory
accounting practices for all or a portion ofits regulated operations, the Company could be:
o reguired to write offits regulatory assets, and
. precluded from the future deferral ofcosts or decoupled revenues not recovered through rates at the time such
amounts are incurred, even if the Company expected to recover these amounts from customers in the future.
Unamortized Debt kpense
Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt.
FERC FORM NO.1 (ED. 12-88)Page 123.7
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) _ A Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Unamortized Gain/Loss on Reacquired Debt
For the Company's Washington regulatory jurisdiction and for any debt repurchases beginning in2007 in alljurisdictions, premiums
or discounts 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 amounts are amortized over the life of the new debt. In the Company's other regulatory
jurisdictions, premiums or discounts 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. The premiums and discounts are recovered or
returned to customers through retail rates as a component ofinterest expense.
Appropriated Retain ed Earnings
In accordance with the hydroelectric licensing requirements of section I 0(d) of the Federal Power Act (FPA), the Company maintains
an appropriated retained eamings account for any earnings in excess of the specified rate of return on the Company's investment in the
licenses for its various hydroelectric projects. Per section l0(d) of the FPA, the Company must maintain these excess earnings in an
appropriated retained eamings account until the termination of the licensing agreements or apply them to reduce the net investment in
the licenses of the hydroelectric projects at the discretion of the FERC. The Company tlpically calculates the eamings in excess of the
specified rate ofreturn on an annual basis, usually during the second quarter.
The appropriated retained eamings amounts included in retained earnings were as follows as of December 3l (dollars in thousands):
2016 20r 5
Appropriated retained eamings $ 23,869 $ 19,428
Operating Leuses
The Company has multiple lease arrangements involving various assets, with minimum terms ranging from I to 45 years. Future
minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one year
were not material as of December 3l ,2016.
Equity in Earnings (Losses) of Subsidiaries
The Company records all the eamings (losses) from its subsidiaries under the equity method. The Company had the following equity in
earnings (losses) of its subsidiaries for the years ended December 3 I (dollars in thousands):
2016 2015
Avista Capital
Alaska Energy and Resources Company
Total equity in eamings of subsidiary companies
$(1,434) $
7,723
4,857
6,308
$ 6,289 $ r r,r 65
Subsequent Events
Management has evaluated the impact of events occurring after December 31,2016 up to February 21,2077 , the date that Avista
Corp.'s U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through March3l,2017
These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
Contingencies
The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss
contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated.
The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a material loss
FERC FORM NO.1 (ED.12-88)Page 123.8
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
may be incurred. As of December 3 I , 20 I 6, the Company has not recorded any significant amounts related to unresolved
contingencies. See Note l6 for further discussion of the Company's commitments and contingencies.
NOTE 2. NEW ACCOUNTING STANDARDS
ASU No. 201 4-09, "Revenue from Contracts with Customers (Topic 606)"
In May 2014,the FASB issued ASU No. 2014-09, which outlines a single comprehensive model for entities to use in accounting for
revenue arising from contracts with customers and supersedes most current revenue recognition guidance, including industry-specific
guidance. The core principle of the revenue model is that an entity should identify the various performance obligations in a contract,
allocate the transaction price among the performance obligations and recognize revenue when (or as) the entity satisfies each
performance obligation. This ASU was originally effective for periods beginning after December 15, 2016 and early adoption was not
permitted. In August 2015, the FASB issued ASU No. 2015-14, "Revenue from Contracts with Customers (Topic 606): Defenal of the
Effective Date," which deferred the effective date of ASU No. 2014-09 for one year, with adoption as of the original date permitted.
The Company has formed a revenue recognition standard implementation team that is working through several implementation issues
described below. The Company has evaluated this standard and is planning to adopt this standard in 201 8 upon its effective date. The
Company is currently expecting to use a modified retrospective method of adoption, which would require a cumulative adjustment to
opening retained eamings, as opposed to a full retrospective application. The Company is not far enough along in the adoption process
to determine the amount, if any, of cumulative adjustment necessary.
Since the vast majority of Avista Corp.'s revenue is from rate-regulated sales of electricity and natural gas to retail customers and
revenue is recogrized as energy is delivered to these customers, the Company does not expect a significant change in operating
revenues or net income. The Company is in the process of reviewing and analyzing certain contracts with customers (most of which are
related to wholesale sales ofpower and natural gas), but has not yet identified any significant differences in revenue recognition
between current GAAP and ASU 2014-09.
During the implementation process, the Company has identified several unresolved issues, the most significant of which are as follows
based on our current assessment:
Contributions in Aid o.f Construction - There is the potential that CIACs could be recognized as revenue upon the adoption of ASU
2014-09. Under current GAAP, CIACs are accounted for as an offset to the cost of utility plant in service.
Utilitv Related Taxes Collected_fron Customers - There are questions on the presentation of utility related taxes collected from
customers (primarily state excise taxes and city utility taxes) on a gross basis. Under current GAAP, the Company is allowed to record
these utility related taxes on a gross basis in revenue when billed to customers with an offset included in taxes other than income taxes
in operating expenses. The Company is evaluating whether this presentation is appropriate under ASU 2014-09 or whether they should
be presented on a net basis. To qualifl, for gross presentation under the new guidance, the Company must perform an analysis to
determine if it is the principal or the agent in regards to utility related taxes.
Collectibility - There are questions regarding the requirement that collection of a sale be probable and how, or if, utilities should
consider bad debt collection mechanisms (riders, base rate adjustments, etc.) in assessing probability of collection on sales to low
income customers. Within the utility industry, there is support for and against considering these recovery mechanisms ufien assessing
collectibility of a sale. If the bad debt recovery mechanisms cannot be considered, there is the potential that certain sales to low income
customers cannot be recognized as revenue until payment is received from the customers, which could result in revenues being
recognized in periods other than when the energy was delivered to customers or not recognized at all.
The Company is monitoring utility industry implementation guidance as it relates to unresolved issues to determine if there will be an
FERC FORM NO.1 (ED. 12-88)Page 123.9
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03l3'U2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
industry consensus regarding accounting and presentation ofthese items.
ASU No. 2016-02 "Leases (fopic 842)."
In February 2016, the FASB issued ASU No. 2016-02. This ASU introduces a new lessee model that requires most leases to be
capitalized and shown on the balance sheet with corresponding lease assets and liabilities. The standard also aligns certain ofthe
underlying principles of the new lessor model with those in Topic 606, the FASB's new revenue recognition standard. Furthermore,
this ASU addresses other issues that arise under the current lease model; for example, eliminating the required use of bright-line tests
in current GAAP for determining lease classification (operating leases versus capital leases). This ASU also includes enhanced
disclosures surrounding leases. This ASU is effective for periods beginning on or after December I 5, 201 8; however, early adoption is
permitted. Upon adoption, this ASU must be applied using a modified retrospective approach to the earliest period presented, which
will likely require restatements of previously issued financial statements. The modified retrospective approach includes a number of
optional practical expedients that entities may elect to apply. The Company evaluated this standard and determined that it will most
likely not early adopt this standard before its effective date in 2019. The Company has formed a lease standard implementation team
that is working through the implementation process. The most significant implementation challenge identified thus far relates to
identi$ing a complete population of leases and potential leases under the new lease standard. Also, the Company is monitoring utility
industry implementation guidance as it relates to several unresolved issues to determine if there will be an industry consensus,
including whether right-of-ways are considered leases. The Company cannot, at this time, estimate the potential impact on its future
financial condition, results of operations and cash flows.
ASU No. 2016-09 "Compensation-StockCompensation (Topic 718): Improvements to Employee Share-Based Payment Accounting."
In March 2016,lhe FASB issued ASU No. 2016-09. This ASU simplifies several aspects of the accounting for employee share-based
payment transactions including:
r allowing excess tax benefits or tax deficiencies to be recognized as income tax benefits or expenses in the Statements of
Income rather than in Additional Paid in Capital (APIC),
. excess tax benefits no longer represent a financing cash inflow on the Statements of Cash Flows and instead will be included
as an operating activity,
. excess tax benefits and tax deficiencies will be excluded from the calculation ofdiluted earnings per share, whereas under
current accounting guidance, these amounts must be estimated and included in the calculation,
o allowing forfeitures to be accounted for as they occur, instead of estimating forfeitures, and
o changing the statutory tax withholding requirements for share-based pal,rnents.
This ASU is effective for periods beginning after December 15,2016 and early adoption is permitted. The Company early adopted this
standard during the second quarter of20l6, with a retrospective effective date ofJanuary 1,2016. The adoption ofthis standard
resulted in a recognized income tax benefit of $1.6 million in2016 associated with excess tax benefits on settled share-based employee
payments. In addition, the Statement of Cash Flows for 20 I 6 included the excess tax benefits as an operating activity rather than as a
financing activity. Periods prior to 20 I 6 were not restated for the adoption ofthis accounting standard as the Company has adopted this
standard on a prospective basis beginning January 1,2016.
ASU No. 2017-07 "Compensation-Retirement Benefits (Topic 715): Improvingthe Presentation of Net Periodic PensionCost and
Net Periodic Postretirement Benefit Cost"
In March 2017,the FASB issued ASU No. 2017-07, which amends the income statement presentation of the components of net period
benefit cost for an entity's defined benefit pension and other postretirement plans. Under current GAAP, net benefit cost consists of
several components that reflect different aspects of an employer's financial arrangements as well as the cost of benefits eamed by
FERC FORM NO.1 (ED. 12-88)Pase 123.10
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
20't6tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
employees. These components are aggregated and reported net in the financial statements. ASU 201 7-07 requires entities to ( I )
disaggregate the current-service-cost component from the other components ofnet benefit cost (other components) and present it with
other current compensation costs for related employees in the income statement and (2) present the other components elsewhere in the
income statement and outside of income from operations.
In addition, only the service-cost component of net benefit cost is eligible for capitalization (e.g., as part of property, plant, and
equipment). This is a change from current practice, under which entities capitalize the aggregate net benefit cost when applicable.
Because Avista Corp. is a rate-regulated entity and all components of net benefit cost are required to be capitalized within utility plant
when applicable, this will result in a Regulatory/CAAP difference because for GAAP, the other components of net benefit cost will be
capitalized as regulatory assets (because they are still allowable costs) but for regulatory reporting, they will be included in utility
plant.
This ASU is effective for periods beginning after December 15,2017 and early adoption is permitted. Upon adoption entities must use
a retrospective transition method to adopt the requirement for separate presentation in the income statement and a prospective
transition method to adopt the requirement to limit the capitalization of benefit costs to the service cost component. The Company
evaluated this standard and does not expect to early adopt this standard. Also, the Company is still evaluating the impact to its financial
statements upon adoption of this standard.
NOTE 3. BUSINESS ACQUISITIONS
Alaska Energlt ond Resources Company
On July 1,2014, the Company acquired AERC, based in Juneau, Alaska, and as of that date, AERC became a wholly-owned subsidiary
of Avista Corp.
The primary subsidiary of AERC is AEL&P, a regulated utility which provides electric services to approximately 17,000 customers in
Juneau, Alaska. In addition to the regulated utility, AERC owns AJT Mining, which is an inactive mining company holding certain
properties.
The purpose of the acquisition was to expand and diversiff Avista Corp.'s energy assets and deliver long-term value to its customers,
communities and investors.
In connection with the closing, Avista Corp. issued 4,501,441 new shares of common stock to the shareholders of AERC based on a
conffactual formula that resulted in a price of $32.46 per share, reflecting a purchase price of $170.0 million, plus acquired cash, less
outstanding debt and other closing adjustments. Avista Corp. also paid $4.8 million in cash. The total fair value of all consideration
transferred was $154.9 million and resulted in goodwill of $52.4 million, which is not deductible for tax purposes.
The majority of AERC's operations are subject to the rate-setting authority of the RCA and are accounted for pursuant to CAAP,
including the accounting guidance for regulated operations. The rate-setting and cost recovery provisions currently in place for
AERC's regulated operations provide revenues derived from costs, including a return on investment, of assets and liabilities included
in rate base. Due to this regulation, the fair values of AERC's assets and liabilities subject to these rate-setting provisions were
assumed to approximate their carrying values. There were not any identifiable intangible assets associated with this acquisition. The
excess ofthe purchase consideration over the estimated fair values ofthe assets acquired and liabilities assumed was recognized as
goodwill at the acquisition date. The goodwill reflects the value paid for the expected continued growth ofa rate-regulated business
located in a defined service area with a constructive regulatory environment, the attractiveness of stable, growing cash flows, as well as
providing a platform for potential future growth outside of the rate-regulated electric utility in Alaska and potential additional utility
investment.
FERC FORM NO. 1 (ED.12-88)Pase 1 23.1 1
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t20't7
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 4. DISCONTII{UED OPERATIONS
On June 30,2014, Avista Capital, completed the sale of its interest in Ecova to Cofely USA lnc., an unrelated party to Avista Corp.
The sales price was $335.0 million in cash, less the payment of debt and other customary closing adjustments. At the closing of the
transaction on June 30,2014, Ecova became a wholly-owned subsidiary of Cofely USA Inc. and the Company has not had and will not
have any further involvement with Ecova after such date.
The purchase price of $335.0 million, as adjusted, was divided among all the security holders of Ecova pro rata based on ownership.
After consideration of all escrow amounts received, the sales transaction provided cash proceeds to Avista Corp., net of debt, payment
to option and minority holders, income taxes and transaction expenses, of $143.7 million, and resulted in a net gain of $74.8 million.
Almost all of the net gain was recognized in 2014 with some true-ups during 2015.
NOTE 5. DERIVATIVES ATID RISK MANAGEMENT
E ner gt C o mmo dily D e r ivatives
Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices.
Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by
supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista
Corp. utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these
commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks.
As part of the Company's resource procurement and management operations in the electric business, the Company engages in an
ongoing process of resource optimization, which involves the economic selection from available energy resources to serve the
Company's load obligations and the use of these resources to capture available economic value. The Company transacts in wholesale
markets by selling and purchasing electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity,
energy and fuel. Such transactions are part ofthe process ofmatching resources with load obligations and hedging the related financial
risks. These transactions range from terms of intra-hour up to multiple years.
As part of its resource procurement and management of its natural gas business, the Company 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 the Company's distribution system. However, daily variations in natural gas demand can be significantly different than monthly
demand projections. On the basis of these projections, the Company plans and executes a series of transactions to hedge a portion of its
projected natural gas requirements through forward market transactions and derivative instruments. These transactions may extend as
much as four natural gas operating years (November through October) into the future. Avista Corp. also leaves a significant portion of
its natural gas supply requirements unhedged for purchase in short-term and spot markets.
The Company is required to plan for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day
event. The Company generally has more pipeline and storage capacity than what is needed during periods other than a peak day. The
Company optimizes its natural gas resources by using market opportunities to generate economic value that helps mitigate fixed costs.
Avista Corp. also optimizes its natural gas storage capacity by purchasing and storing natural gas when prices are traditionally lower,
typically in the summer, and withdrawing during higher priced months, typically during the winter. However, if market conditions and
prices indicate that the Company should buy or sell natural gas during other times in the year, the Company engages in optimization
transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to, wholesale market
sales ofsurplus natural gas supplies, purchases and sales ofnatural gas to optimize use ofpipeline and storage capacity, and
participation in the transportation capacity release market.
FERC FORM NO.1 (ED.12-88)Paqe 123.12
Name of Respondent
Avista CorDoration
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table presents the underlying energy commodity derivative volumes as of December 31,2016 that are expected to be
settled in each respective year (in thousands of MWhs and mmBTUs):
Purchases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives
Physical (l )
MWl'
Financial (l)
MWh
Physical ( I )
mmBTUs
Financial (l )
mmBTUs
Physical (1 )
MWh
Financial ( I )
MWh
Physical ( I )
mmBTUs
Financial (l )
mmBTUsYear
2017
201 8
2019
2020
2021
Thereafter
510
397
235
907 15,475 I 10,380
52,755
29,475
2,725
3r6
286
t58
1,552
1,244
982
4,165
1,360
1,345
1,430
1,060
73,110
I 5,1 l3
4,020610
910
The following table presents the underlying energy commodity derivative volumes as of December 3 1 , 20 I 5 that were expected to be
settled in each respective year (in thousands of MWhs and mmBTUs):
Purchases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Cas Derivatives
Physical (l) Financial (l) Physical (l) Financial (l) Physical (l) Financial (l) Physical (l) Financial (l)
MWh MWh mmBTUs mmBTUs MWh MWh mmBTUs mmBTUsYear
2016
2017
2018
2019
2020
Thereafter
1,954
97
17,252
675
305
455
2,656
483
3,182
1,360
r,360
1,345
1,430
1,060
112,233
26,965
2,739
407
397
397
23s
142,693
49,200
l5,l I 8
6,935
90s
280
255
286
r58
(1) Physical transactions represent commodity transactions in which Avista Corp. will take or make delivery of either electricity or
natural gas; financial transactions represent derivative instruments with delivery of cash in the amount of benefit or cost but with
no physical delivery of the commodity, such as futures, swaps, options, or forward contracts.
The electric and natural gas derivative contracts above will be included in either power supply costs or natural gas supply costs during
the period they are settled and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case
process, and are expected to be collected through retail rates from customers. Any transactions that result in gains will be used to
reduce retail rates charged to customers in the future.
Foreign Currenqt Exchange Deilvatives
A significant portion of Avista Corp.'s natural gas supply (including fuel for power generation) is obtained from Canadian sources.
Most ofthose transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.'s short-term
natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled
within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreigr currency risk by purchasing Canadian currency exchange
derivatives when such commodity transactions are initiated. The foreign currency exchange derivatives and the unhedged foreign
currency risk have not had a material effect on the Company's financial condition, results of operations or cash flows and these
FERC FORM NO. 1 (ED.12-88)Page 123.13
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2\ _A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t20't7
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking.
The following table summarizes the foreign currency hedges that the Company has entered into as of December 31 (dollars in
thousands):
20t6 201 5
Number of contracts
Notional amount (in United States dollars)
Notional amount (in Canadian dollars)
$
2t
2,819 $
3,754
24
1,463
2,002
Interest Rate Swap Dertvafives
Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. The
Company hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swap
derivatives and U.S. Treasury lock agreements. These interest rate swap derivatives 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 unsettled interest rate swap derivatives that the Company has outstanding as of the balance sheet
date indicated below (dollars in thousands):
Balance Sheet Date Number of Contracts Notional Amount
Mandatory Cash Settlement
Date
December 31,2016 75,000
275,000
70,000
20,000
60,000
2017
20r8
2019
2020
2022
6
14
6
2
5
December 31,2015 6
3
1l
2
I
I 15,000
45,000
24s,000
30,000
20,000
2016
2017
20r 8
2019
2022
During the third quarter 2016, in connection with the execution of a purchase agreement for bonds that the Company issued in
December 2016,the Company cash-settled seven interest rate swap derivatives (notional aggregate amount of $125.0 million) and paid
a total of $54.0 million. The interest rate swap derivatives were settled in connection with the pricing of $175.0 million of Avista Corp.
first mortgage bonds that were issued in December 201 6 (see Note I 2). Upon settlement of interest rate swap derivatives, the cash
payments made or received are recorded as a regulatory asset or liability and are subsequently amortized as a component of interest
expense over the life ofthe associated debt. The settled interest rate swap derivatives are also included as a part ofthe Company's cost
of debt calculation for ratemaking purposes.
The fair value ofoutstanding interest rate swap derivatives can vary significantly from period to period depending on the total notional
amount of swaps outstanding and fluctuations in market interest rates compared to the interest rates fixed by the swaps. The Company
would be required to make cash payments to settle the interest rate swap derivatives if the fixed rates are higher than prevailing market
rates at the date of settlement. Conversely, the Company receives cash to settle its interest rate swap derivatives when prevailing
FERC FORM NO.1 (ED. 12{,81 Page'123.14
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
market rates at the time of settlement exceed the fixed swap rates.
Summary of Outstanding Derivative Instrununts
The amounts recorded on the Balance Sheet as of Decembet 31,2016 and December 31, 2015 reflect the offlsetting of derivative assets
and liabilities where a legal right of offset exists.
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 3 l,
2016 (in thousands):
Fair Value
Derivative and Balance Sheet Location
Gross
Asset
Gross
Liability
Collateral
Netting
Net Asset
(Liability)
in Balance
Sheet
Foreign currency exchange derivatives
Derivative instrument liabilities current
Interest rate swap derivatives
Derivative instrument assets current
Long-term portion of derivative assets
Derivative instrument liabilities current
Long-term portion of derivative liabilities
Energy commodity derivatives
Derivative instrument assets current
Derivative instrument liabilities current
Long-term portion of derivative liabilities
Total derivative instruments recorded on the balance sheet
Derivative and Balance Sheet location
$s $ (28)$
3,393
5,754 (3e7)
(15,7s6)
(s7,82s)3,9s1
$ (23)
18,682
16,335
13,071
(16,787)
(29,598)
(29990)
9,731
25,169
6,228
3,630
3,393
5,357
(6,025)
(28,705)
1,895
(7,035)
(t 3,289)
$ 6l,19l $ (1s0,381) $ 44,7s8 $ (44,432)
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2015 (in thousands):
Fair Value
Gross
Asset
Gross Collateral
Liability Netting
Net Asset
(Liability)
in Balance
Sheet
Foreign currency exchange derivatives
Derivative instrument liabilities current
Interest rate swap derivatives
Long-term portion of derivative assets
Derivative instrument liabilities current
Long-term portion of derivative liabilities
Energy commodity derivatives
Derivative instrument assets current
Derivative instrument Iiabilities current
Long-term portion of derivative liabilities
$2 $ (le)$
1,236
67,466
6,613
(23,262)
(62,236)
(5s3)
(8s,409)
(39,033)
3,880
30, l 50
3,675
10,851
$ (17)
23
(19,264)
(30,679)
683
(14,268)
(21,569)
23
ll8
1,407
FERC FORM NO.1 ED.1 123.15
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t20'.t7
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Total derivative instruments recorded on the balance sheet $ 76,865 $ (210,512) $ 48,556 $ (85,091)
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 ofthe contract through cash settlement, in the event of a downgrade in the Company's credit
ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden
and significant demands may be made against the Company's credit facilities and cash. The Company actively monitors the exposure to
possible collateral calls and takes steps to mitigate capital requirements.
The following table presents the Company's collateral outstanding related to its derivative instruments as of as of December 3l (in
thousands):
2016 2015
Energy commodity derivatives
Cash collateral posted
Letters of credit outstanding
Balance sheet offsetting (cash collateral against net derivative positions)
Interest rate swap derivatives
Cash collateral posted
Letters of credit outstanding
Balance sheet offsetting (cash collateral against net derivative positions)
Energy commodity derivatives
Liabilities with credit-risk-related contingent features
Additional collateral to post
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features
Additional collateral to post
NOTE 6. JOINTLY OWI\IED ELECTRIC FACILITIES
$t7,134 $
24,400
9,858
28,716
28,200
14,526
34,900 34,030
3,600 9,600
34,900 34,030
Certain of the Company's derivative instruments contain provisions that require the Company to maintain an "investment grade" credit
rating from the major credit rating agencies. If the Company's credit ratings were to fall below "investment grade," it would be in
violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand
immediate and ongoing collateralization on derivative instruments in net liability positions.
The following table presents the aggregate fair value of all derivative insffuments with credit-risk-related contingent features that are in
a liability position and the amount of additional collateral the Company could be required to post as of December 31 (in thousands):
2016 2015
$1,124 $
1,046
7,090
6,980
85,498
18,750
73,978
2r,r00
The Company has a l5 percent ownership interest in a twin-unit coal-fired generating facility, Colstrip, located in southeastern
Montan4 and provides furancing for its ownership interest in the project. The Company's share of related fuel costs as well as
operating expenses for plant in service are included in the corresponding accounts in the Statements of Income. The Company's share
FERC FORM NO.1 (ED.12€8)Page 123.16
Name of Respondent
Avista Corporation
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o3t3112017
Year/Period of Report
2016tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
of utility plant in service for Colstrip and accumulated depreciation (inclusive of the ARO assets and accumulated amortization) were
as follows as of December 31 (dollars in thousands):
20t6 201 5
Utility plant in service
Accumulated depreciation
See Note 7 for further discussion of AROs.
NOTE 7. ASSET RETIREMENT OBLIGATIONS
$ 380,406 $
(249,359)
362,199
(243,363)
The Company has recorded liabilities for future AROs to:
. restore coal ash containment ponds at Colship,
. cap a landfill at the Kettle Falls Plant,
. remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease, and
. dispose of PCBs in certain transformers.
Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:
. removal and disposal of certain transmission and distribution assets, and
o abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.
On April 17,2015, the EPA published a final rule regarding coal combustion residuals (CCR), also termed coal combustion
byproducts or coal ash, in the Federal Register, and this rule became effective on October 15,2015. Colstrip, of which Avista Corp. is
a 15 percent owner of units3 & 4, produces this byproduct. The rule established technical requirements for CCR landfills and surface
impoundments under Subtitle D of the Resource Conservation and Recovery Act, the nation's primary law for regulating solid
waste. The Company, in conjunction with the other Colstrip owners, developed a multi-year compliance plan to strategically address
the CCR requirements and existing state obligations while maintaining operational stability. During 2015, the operator of Colstrip
provided an initial cost estimate of the expected retirement costs associated with complying with the new CCR rule. Based on the
initial assessments, Avista Corp. recorded an increase to its ARO of $12.5 million during 2015 with a corresponding increase in the
cost basis of the utility plant. During 2016, due to additional information and updated estimates, the ARO increased to $13.6 million
(including accretion of $0.7 million).
The actual asset retirement costs related to the CCR rule requirements may vary substantially from the estimates used to record the
increased ARO due to uncertainty about the compliance strategies that will be used and the preliminary nature of available data used to
estimate costs, such as the quantity of coal ash present at certain sites and the volume of fill that will be needed to cap and cover certain
impoundments. Avista Corp. will coordinate with the plant operator and continue to gather additional data in future periods to make
decisions about compliance strategies and the timing of closure activities. As additional information becomes available, Avista Corp.
will update the ARO for these changes in estimates, which could be material. The Company expects to seek recovery of any increased
costs related to complying with the new rule through customer rates.
The following table documents the changes in the Company's asset retirement obligation during the years ended December 31 (dollars
in thousands):
20t6 2015
Asset retirement obligation at beginning of year $ 15,997 $ 3,028
FERC FORM NO.1 (ED. 12-881 Page 123.17
Name of Respondent
Avista Comoration
This Report is:
(1) X An Original
(2) _A Resubmission
Date of Report
(Mo, Da, Yr)
03t3'U2017
Year/Period of Report
20161Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Liabilities incurred
Liabilities settled
Accretion expense
Asset retirement obligation at end of year
430
(1,529)
617
12,539
(2e)
459
$ 15,515 $ 15,997
NOTE 8. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering the majority of all regular full-time employees at Avista Corp. that were
hired prior to January l,2014.Individual benefits under this plan are based upon the employee's years of service, date of hire and
average compensation as specified in the plan. Non-union employees hired on or after January 1,2014 participate in a defined
contribution 401(k) plan in lieu of a defined benefit pension plan. The Company's funding policy is to contribute at least the minimum
amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts
that are currently deductible for income tax purposes. The Company conhibuted $12.0 million in cash to the pension plan in 2016,
$12.0 million in 2015 and $32.0 million in2014. The Company expects to contribute $22.0 million in cash to the pension plan in
2017.
The Company also has a SERP that provides additional pension benefits to executive officers and certain key employees of the
Company. The SERP is intended to provide benefits to individuals whose benefits under the defined benefit pension plan are reduced
due to the application 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):
201'7 201 8 2019 2020 2021 Total2022-2026
Expected benefit payments $ 30,971 $ 32,014 $ 33,047 $ 34,545 $ 35,892 $ 196,322
The expected long-term rate ofreturn on plan assets is based on past performance and economic forecasts for the types ofinvestments
held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with
maturities similar to that of the expected term of pension benefits.
The Company provides certain health care and life insurance benefits for eligible retired employees that were hired prior to January l,
2014.The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services.
The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January l,
2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution toward
their medical premium.
The Company has a Health Reimbursement Arrangement (HRA) to provide employees with tax-advantaged funds to pay for allowable
medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee's years
of service and the ending salary. The liability and expense of the HRA are included as other postretirement benefits.
The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement.
Under the plan, an executive officer's designated beneficiary will receive a payment equal to twice the executive officer's annual base
salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer's total annual pension
benefit). The liability and expense for this plan are included as other postretirement benefits.
The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):
2017 201 8 2019 2020 2021 Total2022-2026
FERC FORM NO.1 1 123.18
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Expected benefit payments $ 6,991 $ 7,302 $ 7,580 $ 6,479 $ 6,675 S 34,704
The Company expects to contribute $7.0 million to other postretirement benefit plans in 2017, representing expected benefit payments
to be paid during the year excluding the Medicare Part D subsidy. The Company uses a December 3l measurement date for its pension
and other postretirement benefit plans.
The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2076 and 2015 and the
components ofnet periodic benefit costs forthe years ended December 37,2076,2015 and 2014 (dollars in thousands):
Pension Benefits
Other Post-
retirement Benefits
20t6 20t 5 20t6 20t5
Change in benefit obligation:
Benefit obligation as of beginning of year
Service cost
Interest cost
Actuarial (gain)/loss
Plan change
Cumulative adjustment to reclassifu liability
Benefits paid
Benefit obligation as ofend ofyear
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
6r 3,503 $
18,302
27,544
39,997
138,795 $
3,205
6,1l0
(3,648)
$634,674 $
19,791
26,117
(35,790)
(228)
127,989
) a)\
5,1 58
12,668
(1,000)
(1,521)
(7,424)(32,874) (31,061)
(1,042)
(6,967)
$ 666,472 $ 613,503 $ 136,453 $ 138,795
$539,31 I $
(4,305)
12,000
(29,772)
30,868 $
2,497
517,234 S
43,212
12,000
(31,532)
31,312
(444)
$ 540,914 $ 517,234 $ 33,365 $ 30,868
$ (12s,s58) $ (e6,26e) $ (103,088) $ (107,e27)
178,783
23
162,961
25
81,979
(8,e8 r )
92,433
(10,180)
53,248
(1 78,806)
66,717
(162,986)
(30,090)
(72,998)
(25,674)
(82,2s3)
$ (r25,ss8) s (e6,26e) $ (103,088) $ (107,e27)
Accumulated pension benefi t obligation $ 583,498 $ 542,209
Accumulated postretirement benefit obligation:
For retirees
For fully eligible employees
For other participants
Included in accumulated other comprehensive loss (income) (net of tax):
Unrecognized prior service cost $ 15 $
$
$
$
60,670
34,429
41,354
65,652
34,498
38,645
$
$
$
16 $ (5,8s4)$ (6,617)
FERC FORM NO.1 (ED. 12.881 Page '123.19
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t20't7
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Unrecognized net acfuarial loss
Total
Less regulatory asset
Accumulated other comprehensive loss for unfunded benefit
obligation for pensions and other postretirement benefit
plans
116,209 10s,925 53,303 60,081
116,224
(108,903)
105,941
(99,414)
47,449
(47,202)
53,464
(53,34 I )
$ 7,321 $ 6,527 $247 $123
Pension Benefits
Other Pos!
retirement Benefits
2016 2015 2016 201 5
Weighted-average assumptions as of December 3l:
Discount rate for benefit obligation
Discount rate for annual expense
Expected long-term retum 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
Components of net periodic benefit cost:
Service cost
Interest cost
Expected refurn on plan assets
Amortization of prior service cost
Net loss recognition
Net periodic benefit cost
4.26Yo
4.57%
5.400h
4.78o/o
4.57%
4.21%
s.30%
4.87%
Pension Benefits
4.23%
4.57%
6.03%
7.00%
5.00%
2023
7.00%
5.00%
2024
Other Post-
retirement Benefits
4.57o/o
4.16%
6.360/o
7.00%
5.00%
2022
7.00%
5.000/o
2023
2016 201 5 2016 20 l5
$ 18,302 $
27,544
(27,547)
2
8,51 1
19,791 $
26,117
(28,299))
2
9,451
3,205 $
6,1 l0
( 1,861)
(1,208)
5,728
) o)\
5,158
(1,991)
(1, I 99)
5,095
$ 26,812 g 27,062 $ 11,974 $ 9,988
Plan Assets
The Finance Committee of the Company's Board of Directors approves investment policies, objectives and skategies that seek an
appropriate return forthe pension plan and other postretirement benefit plans and reviews and approves changes to the investment and
funding policies.
The Company has contracted with investment consultants who are responsible for managing/monitoring the individual investment
managers. The investment managers' performance and related individual fund performance is periodically reviewed by an internal
FERG FORM NO.1 (ED.12.88)Pase 123.20
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies.
Pension plan assets are invested in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate,
absolute return and commodity funds. In seeking to obtain the desired retum to fund the pension plan, the investment consultant
recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which
then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation
percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are tlpically
the midpoint of the established range. The target investment allocation percentages by asset classes are indicated in the table below:
2016 20ls
Equity securities
Debt securities
Real estate
Absolute retum
37%
45%
8o/o
10Yo
27%
s8%
6%
9Yo
The 2016 target investment allocation percentages were revised in the fourth quarter of2016 and the pension plan assets were
subsequently reinvested during the fourth quarter of 2016 and first quarter of 2017 to move toward the new target investment
allocation percentages. The target asset allocation percentages were modified to better align the asset allocations with the funded status
of the pension plan. Future contributions to the plan will also be increased to improve the funded status of the plan.
The fair value of pension plan assets invested in debt and equity securities was based primarily on fair value (market prices). The fair
value of investment securities traded on a national securities exchange is determined based on the reported last sales price; securities
traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not
readily available or for which market prices do not represent the value at the time of pricing, the investment manager estimates fair
value based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and industry).
Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit value of the
fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund's net assets by its units
outstanding at the valuation date. The Company's investments in common/collective trusts have redemption limitations that permit
quarterly redemptions following notice requirements of 45 to 60 days. The fair values of the closely held investments and partnership
interests are based upon the allocated share ofthe fair value ofthe underlying assets as well as the allocated share ofthe undistributed
profits and losses, including realized and unrealized gains and losses. Most of the Company's investments in closely held investments
and partnership interests have redemption limitations that range from bi-monthly to semi-annually following redemption notice
requirements of 60 to 90 days. One investment in a partnership has a lock-up for redemption currently expiring in 2022 and is subject
to extension.
The fair value of pension plan assets invested in real estate was determined by the investment manager based on three basic
approaches:
. properties are extemally appraised on an annual basis by independent appraisers, additional appraisals may be
performed as warranted by specific asset or market conditions,
. property valuations are reviewed quarterly and adjusted as necessary, and
o loans are reflected at fair value.
The fair value of pension plan assets was determined as of December 31,2016 and2075.
Pension plan other postretirement plan assets whose fair values are measured using net asset value (NAV) are excluded from the fair
FERC FORM NO. 1 (ED.12-88)Page 123.21
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale) A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
value hierarchy and are included as reconciling items in the tables below.
The following table discloses by level within the fair value hierarchy (see Note 14 for a description ofthe fair value hierarchy) of the
pension plan's assets measured and reported as of December 3 I , 201 6 at fair value (dollars in thousands):
Levell Level2 lrvel3 Total
Cash equivalents $
Fixed income securities:
U.S. government issues
Corporate issues
lntemational issues
Municipal issues
Mutual funds:
U.S. equity securities
lntemational equity securities
Absolute retum (l)
Plan assets measured at NAV (not subject to hierarchy disclosure)
Common/col lective trusts:
Real estate
Intemational equity securities
Partnership/closely held investments:
Absolute retum (l)
Private equity funds (2)
Real estate
$ 10,179 $$ 10,179
Total $ 157,503 $ 287,694 $$ 540,914
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of the
pension plan's assets measured and reported as of December 31,2015 at fair value (dollars in thousands):
Level I l*vel? Level 3 Total
30,919
193,563
34,145
18,888
30,919
193,563
34,145
18,888
120,856
30,025
6,622
19,779
29,140
39,077
72
7,649
r20,856
30,025
6,622
Cash equivalents S
Fixed income securities:
U.S. government issues
Corporate issues
lnternational issues
Municipal issues
Mutual funds:
U.S. equity securities
Intemational equity securities
Absolute return (l)
Plan assets measured at NAV (not subject to hierarchy disclosure)
Commor/co I lective trusts :
87,678
40,343
13,996
86 $ 10,641 $
47,845
187,308
34,458
22,416
$ 10,727
47,845
187,308
34,458
22,416
87,678
40,343
13,996
FERC FORM NO. 1 (ED.12.88)Paqe 123.22
Name of Respondent
Avista Cor,poration
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Real estate
Partnership/closely held investments:
Absolute return (l)
Private equity funds (2)
Real estate
Total
Cash equivalents
Mutual funds:
Fixed income securities
U.S. equity securities
lntemational equity securities
Total
24,147
38,302
73
9,941
(2)
$ 142,103 $ 302,668 $$ 517,234
(1)This category invests in multiple strategies to diversifr risk and reduce volatility. The strategies include: (a) event driven,
relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and
(d) market neutral strategies.
This category includes private equity funds that invest primarily in U.S. companies.
The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on market prices. The fair
value ofinvestment securities traded on a national securities exchange is determined based on the last reported sales price; securities
traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not
readily available are fair-valued by the investment manager based upon other inputs (including valuations of securities that are
comparable in coupon, rating, maturity and industry). The target asset allocation was 60 percent equity securities and 40 percent debt
securities in both 2016 and2015.
The fair value of other postretirement plan assets was determined as of December 31, 2016 and2015.
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of other
postretirement plan assets measured and reported as of Decemb er 31 , 2016 at fair value (dollars in thousands):
Level I l-evel2 Level 3 Total
Cash equivalents
Mutual funds:
Balanced index ftmd (1)
Total
$$6$$
33,359
$ 33,359 $6$$ 33,365
(1) The balanced index fund is a single mutual fund that includes a percentage ofU.S. equity securities, fixed income securities and
International securities.
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of other
postretirement plan assets measured and reported as of December 31, 2015 at fair value (dollars in thousands):
Level I kvel 2 Level 3 Total
6
33,359
$$e$9s
12,000
13,224
5,635
12,000
13,224
5,635
$ 30,8s9 $9$$ 30,868
FERC FORM NO. 1 (ED.12-88}Page 123.23
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A one-percentage-point
increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement benefit obligation as of
December 31,2016 by $8.6 million and the service and interest cost by $1.0 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 , 201 6 by
$6.7 million and the service and interest cost by $0.7 million.
401(k) Plans and Executive Deferral Plan
Avista Corp. has a salary deferral 401(k) plans that is a defined contribution plan and covers substantially all employees. Employees
can make contributions to their respective accounts in the plans on a pre-tax basis up to the maximum amount permitted by law. The
Company matches a portion of the salary deferred by each participant according to the schedule in the respective plan.
Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):
20t6
Employer 40 1 (k) matching contributions $ 8,s5s $ 7,875
The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer
until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of
their incentive payments. Defened compensation funds are held by the Company in a Rabbi Trust.
There were deferred compensation assets and corresponding deferred compensation liabilities on the Balance Sheets of the following
amounts as of December 3l (dollars in thousands):
2016 201 5
Deferred compensation assets and liabilities $ 7,679 $ 8,093
NOTE 9. ACCOUNTING FORINCOME TAXES
Deferred income taxes reflect the net tax effects of temporary diflerences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards.
The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company
evaluated available evidence supporting the realization of its defened income tax assets and determined it is more likely than not that
deferred income tax assets will be realized.
As of December 31, 2016,the Company had $17.1 million of state tax credit carryforwards of which it is expected $7.9 million may
expire unused; the Company has reflected the net amount of $9.2 million as an asset at December 31,2016. State tax credits expire
from 2019 to2028.
The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns
in certain jurisdictions, including Idaho, Oregon and Montana. Subsidiaries are charged or credited with the tax effects of their
operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2011 and
all issues were resolved related to these years. The statute of limitations for the IRS to review the2012 tax year has expired, leaving
the 2013 through 2015 tax years still open for review. The Company believes that any open tax years for federal or state income taxes
will not result in adjustments that would be significant to the financial statements.
FERC FORM NO. 1 (ED.12-88)Page 123.24
2015
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
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):
2016 201 5
Regulatory assets for deferred income taxes
Regulatory liabilities for deferred income taxes
$109,853 $
28,966
101,240
17,609
NOTE 10. ENERGY PURCHASE CONTRACTS
Avista Corp. has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the
purchase or exchange of electric energy with other entities. The remaining term of the contracts range from one month to twenty-five
years.
Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs, which are included in utility
resource costs in the Statements of Income, were as follows for the years ended December 3l (dollars in thousands):
2016 2015
Utility power resources $ 402,575 $ 5l I,937
The following table details Avista Corp.'s future contractual commitments for power resources (including ffansmission contracts) and
natural gas resources (including transportation contracts) (dollars in thousands):
2017 2018 2019 2020 2021 Thereafter Total
Power resources
Natural gas resources
Total
$ 202,494 $
95,549
187,080 $
65,230
174,285 $
s3,860
109,878 $
41,340
96,48s $
29,306
775,548 $ 1,545,770
349,468 634,753
$ 298,043 $ 252,310 $ 228,14s $ rsr,218 $ 125,791 $ r,12s,016 $ 2,180,s23
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 fixed contractual amounts related to the Company's contracts
with certain PUDs to purchase portions of the output of certain generating facilities. Although Avista Corp. has no investment in the
PUD generating facilities, the fixed contracts obligate Avista Corp. to pay certain minimum amounts whether or not the facilities are
operating. The cost of power obtained under the contracts, including payments made when a facility is not operating, is included in
utility resource costs in the Statements of Income. The contractual amounts included above consist of Avista Corp.'s share of existing
debt service cost and its proportionate share of the variable operating expenses of these projects. The minimum amounts payable under
these contracts are based in part on the proportionate share of the debt service requirements of the PUD's revenue bonds for which the
Company is indirectly responsible. The Company's total future debt service obligation associated with the revenue bonds outstanding at
December 31,2016 (principal and interest) was $65.2 million.
In addition, Avista Corp. has operating agreements, settlements and other contractual obligations related to its generating facilities and
transmission and distribution services. The following table details future contractual commitments under these agreements (dollars in
thousands):
2017 201 8 20t9 2020 2021 Thereafter Total
Contractualobligations $ 33,922 $ 28,783 $ 32,549 $ 32,160 $ 27,019 $ 189,000 $ 343,433
FERC FORM NO.1 (ED.'12.881 Page 123.25
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 11. NOTES PAYABLE
Avista Corp.
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million. A two-year option
was exercised by the Company in 2016 to extend the maturity of the facility agreement to April 2021.
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 , 201 6, 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):
2016 2015
Balance outstanding at end ofperiod $ 120,000 $ 105,000
Letters of credit outstanding at end of period $ 34,353 $ 44,595
Average interest rate at end of period 1.50% 1.18%
As of December 31, 2016 and 2015, the borrowings outstanding under Avista Corp.'s committed line of credit were classified as
short-term borrowings on the Balance Sheet.
NOTE 12. BONDS
The following details long-term debt outstanding as of December 31 (dollars in thousands):
Maturity Interest
Year Description Rate 2016 2015
First Mortgage Bonds (1)
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 (2)
Secured Pollution Control Bonds (2)
First Mortgage Bonds
First Mortgage Bonds
First Mortgage Bonds
First Mortgage Bonds
First Mortgage Bonds
First Mortgage Bonds
First Mortgage Bonds
First Mortgage Bonds (3)
$$2016
201 8
20r 8
2019
2020
2022
2023
2028
2032
2034
2035
2037
2040
2041
2044
2045
2047
205 I
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
60,000
100,000
80,000
r 75,000
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
8s,000
60,000
100,000
80,000
0.84o/o
5.95o/o
7.39Yo-7.45o/o
5.45%
3.89%
5.130/o
7.l8Yo-7.54o/o
637%
(2)
(2)
6.25o/o
5.70%
5.55%
4.45%
4.11%
4.37%
4.23%
3.54%
FERC FORM NO.1 (ED.12{8)Paqe 123.26
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
YeariPeriod of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Total secured bonds
Secured Pollution Control Bonds held by Avista
Corporation (2)
Total long-term debt
1,621,700 l,536,700
(83,700)
$ 1,538,000 $
(83,700)
1,453,000
(l)In August 2016, Avista Corp. entered into a term loan agreement with a commercial bank in the amount of $70.0 million with
a maturity date of December 30, 2016. Loans under this agreement were unsecured and had a variable annual interest rate.
The Company borrowed the entire $70.0 million available under this agreement, which was used to repay a portion of the
$90.0 million in first mortgage bonds that matured in August 201 6. This term loan was subsequently repaid in full in
December using the proceeds from the first mortgage bonds issued in December 201 6 (discussed below).
In December 2010,$66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding
Bonds (Avista Corporation Colstrip Project) due in 2032 and2034, respectively, which had been held by Avista Corp. since
2008 and 2009, respectively, were refunded by new bond issues (Series 2010A and Series 2010B). The new bonds were not
offered to the public and were purchased by Avista Corp. due to market conditions. The Company expects that at a later date,
subject to market conditions, these bonds may be remarketed to unaffiliated investors. So long as Avista Corp. is the holder of
these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s Balance Sheets.
In December 20 I 6, Avista Corp. issued and sold $ I 75.0 million of 3.54 percent first mortgage bonds due in 205 I pursuant to
a bond purchase agreement with institutional investors in the private placement market. The total net proceeds from the sale
of the bonds were used to repay the $70.0 million term loan discussed above and to repay a portion of the borrowings
outstanding under the Company's $400.0 million committed line of credit. ln connection with the execution of the bond
purchase agreement, the Company cash-settled seven interest rate swap derivatives (notional aggregate amount of $125.0
million) and paid a total of $54.0 million.
(2)
(3)
The following table details future long-term debt maturities including advances from associated companies (see Note 13) (dollars in
thousands):
20t7 20r8 201 9 2020 202t Thereafter Total
Debt maturities $$ 272,500 $ 90,000$ 52,000$ -91,175,047 $1,589,547
Substantially all of Avista Corp.'s owned properties are subject to the lien of its mortgage indenture. Under the Mortgage and Deed of
Trust (Mortgage) securing its first mortgage bonds (including secured medium-term notes), Avista Corp. may issue additional first
mortgage bonds under its mortgage in an aggregate principal amount equal to the sum of:
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
an equal principal amount of retired first mortgage bonds which have not previously been made the basis of any application
under the Mortgage, or
deposit ofcash.
However, Avista Corp. may not issue any additional first mortgage bonds (with certain exceptions in the case of bonds issued on the
basis of retired bonds) unless it has "net eamings" (as defined in the Mortgage) for any period of 12 consecutive calendar months out
of the preceding l8 calendar months that were at least twice the annual interest requirements on all mortgage securities at the time
outstanding, including the first mortgage bonds to be issued, and on all indebtedness of prior rank. As of December 31,2016, property
additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.2 billion in
FERC FORM NO. 1 (ED.12.88)Paqe 123.27
a
a
a
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
aggregate principal amount of additional first mortgage bonds at Avista Corp.
NOTE 13. ADVAI\ICES FROIV1 ASSOCIATED COMPANIES
ln 1997, the Company issued Floating Rate Junior Subordinated Deferrable lnterest Debentures, Series B, with a principal amount of
$51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of
Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly.
The distribution rates paid were as follows during the years ended December 31:
2016 2015
Low distribution rate
High disribution rate
Distribution rate at the end of the year
7.29o/o
1.81o/o
1.81%
1.tt%
1.29o/o
1.29%
Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the
Company. These debt securities may be redeemed at the option of Avista Capital II at any time and mature on June 1,2037.ln
December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.
The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on,
and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital lI has funds available
for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust
Securities will be mandatorily redeemed.
NOTE 14. FAIRVALUE
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 1 measurements) and the lowest priority to fair values derived from
unobservable inputs (Level 3 measurements).
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 l, but which are either directly or
indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other
valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted
forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments,
as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the
full term of the instrument, can be derived from observable data or are supported by obsewable 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 best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is sigrificant to the fair value
FERC FORM NO. 1 (ED. 12-881 Page 123.28
Name of Respondent
Avista Corporation
This Report is:
(1)X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
measurement. The Company's assessment of the significance of a particular input to the fair value measurement requires judgment and
may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The determination
ofthe fair values incorporates various factors that not only include the credit standing ofthe 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 3l (dollars in thousands):
2016 201 5
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
Bonds (Level 2)
Bonds (Level 3)
Advances from associated companies (Level 3)
$951,000 $
587,000
51,547
r,048,661 $
583,073
38,660
95 t,000 $
s02,000
51,547
1,055,797
s05,768
36,083
These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market
information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The
price ranges obtained from the third party brokers consisted of par values of 75.00 to 122.59, where a par value of 100.00 represents
the carrying value recorded on the Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market prices;
however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make estimates
using comparable debt with similar risk and terms if there is no trading activity near a period end. Level 3 long-term debt consists of
private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in Level 3 are
estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and terms to
generate quotes for Avista Corp. bonds.
The following table discloses by level within the fair value hierarchy the Company's assets and liabilities measured and reported on the
Balance Sheets as of December 31,2016 and 2015 at fair value on arecurring basis (dollars in thousands):
Level I Level2 Level 3
Counterparty
and Cash
Collateral
Netting (l)Total
December 31,2016
Assets:
Energy commod ity derivatives
Level 3 energy commodity derivatives:
Natural gas exchange agreements
Power exchange agreement
Foreign currency exchange derivatives
lnterest rate swap derivatives
Deferred compensation assets:
Fixed income securities
Equity securities
$ 47,994 $$ (46,099) $ 1,89s
8,750
$
69
25
(6e)
(2s)
(5)
(4,348)
5
13,098
1,789
5,481
'l,789
5,481
FERC FORM NO. { (ED. 12.88)Page'123.29
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) - A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Total
Liabilities:
Energy commodity derivatives
Level 3 enerry commodity derivatives:
Natural gas exchange agreement
Power exchange agreement
Power option agreement
Interest rate swap derivatives
Foreign currency exchange derivatives
Total
December 31,2015
Assets:
Energy commod ity derivatives
Level 3 enerry commodity derivatives:
Natural gas exchange agreement
Foreign currency exchange derivatives
Interest rate swap derivatives
Deferred compensation assets:
Fixed income securities
Equity securities
Total
Liabilities:
Energy commodity derivatives
Level 3 enerry commodity derivatives:
Natural gas exchange agreement
Power exchange agreement
Power option agreement
Foreign currency exchange derivatives
Interest rate swap derivatives
Total
s 7,270 $ 61,097 $94 $ (50,546)$ 17,915
$$ 56,871 $$ (ss,e57) $914
73,978
28
5,954
13,474
76
(6e)
(2s)
(39,248)
(s)
5,885
13,449
76
34,730
23
$$ 130,877 $ 19,504 $ (95,304) $ 55,077
Level 1 Level2 Level 3
Counterparty
and Cash
Collateral
Netting (l)Total
$$ 74,637 $
]-
2
1,548
$ (73,es4) $ 683
(678)
(2)
1,548
1,727
5,761
678
1,727
5,761
$ 7,488 $ 76,187 $ 678 $ (74,634) $ 9,719
$$ 97,193 $$ (88,480) S 8,713
(678)
l9
85,498
$$ 182,710 $ 27,802 $ (89,160) $ 121,352
(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.
The difference between the amourt of derivative assets and liabilities disclosed in respective levels in the table above and the amount
FERC FORM NO.1 (ED.12-88)Page 123.30
5,717
21,961
124
5,039
21,961
124
t7
85,498
(2)
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
of derivative assets and liabilities disclosed on the Balance Sheets is due to netting arrangements with certain counterparties. See Note
5 for additional discussion of derivative netting.
To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to estimate
the fair value of utility derivative commodity instruments included in Level 2. ln particular, electric derivative valuations are
performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated using
New York Mercantile Exchange (IIYMEX) pricing for similar instruments, adjusted for basin differences, using market quotes. Where
observable inputs are available for substantially the full term ofthe contract, the derivative asset or liability is included in Level 2.
To establish fair values for interest rate swap derivatives, the Company uses forward market curves for interest rates for the term of the
swaps and discounts the cash flows back to present value using an appropriate discount rate. The discount rate is calculated by third
party brokers according to the terms of the swap derivatives and evaluated by the Company for reasonableness, with consideration
given to the potential non-performance risk by the Company. Future cash flows of the interest rate swap derivatives are equal to the
fixed interest rate in the swap compared to the floating market interest rate multiplied by the notional amount for each period.
To establish fair value for foreign curency derivatives, the Company uses forward market curves for Canadian dollars against the US
dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative. Forward
foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the locked-in price of
the foreign exchange contracts.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan.
These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table
above excludes cash and cash equivalents of $0.4 million as of December 31,2076 and $0.6 million as of December 31, 2015.
Level 3 Fair Value
Under the power exchange agreement the Company purchases power at a price that is based on the average operating and maintenance
(O&M) charges from three surrogate nuclear power plants around the country. To estimate the fair value of this agreement the
Company estimates the difference between the purchase price based on the future O&M charges and forward prices for energy. The
Company compares the Level 2 brokered quotes and forward price curves described above to an internally developed forward price
which is based on the average O&M charges from the three surrogate nuclear power plants for the current year. Because the nuclear
power plant O&M charges are only known for one year, all forward years are estimated assuming an annual escalation. ln 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 sunogate 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 intemal forward
price.
For the power commodity option agreement, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value,
and this model includes significant inputs not observable or corroborated in the market. These inputs include: 1) the strike price (which
is an intemally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and
other O&M charges), 2) estimated delivery volumes, and 3) volatility rates. Significant increases or decreases in any of these inputs in
isolation would result in a significantly higher or lower fair value measurement. Generally, changes in overall commodity market prices
and volatility rates are accompanied by directionally similar changes in the strike price and volatility assumptions used in the
calculation.
FERC FORM NO. 1 (ED. 12.88)Page 123.3'l
For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however,
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03131120'17
Year/Period of Report
2016tA4
NOTES TO FINANCIAL STATEMENTS (Continued)
the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions.
Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because
the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions
can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based
on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with
market prices and market volatility.
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 31,2016 (dollars in thousands):
Fair Value
(Net) at
December 31,
2016
Valuation
Technique Unobservable Input Range
Power exchange agreement $(13,449) Surrogate facility
pricing
O&M charges $33.59-$49.15/MWh (1)
Escalation factor
Transaction volumes
3% - 2017 to 2019
241,558 - 396,984 MWhs
Power option agreement (76)Black-Scholes-
Merton
Strike price $37.83/MWh - 2019
Delivery volumes
Volatility rates
$s4.40/\4wh - 2018
157,517 - 285,979 MWhs
0.20 (2)
Natural gas exchange
agreement
(5,885) Internallyderived
weighted-average
cost ofgas
Forward purchase
prices
Forward sales prices
Purchase volumes
Sales volumes
$1.83 - $3.06/mmBTU
$1.90 - $5.l4lmmBTU
I 15,000 - 310,000 mmBTUs
60,000 - 310,000 mmBTUs
( I ) The average O&M charges for the delivery year beginning in November 20 I 6 were $39 .22 per MWh. For ratemaking purposes the
average O&M charges to be included for recovery in retail rates vary slightly between regulatory jurisdictions. The average O&M
charges for the delivery year beginningin2016 were $44.33 for Washington and $39.22 for Idaho.
(2) The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.35 for 2017 to 0.26 in December 2018.
The valuation methods, significant inputs and resulting fair values described above were developed by the Company's management and
are reviewed on at least a quarterly basis to ensure they provide a reasonable estimate offair value each reporting period.
The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using sigrificant
unobservable inputs (Level 3) for the years ended December 3l (dollars in thousands):
Natural Gas
Exchange
Agreement
Power
Exchange
Agreement
Power
Option
Agreement
Year ended December 31, 2016:
Total
FERC FORM NO.1 (ED. 12-88)Paqe 123.32
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originalel A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Balance as ofJanuary 1,2016
Total gains or (losses) (realizedlunrealized):
lncluded in regulatory assets/liabilities (1)
Settlements
Ending balance as of December 31,2016 (2)
Year ended December 31, 2015:
Balance as ofJanuary 1,2015
Total gains or ( losses) (real izedlunre alized):
Included in regulatory assets/liabilities (l)
Settlements
Ending balance as of December 3 I , 2015 (2)
Dividends paid per common share
$ (s,039) $ (21,961) $ (124) $ (27,124)
259
( 1,1 05)
400
8,112
48 707
7,007
$ (s,885) $ (13,449) $ (76) $ (19,410)
$(3s)$ (23,29e)$ (424)$ (23,7s8)
(6,008)
I,004
(6,198)
7,536
300 (l 1,906)
8,540
$ (5,039) $ (21,961) $ (124) $ (27,124)
(l) All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either net
income or other comprehensive income during any of the periods presented in the table above.
(2) There were no purchases, issuances or transfers from other categories ofany derivatives instruments during the periods presented
in the table above.
NOTE 15. COMMON STOCK
The payment of dividends on cornmon stock could be limited by:
. certain covenants applicable to preferred stock (when outstanding) contained in the Company's Restated Articles of
Incorporation, as amended (cunently there are no preferred shares outstanding),
. certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements,
o the hydroelectric licensing requirements of section l0(d) of the FPA (see Note l), and
. certain requirements under the OPUC approval of the AERC acquisition in20l4. The OPUC's AERC acquisition
order requires Avista Corp. to maintain a capital structure of no less than 40 percent common equity (inclusive of
short-term debQ. This limitation may be revised upon request by the Company with approval from the OPUC.
The Company declared the following dividends for the year ended December 3l
2016 2015
$ 1.37 $1.32
Under the most restrictive of the dividend limitations discussed above, which are the requirements of the OPUC approval of the AERC
acquisition, the amount available for dividends at December 31 ,2016 was limited to $263.4 million.
The Company has 10 million authorized shares ofpreferred stock. The Company did not have any preferred stock outstanding as of
December 31,2016 and 2015.
Stock Repurchase Progroms
During 2014 and 2015, Avista Corp.'s Board of Directors approved programs to repurchase shares of the Company's outstanding
common stock. The number of shares repurchased and the total cost of repurchases are disclosed in the Statements of Equity and
FERC FORM NO.1 (ED.12-88)Page 123.33
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Redeemable Noncontrolling Interests. The average repurchase price was $31.57 in2014 and $32.66 in 2015. All repurchased shares
reverted to the status ofauthorized but unissued shares.
Equity Issuances
In March 2016,the Company entered into four separate sales agency agreements under which Avista Corp.'s sales agents may offer
and sell up to 3.8 million new shares of Avista Corp.'s common stock, no par value, from time to time. The sales agency agreements
expire on February 29,2020.1n2016, 1.6 million shares were issued under these agreements resulting in total net proceeds of $65.3
million, leaving 2.2 million shares remaining to be issued.
ln2016, the Company also issued $1.7 million (net of issuance costs) of common stock under the employee plans.
NOTE 16. COMMITIUENTS AT{D CONTINGENCIES
ln 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, conffoversies, disputes and other contingent matters involve litigation
or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and pursue its
rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other contested
proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Corp.'s operations, the Company intends to
seek, to the extent appropriate, recovery ofincurred costs through the ratemaking process.
C alifo rni a R efu n d P ro c e e di ng
In February 201 6, APX, a market maker in the Califomia Refund Proceedings in whose markets Avista Enerry participated in the
summer of 2000, asserted that Avista Enerry and its other customer/participants may be responsible for a share of the disgorgement
penalty APX may be found to owe to Pacific Gas & Electric (PG&E), Southem California Edison, San Diego Gas & Electric, the
California Attorney General (AG), the Califomia Department of Water Resources (CERS), and the Califomia Public Utilities
Commission (together, the "California Parties"). The penalty arises as a result of the FERC's finding that APX committed violations in
the California market in the summer of 2000. APX is making these assertions despite Avista Energy having been dismissed in FERC
Opinion No. 536 from the on-going administrative proceeding at the FERC regarding potential wrongdoing in the California markets
in the summer of 2000. APX has identified Avista Energy's share of APX's exposure to be as much as $16.0 million even though no
wrongdoing allegations are specifically attributable to Avista Energy. Avista Energy believes its settlement with the California Parties
in2014 insulates it from any such liability and that as a dismissed party it cannot be drawn back into the litigation. Avista Energy
intends to vigorously dispute APX's assertions of indirect liability, but cannot at this time predict the eventual outcome.
Pacific Northwest Refund Proceeding
In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market
sales of wholesale energy in the Pacific Northwest between December 25,2000 and June 20,2001 were just and reasonable. In June
2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do notjustifo the imposition of
refunds. In August 2007,the Ninth Circuit found that the FERC had failed to take into account new evidence of market manipulation
and that such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's findings
must be reevaluated in light of the new evidence. The Ninth Circuit expressly declined to direct the FERC to grant refunds. On October
3,2011, the FERC issued an Order on Remand and on April 5,2013 expanded the temporal scope of the proceeding to permit parties
to submit evidence on transactions during the period from January I , 2000 through and including June 20, 200 I .
On July 11,2012 and March 28,2013, Avista Energy and Avista Corp. filed settlements of all issues in this docket with regard to the
claims made by the City of Tacoma and the Califomia AG (on behalf of the California Department of Water Resources). The FERC
approved the settlements and they are final.
FERC FORM NO.1 (ED. 12-88)Page 123.34
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
0313112017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The remaining direct claimant against Avista Corp. and Avista Energy in this proceeding was the City of Seattle, Washington (Seattle).
An evidentiary, trial type hearing before an Administrative Law Judge (ALJ) to permit parties to present evidence of unlawful market
activity was conducted in 2013.
With regard to the Seattle claims, on March 28,2014, the Presiding ALJ issued an Initial Decision finding that: l) Seattle failed to
demonstrate that either Avista Corp. or Avista Energy engaged in unlauful market activity and also failed to identif any specific
contracts at issue; 2) Seattle failed to demonstrate that contracts with either Avista Corp. or Avista Energy imposed an excessive
burden on consumers or seriously harmed the public interest; and that 3) Seattle failed to demonstrate that either Avista Corp. or Avista
Energy engaged in any specific violations of substantive provisions of the FPA or any filed tariffs or rate schedules. Accordingly, the
ALJ denied all of Seattle's claims under both section 206 and section 309 of the FPA. On May 22,2015, the FERC issued its Order on
lnitial Decision in which it upheld the ALJ's Initial Decision denying all of Seattle's claims against Avista Corp. and Avista Energy.
Seattle filed a Request for Rehearing of the FERC's Order on Initial Decision which was denied on December 31,2015. Seattle
appealed the FERC's decision to the Ninth Circuit. In October 2016, Seattle settled all of the matters with the remaining parties and
withdrew its appeal at the Ninth Circuit. All the remaining parties signed the settlement agreement and a petition to dismiss the case
was filed with the Ninth Circuit on October 27,2016. There are no remaining claims outstanding under this proceeding. The settlement
did not have a material adverse effbct on the Company's financial condition, results of operations or cash flows.
Sierra Club and Montano Environmental Informttion Center Litigation
ln2013, the Sierra Club and Montana Environmental Information Center (MEIC) (collectively "Plaintiffs"), filed a Complaint in the
United States District Court for the District of Montan4 Billings Division, against the Owners of the Colstrip Generating Project
("Colstrip"); Avista Corp. owns a l5 percent interest in Units 3 & 4 of Colstrip. The other Colstrip co-Owners are Talen Montan4
LLC (formerly PPL Montana,LLC, an indirect subsidiary of Talen Energy Corporation), Puget Sound Energy, Portland General
Electric Company, NorthWestern Enerry and PacifiCorp. The Complaint alleged certain violations of the Clean Air Act, including the
New Source Review, Title V and opacity requirements with respect to post-January I , 2001 Colstrip projects. The Plaintiffs requested
that the Court grant injunctive and declaratory relief order remediation of alleged environmental damages, impose civil penalties,
require a beneficial environmental project in the areas affected by the alleged air pollution and require payment of Plaintiffs' costs of
litigation and attorney fees.
The liabilitytrial was scheduled to start on May 31,2016. The parties engaged in settlement discussions with the Plaintiffs to resolve
the claims raised in the litigation. On July 12,2016, the parties filed a proposed Consent Decree with the court which contained the
terms of the settlement of the matter with respect to all four units at Colstrip. The settlement does not include any monetary payments
by any party, dismisses all claims against all four units, and provides for the shut-down of units 1 & 2 (which are owned solely by
Talen MontanaLLC and Puget Sound Energy) no later than July, 2022.The Consent Decree was entered on September 6, 2016. The
parties have petitioned the Court for costs and attorneys' fees. The Court denied the defendanfs claim for fees and reduced the
plaintiffs claimed fees from approximately $3.0 million to $l.6 million. On February 15,2017 the Court issued an Order adopting this
resolution in full and closing the case.
The Company does not expect that this matter will have a material adverse effect on its financial condition, results of operations or
cash flows.
Cabina Gorge Total Dksolved Gas Abatement Plan
Dissolved atmospheric gas levels (refened to as "Total Dissolved Gas" or "TDG") in the Clark Fork River exceed state of Idaho and
federal water quality numeric standards downstream of Cabinet Gorge particularly during periods when excess river flows must be
diverted over the spillway. Under the terms of the Clark Fork Settlement Agreement (CFSA) 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
FERC FORM NO.1 (ED. 12-88)Pase 123.35
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t20't7
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
issue. Under the terms of a gas supersaturation mitigation plan, Avista is reducing TDG by constructing spill crest modifications on
spill gates at the dam, and the Company expects to continue spill crest modifications over the next several years, in ongoing
consultation with key stakeholders. Avista Corp. cannot at this time predict the outcome or estimate a range of costs associated with
this contingency; however, the Company will continue to seek recovery, through the ratemaking process, of all operating and
capitalized costs related to this issue.
Fkh Passage at Csbinet Gorge and Noxon Rapids
ln 1999, the United States Fish and Wildlife Service (USFWS) listed bull trout as threatened under the Endangered Species Act. In
2010, the USFWS issued a revised designation of critical habitat for bull trout, which includes the lower Clark Fork River. The
USFWS issued a final recovery plan in October 201 5.
The CFSA describes programs intended to help restore bull trout populations in the project area. Usingthe concept ofadaptive
management and working closely with the USFWS, the Company evaluated the feasibility of fish passage at Cabinet Gorge and Noxon
Rapids. The results ofthese studies led, in part, to the decision to move forward with development of permanent facilities, among other
bull trout enhancement efforts. Parties to the CFSA are working to resolve several issues. The Company believes its ongoing efforts
through the CFSA continue to effectively address issues related to bull trout. Avista Corp. cannot at this time predict the outcome or
estimate a range of costs associated with this contingency; however, the Company will continue to seek recovery, through the
ratemaking process, of all operating and capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids.
Collective Bargaining Agreemen$
The Company's collective bargaining agreements with the IBEW represent approximately 45 percent of all of Avista Corp.'s
employees. A new three-year agreement with the local union in WashinSon and Idaho representing the majority (approximately 90
percent) of the Avista Corp.'s bargaining unit employees was approved in March 2016 and expires in March 2019.
A three-year agreement in Oregon, which covers approximately 50 employees was set to expire in March 2017. A new three-year
agreement has been approved by the IBEW membership that will expire in March 2020. h is still awaiting approval from the National
IBEW.
There is a risk that ifcollective bargaining agreements expire and new agreements are not reached in each ofourjurisdictions,
employees could strike. Given the magnitude of employees that are covered by collective bargaining agreements, this could result in
disruptions of our operations. However, the Company believes that the possibility of this occurring is remote.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company
believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of
operations or cash flows. lt is possible that a change could occur in the Company's estimates of the probability or amount of a liability
being incurred. Such a change, should it occur, could be significant.
The Company routinely i[sesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitments
for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties
who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company's policy is to accrue
and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation,
cleanup and monitoring costs to be incurred. For matters that affect Avista Corp.'s or AE[-&P'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, plants and wildlife that have either already
been added to the endangered species list, listed as "threatened" or petitioned for listing. Thus far, measures adopted and implemented
FERC FORM NO.1 (ED.12-88)Page 123.36
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
have had minimal impact on the Company. However, the Company will continue to seek recovery, through the ratemaking process, of
all operating and capitalized costs related to these issues.
Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights.
In addition, the company holds additional non-hydro water rights. The state of Montana is examining the status of all water right claims
within state boundaries through a general adjudication. Claims within the Clark Fork River basin could adversely affect the energy
production of the Company's Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated adjudication in
northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d'Alene basin. The
Company is and will continue to be a participant in these and any other relevant adjudication processes. The complexity of such
adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to estimate the
impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all operating and
capitalized, costs related to this issue.
NOTE 17. REGULATORY MATTERS
Power Cost Defenals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge on the Balance Sheets for future prudence review and recovery through
retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista
Corp. and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:
o short-term wholesale market prices and sales and purchase volumes,
o the level and availability ofhydroelectric generation,
o the level and availability of thermal generation (including changes in fuel prices), and
o retail loads.
In Washington, the ERM allows Avista Corp. to periodically increase or decrease electric rates with UTC approval to reflect changes
in power supply costs. The ERM is an accounting method used to track certain differences between actual power supply costs, net of
wholesale sales and sales of fuel, and the amount included in base retail rates for Washington customers. The Washinglon ERM
calculation is subject to certain deadbands and sharing bands. For 2016, the Company recognized a pre-tax benefit of $5.1 million
under the ERM in Washington compared to a benefit of $6.3 million for 2015. Total net deferred power costs under the ERM were a
liability of $21.3 million as of December 31,2016 compared to a liability of $18.0 million as of December 31,2015, and these
deferred power cost balances represent amounts due to customers.
Avista Corp. has a PCA mechanism in Idaho that allows it to modiff electric rates on October I of each year with IPUC approval.
Under the PCA mechanism, Avista Corp. defers 90 percent of the difference between certain actual net power supply expenses and the
amount included in base retail rates for its Idaho customers. The October I rate adjustments recover or rebate power costs deferred
during the preceding July-June twelve-month period. Total net power supply costs deferred turder the PCA mechanism were a liability
of $2.2 million as of December 31,2016 compared to an asset of $0.2 million as of December 31, 2015.
Natural Gas Cost Deferrals und Recovery Mechanisms
Avista Corp. files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline ffansportation
costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and
transportation costs for the prior year. Total net deferred natural gas costs to be refunded to customers were a liability of $30.8 million
as of December 31,2016 compared to a liability of $17.9 million as of December 31, 2015.
Decoupling and Earnings Sharing Mechanisms
FERC FORM NO.1 (ED.12-88)Page 123.37
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
2016/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Decoupling is a mechanism designed to sever the link between a utility's revenues and consumers'energy usage. In each of Avista
Corp.'s jurisdictions, each month Avista Corp.'s electric and natural gas revenues are adjusted so as to be based on the number of
customers in certain customer rate classes, rather than KWh and therm sales. The difference between revenues based on the number of
customers and revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following
year.
Ll/ashington Decoupling and Earnings Sharing
In Washington, the UTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period beginning
January 1,2015. Electric and natural gas decoupling surcharge rate adjustments to customers are limited to 3 percent on an annual
basis, with any remaining surcharge balance carried forward for recovery in a future period. There is no limit on the level of rebate rate
adjustments.
The electric and natural gas decoupling mechanisms each include an after-the-fact eamings test. At the end of each calendar year,
separate electric and natural gas earnings calculations will be made for the prior calendar year. These eamings tests will reflect actual
decoupled revenues, normalized power supply costs and other normalizing adjustments. See below for a summary of cumulative
balances under the decoupling and earnings sharing mechanisms.
Idaho Fixed Cost Adjustment (FCA) and Earnings Sharing Mechanisms
In ldaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the
Washington decoupling mechanisms) for an initial term of three years, beginning January 1,2016.
For the period 2013 through 2015 the Company had an after-the-fact earnings test, such that if Avista Corp., on a consolidated basis
for electric and natural gas operations in ldaho, earned more than a 9.8 percent ROE, the Company was required to share with
customers 50 percent of any earnings above the 9.8 percent. There was no provision for a surcharge to customers if the Company's
ROE was less than 9.8 percent. This after-the-fact earnings test was discontinued as part of the settlement of the Company's 2015 ldaho
electric and natural gas general rates cases. See below for a summary of cumulative balances under the decoupling and eamings
sharing mechanisms.
Ore gon De c oupl ing Mec hanis m
In February 2016,the OPUC approved the implementation of a decoupling mechanism for natural gas, similar to the Washington and
Idaho mechanisms described above. The decoupling mechanism became effective on March 1,2016 and there will be an opportunity
for interested parties to review the mechanism and recommend changes, if any, by September 2019. An eamings review is conducted
on an annual basis, which is filed by the Company with the OPUC on or before June I of each year for the prior calendar year. In the
annual earnings review, if the Company earns more than 100 basis points above its allowed return on equity, one-third of the earnings
above the 100 basis points would be defened and later returned to customers. The earnings review is separate from the decoupling
mechanism and was in place prior to decoupling. See below for a summary of cumulative balances under the decoupling and earnings
sharing mechanisms.
Cumulqtive Decoupling and Earnings Sharing Mechanism Balances
As of December 31,2016 and December 31,2015, the Company had the following cumulative balances outstanding related to
decoupling and eamings sharing mechanisms in its various jurisdictions (dollars in thousands):
December 3l ,
2016
December 3 l,
2015
Washington
FERC FORM NO.1 (ED.12-88)Page 123.38
Name of Respondent
Avista Comoration
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
2016tQ4
NOTES TO FINANCIAL STATEMENTS (Continued)
Decoupling surcharge
Provision for eamings sharing rebate
Idaho
Decoupling surcharge
Provision for eamings sharing rebate
0regon
Decoupling surcharge
Provision for earnings sharing rebate
$30,408 $
(5,1 l3)
10,933
(3,422)
$8,292
(5,1 84)
nla
(8,814)
$ 2,021 nla
(r/a) This mechanism did not exist during this time period.
NOTE 18. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow information consisted of the following items for the years ended December 3l (dollars in thousands):
20t6 2015
Cash paid for interest
Cash received for income taxes, net
$79,193 $
(14,624)
72,405
(l 0,s06)
FERC FORM NO.1 (ED.12.88)Pase 123.39
Name of Respondent
Avista Corporation
ThiS
(1)
(2)
Reoort
8nn
ls:
Original
;-1A Resubmission
Date of Reoorl(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 20161Q4
S IA I EMEN I S OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of{ax basis, where appropriate.
2. Reporl in columns (0 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.
Line
No.
Item
(a)
Unrealized Gains and
Losses on Available-
for-Sale Securilies
(b)
Minimum Pension
Liability adjustment
(net amount)
(c)
Foreign Currenry
Hedges
(d)
Other
Adjustments
(e)
1 Balance of Account 219 at Beginning of
Preceding Year ( 7,887,881)
2 Preceding Qtrffr to Date Reclassifications
from Acct 219 to Net lncome
a Preceding Quarter/Year to Date Changes in
Fair Value 1 ,238,1 10
4 Total (lines 2 and 3)1 ,238,1 1 0
E Balance ofAccount 219 at End of
Preceding Quarterfr/ear ( 6,649,771)
6 Balance ofAccount 219 at Beginning of
Current Year ( 6,649,771)
7 Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net lncome
8 Current QuarterfYear to Date Changes in
Fair Value ( 917,738)
I Total (lines 7 and 8)( 917,738)
10 Balance ofAccount 219 at End ofCurrent
QuarterfYear ( 7,s67,509)
FERC FORM NO. I (NEW 0642)Page 122a
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn Orisinat(2) l--lA Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period ol Report
End of 2016/Q4
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVI]IES
Line
No.
Other Cash Flow
Hedges
lnterest Rate Swaps
(f)
Other Cash Flow
Hedges
lSpecifuI
(s)
Totals for each
category of items
recorded in
Account 2'19
(h)
Net lncome (Carried
Fontrrard from
Page 117, Line 78)
(D
Total
Comprehensive
lncome
0)
1 ( 7,887,881)
2
3 1,238,110
4 1 ,238,1 1 0 123,227,041 124,465,151
E ( 6,649,771)
6 ( 6,U9,771)
7
8 ( 917,738)
o ( 917,738)137,228,107 136,310,369
10 ( 7,567,509)
FERC FORM NO. 1 (NEW 06-02)Page 122b
Avista Corporation (1)
(2)A Resubmission
uare or l(eoon(Mo, Da, Yi)
03t31t2017
YearPenoo or Kepon
End of 20161Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION, AMORTIZATION AND DEPLETION
Report in Column (c) the amount for eleclric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
:olumn (h) common function.
Line
No.
Classification
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
1 Utility Plant
2 ln Service
3 Plant in Service (Classified)5,288,471,ffi7 3,782,482,769
4 Property Under Capital Leases 5,8/.3,742 289,388
5 Plant Purchased or Sold
b Completed Construc{ion not Classified
7 Experimental Plant Unclassified
I Total (3 thru 7)5,294,315,409 3,782,772,157
9 Leased to Others
10 Held for Future Use 9,941,983 9,751,398
11 Construction Work in Progress 't44,751,274 82,968,637
12 Acquisition Adjustments
13 Total Utility Plant (8 thru 12)5,449,008,666 3,875,492J92
14 Accum Prov for Depr, Amort, & Depl 1,770,511,420 I ,313,645,01 5
15 Net Utility Plant (13 less 14)3,678,497,246 2,561,U7,177
16 Detail of Accum Prov for Depr, Amort & Depl
17 ln Service:
18 Depreciation 1,701,243,278 1,294,760,452
19 Amort & Depl of Producing Nat Gas Land/Land Right
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant 69,268,'.!42 18,884,562
22 Total ln Service (18 thru 21)1,770,511,420 1,313,645,014
23 Leased to Others
24 Depreciation
25 Amortization 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) (22,26,30,31,32)1,770,511,420 1,313,645,014
FERC FORM NO.1 (ED. 12-89)Page 200
Name of Respondent
Avista Corporation
This Reoort ls:(1) ElAn Orisinat(2) [A Resubmission
Date of Reoorl
(Mo, Da, Yi)
o3t31t2017
Year/Period of Report
End of 2016/Q4
SUMMARY OF UTILITY PI-ANT AND ACCUMUISTED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas
(d)
Other (Speciff)
(e)
Other (Speciff)
(0
Other (Speci!)
(s)
Common
(h)
Line
No,
1
2
1,0/.1.145.79'l 4U,8/.3,107 3
zil,354 5,300,000 4
E
6
7
1,041,400,145 470,143,107 8
I
190,585 10
7,987,817 53,794,82C 11
12
1,U9,578,547 523,937,92i 13
337,046,928 119,819,471 14
7',12,531,619 4U,118,45C 15
16
17
335,655,367 70,827,459 18
't9
20
1,391 ,561 48,992,0't!21
337,046,928 119,819,478 22
23
24
25
26
27
28
29
30
31
32
337,046,92€'t19,819,478 33
FERC FORM NO. I (ED. 12-89)Page 201
Avista Corporation
(1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03131t2017
Year/Periocl of Report
End of 2O'l6lQ4
hltutRlu PLANI tN SLRV|UE (Account 1O1, 102, 103 and 10t)
1. Report below the original cost of electric plant in service according to the prescribed accounts.
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 106, Completed Construction Not Classified-Electric.
3. lnclude in column (c) or (d), as appropriate, correclions of additions and retiremenls for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effecl of such accounls.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount
of plant retirements which have nol 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 deprecialion provision. lnclude also in column (d)
Ltne
No.
ACCOUnI
(a)
AOOmOnS
(c)
1 l.INTANGIBLE PLANT
2 (301) Orsanization
3 (302) Franchises and Consents 44.651.922
4 (303) Miscellaneous lntangible Plant 18,474,037 934,934
5 TOTAL lntanqible Plant (Enter Total of lines 2, 3, and 4)63.125.959 934,934
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
I (310) Land and Land Riqhts 7,120,986 -3,*2,814
9 (311) Structures and lmDrovements 131.305.776 2.517,897
10 (312) Boiler Plant Equipment 166,507,956 6,261,474
11 (313) Enqines and Enoine-Driven Generators 6.770
12 (314) Turboqenerator Units 54,U4,179 2,285,638
13 (31 5) Accessorv Electric Eouioment 27.022.693 874.771
14 (316) Misc. Power Plant Equipment 17 11 8't7,535
15 (317) Asset Retirement Costs for Steam Production 13.124.454 -693.27'.\
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15)416,ilg,492 8,521,230
17 B. Nuclear Production Plant
18 (320) Land and Land Riqhts
19 (321) Structures and lmorovements
20 (322) Reactor Plant Equipment
21 (323) Turboqenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Riqhts 59,936,653 1.757 ,149
28 (331) Structures and lmprovements 61,708,187 15,811,464
29 (332) Reservoirs, Dams, and Wateruvays 153,839,363 27.345,779
30 (333) Water Wreels, Turbines, and Generators 167,828,800 63,336,443
31 (334) Accessory Eleclric Equipment 42,5U.172 18,236,193
32 (335) Misc. Power PLant Equipment 9,526,404 3,033,277
33 (336) Roads. Railroads. and Bridqes 2.681.352 419,994v(337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hvdraulic Production Plant (Enter Total of lines 27 thru 34)498.104.931 129,9r0,299
36 D. Other Production Plant
37 (340) Land and Land Riqhts 90s,167
38 (341) Struclures and lmprovements 16,793,360 162.367
39 (342) Fuel Holders, Producls, and Accessories 21.377.912 1.791
40 (343) Prime Movers 23,909,470
4',!(3214) Generators 206.578.655 24,282,68e
42 (345) Accessory Eleclric Equipment 20,780,726 20,673
43 (346) Misc. Power Plant Eouioment 1.775.348 44.ye
44 (347) Asset Retirement Costs for Other Produc{ion 351,683
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru ,14)292,472,321 24.423.171
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45)1,207,226,744 162,884,70C
FERC FORM NO.1 (REV.12-05)Page 204
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
(Mo End of
of Report
2016tQ4
03131t2017
01 1 1 and 1
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent's plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utilig plant accounts. lnclude also in column (f1 the additions or reduclions of primary account
classifications arising from distribution of amounts initialty recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisilion adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date oftransaction. lf entries have been filed with the Commission as the Uniform of Accounts ive also date
Retirements
(d)
AdJustments
(e)
lransters
(f)
Balance at
End ofYear(q)
Line
No.
1
2
44.651,922 3
824.7ffi 18,584,205 4
824,7ffi 63.zfi.127 5
6
7
389 3.577.783 I
69,778 133.753.895 9
1,320,884 171.448,il6 10
6,770 11
74,050 56,655,767 12
427.895 27,469,569 13
31,559 17,902,6U 14
134,589 12,296,594 15
2,059,',tM 423.111,578 16
'17
't8
19
20
21
22
23
24
25
26
61,693,802 27
1,327,788 76,1 91 ,863 28
1.665.518 179.519.624 29
14,066,889 217.098.354 30
2.856.982 57,963,383 31
421,075 12.'t38.606 32
30.311 3,07't,035 33u
20.368.563 607,676,667 35
36
905,167 37
4,010 16,951,717 38
21.379.703 39
23.909.470 40
14,653,335 216.208.006 41
191,277 20,610,122 42
1,731,O02 43
351,683 44
14.8/,8.622 302,0/16,870 45
37,276,329 1 ,332.835,1 15 46
FERC FORM NO. 1 (REV.12-05)Page 2Os
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn orisinat(2) nA Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
End of 20161Q4
I 1 1 1 and
Ltne
No.
ACCOUnI
(a)
Addtttons
(c)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights 21,941 ,751 3,245.2U
49 (352) Structures and lmprovements 20,538,173 3,778,654
50 (353) Station Equipment 17.165.076
51 (354) Towers and Fixtures 17.172.555 1,74e
52 (355) Poles and Fixtures 198,418,239 14,050,573
53 (356) Overhead Conductors and Devices 131 ,684,983 5,876.123
il (357) Underqround Conduit 2,987,090
55 (358) Underoround Conductors and Devices 687
56 (359) Roads and Trails 1,966,794 131,5',t4
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57)640,091,734 44,249,607
59 4. DISTRIBUTION PLANT
60 (360) Land and Land Riohts 7.U7,465 1,169,161
61 (361) Structures and lmprovements 20,387,882 938.311
62 (362) Station Equipment 124,856,555 4,636,596
63 (363) Storage Battery Equipment 23il,235 243,61Cu(364) Poles. Towers. and Fixtures 338,516,1 98 21,831,202
65 (365) Overhead Conductors and Devices 213,576,868 18,838,34C
66 (366) Underqround Conduit 98,828,188 5.274,332
67 (367) Underqround Conduclors and Devices 173,962,389 12,021,193
68 (368) Line Transformers 2y.112.624 8,968,406
69 (369) Services 151,461,634 6,939,922
70 (370) Meters 49,503,959 1.341 ,274
71 (371) lnstallations on Customer Premises 219.118
72 (372) Leased ProDertv on Customer Premises
73 (373) Skeet Liqhtinq and Siqnal Systems 49,377,953 9,549,002
74 (374) Asset Retirement Costs for Distribution Plant 129.707
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74)1 ,464,915,653 91,970,468
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (381) Structures and lmprovements
79 (382) Computer Hardware
80 (383) Computer Software
81 (3&4) Communication Equipment
82 (385) Miscellaneous Regional Transmission and Market Operation Plant
83 (386) Asset Retirement Costs for Regional Transmission and Market OperuTOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
85 6. GENERAL PLANT
86 (389) Land and Land Riqhts 398,664
87 (390) Structures and lmprovements 7,028,571 1.076.029
88 (391) Ofiice Furniture and Equioment 9,190,855 253,987
89 (392) Transportation Equipment 34,138,376 5.829,460
90 (393) Stores Equipment 400,506
91 (394) Tools, Shop and Garage Equipment 3,725,151 417.435
92 (395) Laboratory Equipment 582.187 401,394
93 (396) Power Operated Equipment 33,435,575 '116,754
94 (397) Communication Equipment 61.110,391 3,409,571
95 (398) Miscellaneous Equipment 80,897 62,il6
96 SUBTOTAL (Enter Total of lines 86 thru 95)150,091 ,1 73 11,567,176
97 (399) Other Tangible Propertv
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98)150,091,173 11,567,176
100 TOTAL (Accounts 101 and 106)3.525.451.263 311,606,885
101 (102) Electric Plant Purchased (See lnstr. 8)
102 (Less) (102) Electric Plant Sold (See Instr. 8)
103 (103) Experimental Plant Unclassified
1M TOTAL Electric Plant in Service (Enter Total of lines 100 thru 1 03)3,525,451,263 311,606,885
FERC FORM NO. I (REV. 12-05)Page 206
of Respondent
(1)
(2)
OriginalAvista Corporation Resubmission
Date of Report(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 2016/Q4
Continued)
Retirements
(d)
Aclustments
(e)
I ranslers
(0
Balance at
End ofYear(q)
Line
No.
47
25,1 86,985 48
156,096 24.160.731 49
4,790,551 255,414,4U 50
't7.174.301 51
508,362 211,960,450 52
143.535 137,417,571 53
2,987,090 54
2342,957 55
2,098,308 56
57
5,598.544 678.742,797 58
59
882 -279.882 8.735,862 60
255.145 21,071,048 61
2,851,616 126,641,535 62
2,597,U5 63
522.626 8,040 359,832.814 64
224,562 3,971 232,194,617 65
32.235 39,626 104.109.911 66
208,679 -24.631 185.750.272 67
'123.226 2,194 242.959.994 68
72,338 32,817 158,362,035 69
78.259 50.766.975 70
219,118 71
72
1,363,099 57,563,856 73
129.707 74
5,862,374 -217.865 1.550,805,882 75
76
77
78
79
80
81
82
83u
85
398,664 86
10,014 8,0%,586 87
1,062,377 8,382,465 88
1,182.701 -3,804 38,781,331 89
400,506 90
105,210 -19.837 4,017,539 91
67,870 915.711 92
1,404,677 1 13,703 32,261,355 93
u1.882 -219,145 63.758.935 94
2,299 141,'.\M 95
4.377.030 -129,083 157.152.236 96
97
98
4,377,030 -129,083 157,152,236 99
53.939.043 -346,948 3.782.772.157 100
101
102
103
53,939.043 -346,948 3,782,772,157 1U
FERC FORM NO. 1 (REV.12-05)Page 207
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn originat(2\ nA Resubmission
Date of Reoort
(Mo, Da, Yi)
03t3112017
Year/Period of Report
End of 2016/Q4
1. Report separately each proper$ 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 oJ such property was discontinued, and the date the original cost was transferred to Account 105.
LineNo.in
Balance at
End of Year(d)
1 Land and Rights:
2
3
4 Distribution Plant Land, Spokane, Washington Oct 2008 Unknown 1,457,302
5 Distribution Plant Land, Carlin Bay, ldaho Dec 2010 Unknown 162,352
6 Distribution Plant Land, Spokane, Washington Mar 2011 Unknown 540,307
7 Distribution UG Plant Conduit, Spokane, Washington Dec 201 0 Unknown 22.437
I Distribution UG Plant Conductors, Spokane, Washingto Dec 201 0 Unknown '197,444
I Transmission Plant Land, Spokane, Washington Dec20'11 Unknown 431,600
10 Transmission Plant Land, Spokane, Washington July 2014 Unknown 62,168
11 Transmission Plant Land, Noxon, Montana Mar 2016 Unknown 3,292,167
12 Other Production Plant Land, Spokane, Washington Dec 201 1 Unknown 40,896
13 Steam Produc{ion Plant Land, Spokane, Washington Dec 2015 Unknown 3,U4,725
14
15
16
17
18
19
20
21 Other Property:
22
23
24
25
26
27
28
29
30
3'l
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47 Total 9,751,
FERC FORM NO. I (ED. 12-96)Page 214
Name of Respondent
Avista Corporation (1)
(2)
An Original
Resubmission
Date of(Mo, Da
Report
,Y0
03t31t2017
Year/Period of Report
End of 20'16/Q4
CoNSTRUCT|ON WORK rN PROGRESS - - ELECI RtC (Account 107)
1 . Report below descriptions and balances at end of year of projects in process of construclion (107)
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
Electric (Account
(b)
orooress
1'07r
1 Clark Fork lmplementation PME Agreement 14,904,135
2 Little Falls Powerhouse Redevelopment 10,'t71,419
3 South Region Transmission Voltage Control 5,717,386
4 Benton-Othello 1 1 5 Reconduclor 4,136,563
5 Productivity lnitiative 3,384,676
6 Transmission Minor Rebuild 3,342,773
7 Nine Mile Redevelopment 2,965,943
8 Substation Rebuilds 2,795,041
I Regulating Hydro 2,591,044
10 Westside 230 kV Substation - Rebuild 2,558,725
11 Noxon Station Service 2,496,391
12 Mobile Subslation - Purchase New Mobile Subs 2,252,499
13 Substation Asset Mgmt Capital Maintenance 1,916,848
14 Devils Gap-Lind 115kV Transmission Rebuild Proj 1,879,482
15 Beacon-Boulder #2 1'l 5: Capacity Upgrade 1,641,084
16 Distribution Grid Modernization 1,397,745
17 WSDOT Highway Franchise Consolidation 1,390,145
18 Kettle Falls Stator Rewind 1,382,424
19 lrvin Sub - New Construction 1,225,129
20 College & Walnut Substation Yard Expansion 1 ,193,'143
21 Strategic lnitiatives 1 .1 19.039
22 COF Long Term Restructuring Plan Phase 2 1,070,854
23 Minor Projects <$1M 11,436,149
24
25
26 Research, Development, and Demonstrating:
27 There are no Research, Development, and Demonstrating CWP balances tor 2016
28
29
30
31
32
33
v
35
36
37
38
39
40
41
42
43 TOTAL 82,968,637
FERC FORM NO.1 (ED.12-87)Page 216
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn Originat(2) nA Resubmission
Date of Report
(Mo, Da, Y0
03t31t2017
Year/Period of Report
End of 2O16lQ4
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'l , 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 amounts 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 classiflcations, 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
Ltne
No.
tlem
(a)
. I otal.(c+d+e)
(b)
Eteclflc Planl tnService
(c)
Eteclflc Ftanl nelofor Future Use(d)
trteclnc FtanILeased to Others(e)
1 Balance Beginning of Year 't,247,691,281 1,247,691,281
2 Depreciation Provisions for Year, Charged to
(403) Depreciation Expense 87,800,008 87,800,008
4 (403.1) Depreciation Expense for Asset
Retirement Costs
5 (413) Exp. of Elec. Plt. Leas. to Others
6 Transportation Expenses-Clearing 5,392,148 5,392,148
7 Other Clearing Accounts
I Other Accounts (Specify, details in footnote):-73,186
o Transfer -261,858 -261,858
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
92,857,112 92,857,',t12
11 Net Charges for Plant Retired
12 Book Cost of Plant Retired 40,971,792 40,971,792
13 Cost of Removal 1,627,778 1,627,778
14 Salvage (Credit)105,201 105,201
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
42,494,369 42,494,369
't6 Other Debit or Cr. Items (Describe, details in
footnote):
-3,497,771 ., -3,497 i771
:..
17
18 Book Cost or Asset Retirement Costs Retired 204.199 204,199
19 Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
1,294,760,452 1,294,760,452
Section B. Balances at End of Year According to Functional Classification
2A Steam Production 288,945,491 288,945,491
21 Nuclear Production
22 Hydrau lic Production-Conventional 122,432,583 122,432,583
a1 Hydrau lic Production-Pumped Storage
24 Other Production 108,296,41 5 108,296,415
25 Transmission 26,859,724 206,859,724
26 Distribution 495,276,875 495,276,874
27 Regional Transmission and Market Operation
28 General 72,949,364 72,949,3U
29 TOTAL (Enter Total of lines 20 thru 28)1,294,760,452 1,294,760,452
FERC FORM NO. 1 (REV. 12-0s)Page 219
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
219 Line No.:Schedule Page: 2L9 Line No
Includes:
Col-umn: c
ARC depreciation expense of $224,639 1,8237 6 to 108000Depreciation offset for non-recoverabfe plant ($299,'796) for Kettle Falfs & Boufder Park
Miscellaneous adjustment of $101
Z.ED.AN 392230 adjustment of $1,870
Schedule Page L9 Line No.:16 Column: c
Includes:
Change in Removal Work in Progress ($3,49'7,7'77)
219 Line No.: 16 Column: c
FERC FORM NO.1 (ED. 12471 Page 450.1
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
(Mo,
03t31t2017
Year/Period of Report
End of 2O16lQ4
INVESTMENTS lN SUBSIDIARY COMPANIES (Account 123.1
1 . Report below investments in Accounts 123.1 , investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) lnvestment in Securities - List and describe each securig owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) lnvestment Advances - Report separate! the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. \Mth respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary eamings since acquisilion. The TOTAL in column (e) should egual the amount entered for
Account 418.1.
Lrne
No.
Descfl ptron ot lnvestment
(a)
Date Acquired
(b)
Amounl oI tnveslmenl al
aeSin[$S of Year
1
2 lnvestment in Avista Capital 1 997 206,138,971
3 Avista Capital - Equity in Eamings -144,021,712
4 lnvestment in AERC 2014 89,816,380
5 AERC - Equity in Earnings s,581,641
b
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 lTotal Cost TOTAL 157,5'15,280
FERC FORM NO.1 (ED.12-89)Page ZZ4
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 2O16lQ4
INVESTMENT S lN SUtsSTD|ARY COMPANIES (Account 123.1) (Conttnued)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. 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. ln 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
Equrty rn subsrdrary
Earninos of Year'(e)
Revenues lor Year
(f)ena grfear
Garn or Loss trom lnvestment
ols016,eo ot Line
No.
1
206,138,971 2
-1,433,856 -145,455,568 3
89,816,380 4
7,722,732 -2,000,000 11,304,373 5
6
7
8
I
10
11
12
13
14
15
16
17
18
't9
20
21
22
23
24
25
26
27
28
29
30
31
32
33
u
35
36
37
38
39
40
41
6,288,876 -2,000,000 161,804,156 42
FERC FORM NO. 1 (ED. 12-89)Page 225
Name of Respondent
Avista Corporation
ThiS
(1)
(2\
ReDort ls:
5]Rn Orisinat
aA Resubmission
Date of Report(Mo, Da, Y0
03t3112017
Year/Peraod of Report
End of 2O16lQ4
MATERIALS AND SUPPLIES
1 . For Account "154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by funclion 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 lhe
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 ofYear
(c)
Department or
Departments which
Use Material
(d)
1 Fuel Stock (Account'151)3,293,585 3,566,367 (1)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Exlracted Producls (Account 153)
4 Plant Materials and Operating Supplies (Account'154)
5 Assigned to - Conslruction (Estimated)23,000,160 26,085,323
b Assigned to - Operations and Maintenance
7 Production Plant (Estimated)3,061,532 3,084,192
I Transmission Plant (Estimated)91,062 109,594
9 Distribution Plant (Estimated)299,907 467,705
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to - Other (provide details in footnote)7,479,110 7,676,843
12 TOTAL Account 154 (Enter Total of lines 5 thru 11)33,931,771 37,423,657
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)-86
17
18
19
20 TOTAL Materials and Supplies (Per Balance Sheet)37,225,356 40,989,938
FERC FORM NO. 1 (REV. 12-0s)Page 227
Name of Respondent
Avista Corporation
This Report is:
(1)X An Originale) A Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
227 Line No.: 1 Column: d
(1) Electric
(2) Natural Gas
Schedule Pase: 227 Line No.: 5 Column: d
(1) Electric
(2) Natural Gas
Schedule Pase: 227 Line No.:7 Column: d
(1) Electric
(2) Natural Gas
(1) Electric
(2) Natural Gas
227 Line No.: 9 Column: d
(1) Electric
(2) Natural Gas
Schedule Pase: 227 Line No.: 11 Column: d
(1) Electric
(2) Natural Gas
FERC FORM NO. 1 (ED. 12471 Page 450.1
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reporl(Mo, Da, Yr)
03t3112017
Year/Period of Report
En6 6y 2016/Q4
Transmission 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 interconneclion 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)
KetmDursementsReceived Durinothe Period -
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
2
3
4
5
6
7
I
I
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
22 Rattlesnake Flats Project #49 1 86200
23 Gordon Butte Project #50 287 186200
24 Avista NineMile Upgd 6,710 186200
25 Cleauater Wind I nterconnect 142 186200
26 Saddle Mountain East 59,194 186200
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 Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t3'u2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
231 Line No.:22 Column: bTotal 1i-fe to te costs231 Line No;23 Column: b
Tota fe to date costs.
Schedule Pase:231 Line No.:24 Column: b
Total- life to date costs
Schedule Paqe: 231 Line No.: 25 Column: b
Iotal l-ife to date costs
231 Line No.:26 Column: bTotal life to date costs
FERC FORM NO. 1 (ED. 12-871 Page 450.1
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5l1ln Orisinat(2) nA Resubmission
Date of Report(Mo, Da, Yr)
o3R1t2017
Year/Period of Report
End of 2O16lQ4
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
Beginning of
Cunent
Quarterffear
(b)
Debits
(c)
CREDITS Balance at end of
Cunent Quarterffear
(0
wnnen 0r uunng
the Quarterffear
Account Charged
(d)
wn[en 0n uunng
the Period
Amount
(e)
1 WA Excess Nat Gas Line Extension Allowance 1,444028 1,444,028
2 Reg Asset Post Ret Liab 235,m8,848 5,105,058 240,1 1 3,906
3 Regulatory Asset FAS109 Utility Plant 42,10/,242 56,282,20r 98,386,447
4 Resulatory Asset FAS109 DSIT Non Plant 51,827,593 283 50,774,1 51 1,053,442
5 Requlatory Asset FAS109 DFIT State Tax Cr 4,652,121 283 4,6s2,121
6 Resulatory Asset FAS109 WNP3 2,703,891 283 737,482 1,966,409
7 Regulatory Asset- Spokane River Relicense 386,154 407 78,736 307,418
I Regulatory Asset Spokane River PM&E 355,950 557 73,312 282,638
9 Regulatory Asset Lake CDA Fund 8,8M,404 407 211,065 8,593,339
10 Regulatory Asset Lake CDA IPA Fund 2,000,000 2,000,000
11 Regulatory Asset- Spokane River TDG ldaho 468,893 407 117,223 351,670
12 Reg Assets- Decouplinqs Surcharqe 5,810 1 1,828,860 1 1,834,500
13 Regulatory Asset- Lake CDA DEF Costs 1,244,704 407 32,719 1,211,9U
14 DEF CS2 & COLSTRIP 4,823,298 407 2,151,63C 2,671,668
15 Commodity MTM St Regulatory Asset 17,260J77 244 5,895,089 11,365,088
16 Commodity MTM Lt Regulatory Asset 32,419,72i 2M 15,500,519 16,919,204
17 Regulatory Asset FAS143 Asset Retirement Oblhation 2,875,89€495,837 3,371,735
18 Reg Asset AN- CDA Lake Settlement 33,632,09(407 884,086 32,748,004
19 Reg Asset WA-CDA Lake Settlement 747,91t 407 '152,1 18 595,798
20 Regulatory Asset Workers Comp 2,U7,832 407 835,020 1,212,812
21 Regulatory Asset lD PCA Defenal 1 932,887 557 932,887
22 Spokane RlverTDG s80,78!407 290,395 290,394
23 Settled lnterest Rate Swap Asset 40,786,51i 51,092,099 91,878,61 1
24 DSM Asset 3,167,51!12,502,132 15,669,651
25 Unsettled Interest Rate Swaps Asset 83,972,ni 245 14,343,183 69,629,594
26 Defened ITC 8,481,289 8,481,289
27 Other Reg Assets 221,213 254 136,431 84,782
28
29
30
31
32
33v
35
36
37
38
39
40
41
42
43
M TOTAL 573,031,070 147 ,231,508 97,798,167 622,464,411
FERC FORM NO. 1/3-Q (REV.02-04)Page 232
Name of Respondent
Avista Corporation
This Reoort ls:(1) 51nn originat(2) l-lA Resubmission
Date of Reoort(Mo, Da, Yi)
03t3112017
YearlPeriod of Report
End of 2O16lQ4
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3, Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
Line
No.
Description of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(c)
CREDITS Balance at
End of Year
(0
Amount
(e)
1
2 Colstrip Common Fac.1,110,999 406 1,110,999
3 Regulatory Asset-Mt Lease Pymt 270,513 540 270,513
4 Regulatory Asset-Mt Lease Pymt 676,584 540 676,584
5 Colstrip Common Fac.2,355,il2 2,355,U2
6 Prepd Plane Lease LT-3 vr amort 441,966 196,429 245,537
7 Misc DD-plane Lease- 3 yr amort 515,400 229,67 286,333IPlant Alloc of Clearinq Jrl 1,888,049 1,632.106 3.520,155
9 Misc Posting Suspense 115,295 169,17S VAR 284,474
10 Renewable Enerqv-Cert Fees 21.750 557 21.750
11 Nez Perce Settlement 145,1'.t3 557 5,2',12 139,901
12 Req Asset lD-Lake CDA 10 yr amt 147.13'.1 506 30.975 1 16.156
13 Credit Union Labor and Exp 62,978 44,375 107,357
14 Misc Work Orders <$50,000 -92.021 VAR 395,354 487,375
15 Subsidiary Billinqs 471,651 VAR 44,658 426,993
16 MiscDeferred Debits (WA)16.568 1 ,405,1 99 -1.388.631
17 Requlatory Assets Consv 2,154,581 1,112,190 1,M2.391
18 Req Asset-Decouolino deferred 't3.305.979 19.8/;6.22a 33.152.204
19 Optional Wnd Power -206,235 271,55?65,318
20 Gas Telemetrv eouio 4,823 651 4,172
21 Defened Proi Compass - lD 4 yr 3,346,902 836,726 2,510,176
22 Saddle Mountain East Trans Line 5.929 53,26a 59,1 94
23 AMI Suspense A Base Change Out 299,40i 299,407
24
25
26
27
28
29
30
31
32
33v
35
36
37
38
39
40
41
42
43
44
45
46
47 Misc. Work in Progress
48 uererreo Kegulatory Gomm.
Expenses (See pases 350 - 351 )
49 TOTAL 26,759,597 43,850,403
FERC FORM NO. 1 (ED. 12-94)Page 233
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03131t2017
Year/Period of Report
End of 2016/Q4
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.
Description and Locatton
(a)
tsalanc*91 Begrnrng
(b)
tsalance at Enoof Year
(c)
1 Electric
2 10,573,200 19,561,839
?
4
(
6
7 Other
8 TOTAL Electric (Enter Total of lines 2 thru 7)10,573,200 19,551,839
o Gas
10 750,525 2,568,178
11
12
13
14
15 Other
16 TOTAL Gas (Enter Total of lines 10 thru 15 750,525 2,568,178
17 Other 124,712,394 125,224,690
18 TOTAL (Acct 190) (Total of lines 8, 16 and '17)1 36,036,1 1 9 1473il,707
Notes
FERC FORM NO. 1 (ED.12-88)Page 234
Name of Respondent
Avisla Corporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 2O16lQ4
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.
Line
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 Restricied shares
4 Total Common 200,000,000
5
6
7 Account 204 - Preferred Stock lssued 10,000,000
I
I
10 Cumulative
11
12
13 Total Preferred 10,000,000
14
15
16
17
18
'19
20
2'l
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
s:
(1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 20161Q4
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
Snares(e)Amount(0 shares(s)cost(h)shares(i)Amounto
1
64,187,934 1,052,578,756 2
4,127,608 3
u,187pU 1,052,578,756 109,80€4,127,608 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
33v
35
36
37
38
39
40
41
42
FERC FORM NO. r (ED. 12-88)Page 251
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ) A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016/Q4
FOOTNOTE DATA
250 Line No.: 3 Column: i
Restricted share awards vest in equal thirds each yezr over a three-year period and are payable in Avista Corp. common stock at the
end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target
in order for the CEO's restricted shares to vest. Restricted stock is valued at the close of market of the Company's common stock on
the grant date.
FERC FORM NO.1 (ED. 12471 Paqe 450.1
Name Respondent ls:
Original(1)
(2)
An
Avista Corporation A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
End of 20161Q4
OTHER PAID-lN 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-ln 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 21 1)-Classiry 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.Amount(b)
1 Equity transac{ions of subsidiaries -9,506,475
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
31
32
33
v
35
36
37
38
39
40 TOTAL -9,506,476
FERC FORM NO. 1 (ED. 12-87)Page 253
Avisla Corporation (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t31t2017
Year/Penod of Report
End of 20161Q4
cAPt I AL S I OCK TXPENSE (Account 214)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. lf 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.
Ltne
No.
utass ano Serles oI SIocK
(a)
Earance aI Eno or Year
(b)
1 Common Stock - no par
2
3
4
5
6
7
8
o
10
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL -32,208,771
FERC FORM NO. r (ED. 12-87)Page 254b
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016/Q4
FOOTNOTE DATA
Schedule Paoe:254 Line No.: 1 Column: b
Beginning Balance
lssuance Costs of Common Stock
(29,238,2L31
L,022,242
Payment of Minimum Tax Withholdings for
Share-Based Payment awards
3,072,433
Vested stock com pensation
Stock Compensation Accrual
(31,835,414)
24,770,L8L
Ending Balance 132,208,77L1
s
S
S
s
s
s
FERC FORM NO. 1 (ED. 12.871 Pase 450.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn Originat(2) nA Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 20161Q4
nt a
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, Olher long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. 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 - SERTES A - 7.53% DUE 05t0512023 5,500,000 42,712
2 FMBS - SERIES A - 7,54% DUE 5IO5I2O23 1.000.000 7.766
3 FMBS - SERTES A - 7.39% OUE 5t1 1 t2018 7.000.000 54,364
4 FMBS - SERIES A-7/5% DUE 6/1 1/2018 15,500,000 120,377
5 Discount - FMBS - SERIES A - 7 .45o/o DUE 6/1 1/2018 50,220
6 FMBS - SERIES A-7.18%DUE8I11I2O23 7,000,000 54,364
7 ADVANCE ASSOCIATED-AVISTA CAPITAL I I (l-oPRS)5't,547,000 1,296,086
I FMBS - 6.37% SERIES C 25,000,000 158,304
9 FMBS - 5.45% SERIES 90,000,000 1,192,681
10 Discount- FMBS - 5.45% SERIES 239,400
't1 FMBS - 6.25% SERIES 150,000,000 1,812,935
12 Discount- FMBS - 6.25% SERIES 367,500
13 FMBS.5.7O% SERIES 150,000,000 4,702,304
14 Discount- FMBS - 5.70% SERIES 222,OOO
15 FMBS - 5.95% SERIES 250,000,000 2,246,419
16 Discount- FMBS - 5.95% SERIES 835,000
't7 FMBS - 5.125% SERIES 250,000,000 2,284,788
18 Discount- FMBS - 5.125o/o SERIES 575,000
19 COLSTRIP 2O1OA PCRBs DUE 2032 66,700,000
20 )OLSTRIP 2O1OB PCRBs DUE 2034 17,000,000
21 FMBS - 3.89% SERIES 52,000,000 385,'t29
22 FMBS - 5.55% SERIES 35,000,000 258,834
23 4.45% SERTES OUE 12-14-2041 85,000,000 692.833
24 4.23% SERTES DUE 11-29-2047 80,000,000 730.833
25 FMBS- 4.11% SERIES 60,000,000 428,205
26 FMBS- 4.37% SERIES 100,000,000 590,761
27 FMBS- 3.54% SERIES 175,000,000 1,001,382
28
29
30
31
32
33 TOTAL 1,673,247,20,350,197
FERC FORM NO. I (ED. 12-96)Page 256
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn Originat(2) ;-1A Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 2O16lQ4
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, Amorlization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. ln a footnote, give explanatory (details) for Accounts 223 and 224 ot nel changes during the year. Wlth respect to long-term
advances, show for each company: (a) prlncipal 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-term 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 Account 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)
AMORTIZATION PERIOD uulslanotno(Total amount outstanalino without
reduction for amounts h-eld byres0lpfent)
lnterest for Year
Amount
(D
Line
No.Date From
(0
Date To
(q)
05-06-'t 993 05-05-2023 05-06-1 993 05-05-2023 5,500,00c 414,150 1
05-07-1 993 05-05-2023 05-07-1 993 05-05-2023 1,000,00c 75,400 2
05-1 1-1993 05-1 1 -201 8 05-1 1-1993 05-11-20't8 7,000,000 517,300 3
06-09-1 993 06-1 1-201 8 06-09-1993 06-1 1 -201 8 15,500,000 1j54,750 4
5
08-1 2-1 993 08-11-2023 08-12-1993 o8-11-2023 7,000,000 502,600 b
06-03-1997 06-01-2037 06-03-1 997 06-01-2037 51,547,000 6U,372 7
06-19-1998 06-19-2028 06-1 9-1 998 06-1 9-2028 25,000,000 1,592,500 I
11-18-2004 12-01-2019 11-18-2004 't2-01-2019 90,000,000 4,905,000 I
10
11-17-2005 12-01-2035 11-17-2005 12-01-2035 '150,000,000 9,375,000 11
't2
12-15-2006 07-01-2037 12-15-2006 07-01-2037 150,000,00c 8,550,000 13
14
04-02-2008 06-01-20'18 04-02-2008 06-01-2018 250,000,00c 14,875,000 15
16
09-22-2009 04-01-2022 09-22-2009 04-01-2022 2s0,000,00c 12,812,500 't7
18
12-15-2010 10-1-2032 12-15-2010 10-1-2032 66,700,00c 't9
12-15-2010 3-1-2034 12-15-2010 3-1-203r',17,000,00c 20
12-20-2010 12-20-2020 12-20-2010 12-20-2020 52,000,00c 2,022,800 21
12-20-2010 12-20-2040 12-20-2010 12-20-2040 3s,000,000 1,942,500 22
12-14-2011 12-14-2M1 12-14-20'.t1 12-14-2041 85,000,000 3,782,500 23
't1-30-2012 11-29-2047 11-30-2012 11-29-2047 80,000,000 3,384,000 24
12-'.t8-2014 12-1-20M 12-18-2014 12-1-2044 60,000,000 2,466,000 25
12-16-2015 12-1-2M5 12-16-2015 12-1-2U5 100,000,000 4,370,000 26
12-15-2016 12-1-2051 12-15-2016 12-1-20s1 175,000,000 275,333 27
28
29
30
3'l
32
1,673,247,OO0 73,651,705 33
FERC FORM NO. 1 (ED. 12-96)Page 257
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
256 Line No.:7 Column: a
256 Line No.: 19 Column: a
Upon ssuance Av sta Capital fI issued $1.5 million of Common Trust Securities to the
Company. In December 2000, the Company purchased $10.0 million of these Preferred Trust
Securi-ties .
The debt in 2010. These bonds have not been retired or canceled; the Company plans, based on
id needs and market conditions to remarket these bonds at a future date.
The C reac ].red these bonds an 207
The Company reacquired this debt in 2010. These bonds have not been retired or canceled; the Company plans, based on
needs and market conditions to remarket these bonds at a future date.
e reac red these bonds in 2010n
The new issuance is based on the following state commission orders:
1. Order of the Washington Utilities and Transportation Commission entered July 13, 2011, as
amended on August 24, 2011 in Docket No. U-111176 and in Docket No. UE-151822 entered
October 29,2015;
2. Order of the ldaho Public Utilities Commission, Order No. 32338, entered August 25,2011 and
Order No. 33401, entered October 23,2015;
3. Order of the Public Utility Commission of Oregon, Order No. 15305, entered October 6,2015;
Order of the Public Service Commission of the State of Montana, Default Order No. 4535
Schedule Pase: 256 Line No.:27 Column: c
Expenses may change as more invoices related to this issuance become known.
256 Line No.: 19 Column: c
256 Line No.:20 Column: a
256 Line No.: 20 Column: c
256 Line No.:27 Column: a
FERC FORM NO.1 (ED. 12.871 Pase 450.1
This Reoort ls:(1) 5]Rn originat(2) [-1A Resubmission
Date of Reporl(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2016/Q4
Name of Respondent
Avista Corporation
RECONCILIATION OF REPORTED NET 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 retum 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 retum, 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 consistenl and meets the requirements of
the above instructions. For electronic reporting purposes complete Line 27 and provide the substilute Page in the context of a footnote.
Ltne
No.
Hanrcurars (uera[s)
(a)
AmounI
(b)
137,228j071Net lncome for the Year (Page 1 17)
2
3
4 faxable lncome Not Reported on Books
5 5,326,302
6
7
8
9 Deductions Recorded on Books Not Deducted for Return
10 -2,613,289
74,121,26311Income Tax Expense
12
13
14 lncome Recorded on Books Not lncluded in Return
15 -39,942,100
16
17
18
'19 Deductions on Return Not Charged Against Book lncome
20 -2il132,226
21
22
23
24 s,288,876iquity in Subs Eamings
25 2,385,3s5Sorporate Overhead Unallocated Subs
26
27 -83,9'15,464=ederal Tax Net lncome
28 Show Computation of Tax:
29 379,481State Tax
30 -83,535,983:ederal Tax Net lncome, less state tax
31 -29,237,s94:ederal Tax Net lncome @35Yo
32
33 tline Mile ITC -19,418,459
34 )rior years lrue ups and misc adjustments 1,414,639
35 labinet Gorge tax Credits -166,884
36
37 l-otal Federal Tax Expense 47,408,298
38
39
40
41
42
43
44
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2O16lQ4
IAXtsS ACCRUEIJ, PRE,PAILI AND CHAHGE,D LIURING YE,AR
1. Give particulars (details) of lhe combined prepaid and accrued tax accounts and show the total taxes charged lo operations and other accounls 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 direcl 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.
Lrne
No.
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR I axesCharoedqr#]s
(d)
'FIid"
?ssls(e)
Adjust-
ments
(f)
I axes Accrueo(Account 236)(b)
Preoato laxes(lnclude in Account 165)
1 FEDERAL:
2 lncome Tax 2013 806,204
2 lncome Tax 2014 514,866 325,2@ 1
4 lncome Tax 2015 -'t8,877,196 1,7U,007 -19,013,777 -1,920,589
E lncome Tax (Current)-40,949,517 4,378,957
6 Retained Earnings (Current)-3,371,282
7 Retained Earnings 2015 -'t,920,588 1,920,588
I Prior Retained Earnings 483,257
I Total Federal -19,959,971 42,211,586 -14,634,820
10
11 STATE OF WASHINGTON:
12 Property Tax (2014)-3,U4 -15,470 -18,813 1
13 Property Tax (2015)15,559,562 271,617 15,837,020
14 Property Tax (2016)'t6,219,999
15 Excise Tax (2014)1 1
16 Excise Tax (2015)2,706,504 -7,150 2,699,353 1
17 Excise Tax (2016)26,587,557 22,789,011
18 Natural Gas Use Tax 537 3,569 3,452
19 Municipal Occupation Tax 2,902,651 23, 't 1 5,318 23,095,318 1
20 Community Solar -105,669 -615,995 -696,1 51
21 Sales & Use Tax (2014)u4 y4
22 Sales & Use Tax (2015)127,828 127,828
23 Sales & Use Tax (20'16)1,124,451 967,442
24 Total Washington 21,188,412 66,683,896 64,804,804 2
25
26 STATE OF IDAHO:
2?lncome Tax (2013)41,220 -100,982 -142,202
28 lncome Tax (2014)-142,202 270 141,932
29 lncome Tax (2015)-57,305 530,1 00 -215,096 687,891
30 lncome Tax (2016)51 1,938 500,000
31 Property Tax (2014)52,403 -52,002 401
32 Property Tax (2015)3,557,972 3,s57,985
33 Property Tax (2016)7,',145,215 3,572,839
34 Sales & Use Tax (2015)12,7U 12.784
35 Sales & Use Tax (2016)360,849 337,305
36 K\rvH Tax (2015)24,195 824 25.019
37 Ktl/FlTax (2016)414,153 383,274
38 Franchise Tax (2015)1,526,981 1,526,982 1
39 Franchise Tax (2016)4,440,675 2,951,606
40 Total ldaho 5,016,048 13,352,022 12,552,117 -688,160
41 TOTAL 7,186,818 57,344,759
FERC FORM NO.1 (ED. 12-96)Page 262
Name Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
5. lf any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifuing 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 otheMise 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 Accounls 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.
Line
NoOaxes accrued
Account 236)(s)
Prepaid Taxes
(lncl. in A;;'rount 165)
Electric
(Account 408.1 , 409.1 )
Ertraordinary ltems
(Account 409.3)
Adrustments to Het.
Earnings (Account 439)
(k)
Other
(l)
1
806,204 2
8/,o.072 325,206 3
-5,173,655 6,957,662 4
45,328,474 -34,563,043 -6,386,474 5
-3,371,282 -3,371,282 6
7
483,257 8
-47,536,737 -39,411,492 -2,800,094 9
10
11
-23,274 7,804 12
-5,841 626,771 -355,1 54 13
16,219,999 13,357,998 2,862,001 14
15
-12,176 5,026 16
3,798,546 20,023,s90 6,563,967 17
654 3,569 18
2,922,652 17,746,956 5,368,362 19
-25,s13 -615,995 20
21
22
157,008 1,124,451 23
23,067,505 51,723,4U 14,960,462 24
25
26
27
270 28
$5,276 595,376 29
11,938 435,148 76,790 30
-43,579 -8,423 31
-13 4,sil .4,564 32
3,572,375 5,694,596 1,450,619 33
u
23,544 360,849 35
824 36
30,880 414,863 -710 37
1 38
1,489,069 3,352,949 1,087,726 39
5.127.794 9,794,089 3,557,933 40
-16,431,293 35,237,427 22,107,332 41
FERC FORM NO. r (ED.12-96)Page 263
Avista Corporation
(1)
(2)
An
A Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 20161Q4
PREPAID
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 direcl 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 lo 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.
Lrne
No.
Kind of Tax
(See inslruc{ion 5)
(a)
BALANCE AT BEGINNING OF YEAR I axesCharoedDurinoYear-(d)
'F5ffDurinoYear-(e)
Adjust-
menls
(f)
I axes Accrueo(Account 236)(b)
Preoaro taxes(lnclude in Account 165)
1
2 STATE OF MONTANA:
e lncome Tax (2014)-74,950 233,684 -74,950 -233,6U
4 lncome Tax (2015)413,607 -11,057 119,714
E lncome Tax (2016)118,720
6 Property Tax (2014)9,257 -9,257
7 Property Tax (2015)4,233,693 422,070 3,811,623
8 Property Tax (2016)9,750,999 4,886,505 -1
o Colstrip Generation Tax 3,686 3,686
10 K\rvH Tax (2015)240,112 240,112
11 KVvtl Tax (2016)1,079,381 804,965
12 Consumer Council Fee 23 -3 45 36
13 Public Commission Fee 60 112 93 -36
14 Total Montana 3,994,588 10,744,195 9,672,079 -113,971
15
16 STATE OF OREGON:
17 lncome Tax (2014)-100,000 -100,000
18 lncome Tax (2015)-378,037 378,036 2
19 Property Tax (2015)-2,722,U9 2,722,849
20 Property Tax (2016)2,Bil,826 5,709,653
2'l BETC Credit (2010 and Prior)-17,483
22 BETC Credit (201 1)-29,962
23 BETC Credit (2012)-57,789
24 Glendale Regulatory Cr. 2009 -34,911
25 Franchise Tax (2015)920,340 -338 920,001 -1
26 Franchise Tax (2016)3,448,708 2,519,669
27 Total Oregon -2,420,691 9,404,081 9,049,323 1
28
29 STATE OF CALIFORNIA:
30 lncome Tax (2016)1.600
3'l Total California 1,600
32
33 MISCELLANEOUS STATES
34 lncome Tax (2013)1
35 lncome Tax (2014)28,632
36 lncome Tax (2015)$46,729 -155,403 802,132
37 Total Misc States 618,096 -155,403 802,132
38
39 COUNTY & MUNICIPAL
40 Vehicle Excise Tax -13,850 13,850
41 TOTAL 7,186,818 57,344,759 80,962,872
FERC FORM NO. 1 (ED. 12-96)Page 262.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn Original(2) jA Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 20161Q4
5. lf any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year,
identifuing 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 othenrvise 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.
TJALANCE AT :ND OF YEAR Line
No.(Taxes accruedAccoln| 236)
Prepaid Taxes
(lncl. in Ap;1ount 165)
Electric(Account408.1,409.1)Extraordinary ltems
(Account 409.3)
Adtustments to h<et.
Earnings (Account 439)
(k)
Other
(t)
1
2
233,684 3
-304,950 -11,057 4
118,720 118,720 5
-9,257 6
422,070 7
4,864,493 9,750,999 I
3,686 I
10
274,416 1,079,381 11
11 -3 12
43 112 13
4,952,733 10,510,511 233,684 14
15
16
17
1 -781 378,817 18
1.358.912 1,363,937 19
-2,854,827 1,262,7U 1,592,072 20
-17,483 21
-29,962 22
-57.789 23
-34,911 24
-338 25
929,039 3,M8,708 26
-2,065,932 2,620,885 6,783,196 27
28
29
-1,600 30
-1,600 3'l
32
33
1 u
28,632 35
-155,403 36
28,633 -155,403 37
38
39
13,850 40
-16,431,293 35,237,427 22j07,332 41
FERC FORM NO.1 (ED. 12-96)Page 263.1
Name of Respondent
Avista Corporation
(1)
(2)
An
A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Penod of Report
End of 20161Q4
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 direcl 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 lax in such manner lhat the total tax for each State and suMivision can readily be ascertained.
Ltne
No.
Kind of Tax
(See instruclion 5)
(a)
BALANCE AT BEGINNING OF YEAR I axesCharoedq{r?s
(d)
'fllB'
R{Jls(e)
Adjust-
ments
(D
I axes Accrueo(Account 236)(b)
Preoaro taxes(lnclude in Account 165)
1 WA Renewable Energy -561 -w,804 -539,726 -1
2 Misc.939 58,508 57,495 -3
3 Total County -13,472 472,M6 482,231 4
4
5
6
7
I
9
10
't1
't2
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 TOTAL 7,186,818 57,344,759 80,962,
FERC FORM NO. 1 (ED. t2-96)Page 262.2
Avista Corporation
(1)
(2)
An
ls:
Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
o3t3112017
Year/Period of Report
End of 2O16lQ4
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 laxes collected through payroll deductions or otheruvise 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.'l 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.
DISTRItsUTION OF TAX Line
No.ffaxes accrued
Account 236)(s)
Prepaid Taxes
(lncl. in A,c;1ount 165)
Electric
(Account 408 1, 409.1)
Extraordinary ltems
(Account 409.3)
Aorustments lo Ket.
Earnings (Account 439)
(k)
Other
(t)
-5,638 -544,804 1
1,949 58,508 2
-3,689 472,446 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
-16,431,293 35,237,427 22,107,332 41
FERC FORM NO.1 (ED.12-96)Page 263.2
Avista Coporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Penod of Report
End of 20'16/Q4
Report below information applicable to Account 255. \Mere 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.
Lrne
No.
Account
sub{iions
Eatanoe aI E eotnnof Year-tng
(b)
Deferred for Year Curren Adjustments
(s)ACCOUnI NO.(c)AmounI(d)AO@UnI NO.(e)Am((,
runl
1 Electric Utility
I 3%
4o/o
4 7%
E 1Oo/o
€12,550,579 411 18,887,908
't
I IOTAL 12,550,579 18,887,908
c Other (List separately
and show 3o/o, 4Yo,7o/o,
10% and TOTAL)
1C Gas Property (100%23,328 411 7,674
11 65,280 411 17,49C
12 IOTAL PROPERTY 88,608 25Jil
13
14
1€
1€
11
18
19
2C
21
22
aa
24
2Z
2e
27
28
3C
3'l
52
a
2E
36
37
38
eo
4A
41
42
43
44
45
46
47
48
FERC FORM NO.1 (ED. 12-89)Page 266
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
(Mo, Da,
oa31nu7
Year/Period of Report
End of 2O16lQ4
Balance at End
of Year
(h)
Averaoe Henooof Allocation
to lncome(i)
ADJUSTMENT EXPLANATION Line
No.
1
2
3
4
5
31,438,487 6
7
31,438,487 I
I
15,654 10
47,790 11
63,444 12
't3
14
15
16
'17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33u
35
36
37
38
39
40
41
42
43
M
45
46
47
48
FERC FORM NO. 1 (ED. t2-89)Page 267
Avista Corporation
(1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
03t3112017
Year/Period of Report
End of 20161Q4
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 greate0 may be grouped by classes.
Line
No.
Description and Other
Deferred Credits
(a)
Balance at
Beginning of Year
(b)
DEBITS
Credits
(e)
Balance at
End of Year
(f)
Contra
Account(c)
Amount
(d)
1 Energy Commodity (253020)14,694,374 124 14,694,374
2 Defer Gas Exchange (253028)1,125,000 1,125,000
3 Rathdrum Refund (253120)138,1 10 550 33,822 104,288
4 NE Tank Spill(253130)3,230 3,230
5 Kettle Falls Diesel Leak (254135)236,1 35 139,960 376,095
b Bills Pole Rentals (253140)184,401 4il 21,459 162,942
7 DOC EECE Grant (253155)17,918 7,910 25,828
8 Defer Comp Active Execs (253910)8,093,780 426 410,580 7,683,200
I Executive lncent Plan (253920)140,000 140,000
10 Unbilled Revenue (253990)8/,8,7y 1,249,835 2,098,569
11 WA Energy Recovery Mechanism 't 1 ,535, 183 186 8j92,200 3,342,983
12 Misc Deferred Credits 2,773,438 407 2,573,455 199,983
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
u
35
36
37
38
39
40
41
42
43
4
45
46
47 TOTAL 39,790,303 25,925,890 1,397,705 15,262,118
FERC FORM NO. 1 (ED. 12-94)Page 269
This Page Intentionally Left Blank
Avista Corporation (1)
(2)
Original
Resubmission 03t31t2017
Year/Period of Report
End of 2O'l6lQ4
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.
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
Amounts Debited
to Account 41 0.'l
(c)
Amounts Credited
to Account 41 1.1
(d)
1 Account 282
2 Electric 443.772,673 59,131,206
3 Gas 135,61 1 ,950 18,297,477
4 Other 67,485,743 6,863,072
5 TOTAL (Enter Total of lines 2 thru 4)il6,870,366 u,291,755
6
7
8
I TOTAL Account 282 (Enter Total of lines 5 thru 646,870,366 u,291,755
10 Classification of TOTAL
11 Federal lncome Tax 646,870,366 u,291,755
12 State lncome Tax
13 Local lncome fax
NOTES
:ERC FORM NO.l (ED.12-96)Page 274
Name of Respondent
Avista Corporation
This Reoort ls:(1) fiAn Original(2) llA Resubmission
Date of Report(Mo, Da, Yr)
o3R1t2017
Year/Period of Report
End of 2O16lQ4
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End ofYear
(k)
Line
No.
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(f)
Debits Credits
Account
Credited(s)
Amount
(h)
Account
Debited
(i)
Amount
0)
1
502,903,87(2
153,909,42i 3
74,348,81a 4
731J62,121 5
6
7
8
731,162,121 9
10
731,'.162,121 11
12
13
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96)Page 275
Name
Avista Corporation (1)
(2)
Original
Resubmission 03R1t2017
Year/Period of Report
End of 20'l6lQ4
1. Report the information called for below @ncerning the respondent's accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),indude deferrals relating to other income and deductions.
Line
No.
Account
(a)
Balance at
Beginning of Year
(b)
CHANGES DURING YEAR
to 41 1 to Accolglt 41 1 .1
1 Account 283
2 Electric
2 Ebclric 16,367,410 't,760,44
4
5
6
7
8
I TOTAL Electric (Total of lines 3 thru 8)16,367,410 1,760,464
10 Gas
11 Gas -3,286,746 u,62e,
12
13
14
15
16
17 TOTAL Gas (Iotal of lines 11 thru 16)-3,2ffi,746 14,626
18 Other 214,729,975 16,799,765
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18)227,810,639 18,574,855
20 Classification of TOTAL
2'l Federal lncome Tax 227,810,639 18,574,855
22 State lncome Tax
23 Local lncome Tax
NOTES
FERC FORrut NO. t (ED. t2-96)Page 276
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]1Rn orisinat(2) fIA Resubmission
Date of Reoort
(Mo, Da, Yi)
o3t3112017
Year/Period of Report
End of 20161Q4
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.
Balance at
End ofYear
ft)
Line
No.
Amounts uebrtecl
to Account 410.2
(e)
Amounts credrted
to Account 41 1.2
(fl
UEDIS cred[s
Amount
(h)
ATIlOUItt
(i)
1
2
737,482 17,390,392 3
4
5
6
7
8
737,482 17,390,392 I
't0
16,669 -3,288,789 1'l
12
13
14
15
16
16,669 -3,288,789 17
5,429,247 4,602,839 232,3fi,148 18
5,429,247 5,356,990 246,457,751 't9
20
5,429,247 5,356,990 246,457,751 21
22
23
NOTES (Continued)
FERC FORM NO. r (ED.12-96)Page 277
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Peraod of Report
End of 2016/Q4
OTHER REGULATORY LIABILITIES (Account 254)
1. Report below the particulars (details) called for conce.rning 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
Ouarterl/ear
(b)
DEBITS
Credits
(e)
Balance at End
of Current
Quarterffear
(0
ACCOUnt
Credited
(c)
Amount
(d)
1 ldaho lnvestrnent Tax Credit (254005)1 1,288,009 190 2,093,60€9.1 94.40:
2 Oregon BETC Credit (2540'10)1,099,872 190 88,443 1,011,425
3 Settled lnt Rate Swaps (254090)14,271,U7 428 1,829,707 12,M1.UC
4 Unseftled lnt Rate Swaps (254100)22,687 8,726,86t 8,749,555
5 FAS 109 lnvest Credit {254180)47,712 190 '13,551 34,161
6 Nez Perce (254220)616,340 557 22,008 594,33i
7 ldaho Eamings Tesl (2?42291 760,068 2,936,80{3.696.87:
8 Decouplinq Rebate (254338)2,4U,911 2,404,91€
9 BPA RES EXCH (254345)428,624 239,00'.667,62a
10 Other Regulatory Liabilities 1,841,650 190 27,105 1,814,54a
't1 WA ERM 6,457,271 1 1,490,39(17,947,67C
12 ID PCA 754,958 1,482,431 2.237.391
13 RoseburqNedford 8,729 182 8,729
14 Defened Federal ITC 3,379,017 190 62,40C 13,628,90r 16,945,52i
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 TOTAL 40,976,484 4,'145,54!40,909,333 77,740,268
FERC FORM NO. r/3{ (REV 02-04)Page 278
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An originat(2) f]A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2016/Q4
ELECTRIC OPERATING REVENUES I
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 not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are added
for billing purposes, one customer should be counted for each group of rneters added. The -average number of custorners means th'e 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 $250,000 or greater in a footnote for accpunts 451, 456, and 457.2.
Line
No.
Title of Account
(a)
operating Revenues Year
to Date Quarterly/Annual
(b)
Operating Revenues
Previous year (no Quarterly)
(c)
1 Sales of Eleclricity
2 (440) Residential Sales 339,210,392 335,551,962
3 (442) Commercial and lndustrial Sales
4 Small (or Comm.) (See lnstr. 4)305,612,410 308,210,379
5 Large (or lnd.) (See lnstr. 4)107,296,247 111,769,969
6 (444) Public Street and Highway Lighting 7,662,138 7,276,497
7 (445) Other Sales to Public Authorities
8 (,146) Sales to Railroads and Railways
9 (1148) I nterdepartmental Sales 1,193,923 1,190,013
10 TOTAL Sales to Ultimate Consumers 760,975,110 763,998,820
'11 (/147) Sales for Resale 1 1 8,815,965 133,316,869
12 TOTAL Sales of Electricity 879,791,075 897,315,689
't3 (Less) (449.1) Provision for Rate Refunds -93't,768 5,620,861
14 TOTAL Revenues Net of Prov. for Refunds 880,722,U3 891,694,828
'15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451 ) Miscellaneous Service Revenues 437,415 252,517
18 (453) Sales of Water and Water Power 356,663 407,336
19 (454) Rent from Electric Property 2,802,518 2,632,221
20 (455) I nterdeparlmental Rents
21 (456) Other Electric Revenues 107,066,515 96,6s0,358
22 (456.1) Revenues from Transmission of Electricity of Others 13,51 1 ,670 14,502,801
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 't24,174,781 114,445,233
27 TOTAL Electric Operating Revenues 1,004,897,624 1,006,140,061
FERC FORM NO. r/3-Q (REV. 12-05)Page 300
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn Original(2) jA Resubmission
Date of Reoort
(Mo, Da, Yi)
03131t2017
Year/Period of Report
End of 2016/Q4
ELECTRIC OPERATING REVENUES I
respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of classification
in a footnote.)
7. See pages 10&109, lmportant Changes During Period, for important ne$/ territory added and important rate increase or decreases.
8. For Lines 2,4,s,and 6, see Page 304 forarnounts relating to unbilled revenue by accounts.
9. lnclude unmetered sales. Provide details of such Sales in a botnote.
MEGAWATT HOURS SOLD AVG.NO. CUSTOMERS PER MONTH Line
No.Year to Date Quarterly/Annual
(d)
Amount Previous year (n0 Quarterly)
(e)
Current Year (no Quarterly)
(f)
Previous Year (no Quarterly)
(s)
1
3,527,707 3,571,426 330,699 329,874 2
3
3,182,594 3,196,583 41,785 41,71C 4
1,763,248 1,81 1,996 1,342 1,364 5
23,317 23,304 558 551 6
7
8
12,4U 12,v5 123 11t 9
8,509,330 8,615,654 374,507 373,614 10
3,224,2%3,326,381 11
11,733,626 1 1,942,035 374,507 373,614 12
13
11,733,626 11,942,035 374,507 373,614 14
Line 12, column (b) includes $
Line 12, column (d) includes
4,906,228
50,276
of unbilled revenues.
M\A/l-l relating to unbilled revenues
FERC FORM NO. 1r3-Q (REV. 12-05)Page 30.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn Originat(2) aA Resubmission
Date of Report(Mo, Da, Y0
03t3112017
Year/Period of Report
End of 20'l6lQ4
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 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.
Lrne
No.
t\umDer ano tllte or KaIe scneoute
(a)
MVVN DOlo
(b)
l(evenue
(c)
NvvnPer (TWflS%6''(f)
1 RESIDENTIAL SALES (440)
I 1 Residential Service 3,361,950 309,542,263 314,247 10,69€0.0921
2 Residential Service 5,481 325,669 462 11,854 0.0594
4 3 Residential Service
E 12 Res. & Farm Gen. Service 79,442 11,1U,078 14,195 5,59€0.1408
€15 MOPS ll Residential
22 Res. & Farm Lg. Gen. Service 38,875 3,458,817 6€589,01€0.0890
8 30 Pumping-Special
c 32 Res. & Farm Pumping Service 8,468 "1,047,680 1,729 4,898 0.1237
1C 48 Res. & Farm Area Lighting 3,998 1,056,423 0.2642
11 49 Area Lighting-High-Press.234 75jU 0.3267
lz 56 Centralia Refund
13 95 Wind Power 140,826
14 72 Residential Service
1€73 Residential Service
1€74 Residential Service
1i 76 Residential Service
1t 77 Residenlial Service
1S 58A Tax Adjustment -30,1 92
2C 58 Tax Adjustment 9,225,107
21 SubTotal 3,498,444 336,025,805 330,699 10,57S 0.0961
22 Residential-Unbilled 29,263 3,184,587 0.1 088
23 Total Residential Sales 3,527,707 339,210,392 330,699 10,667 0.0962
24
2a CoMMERCTAL SALES (442)
2e 2 General Service
2i 3 General Service
2t 11 General Service 876,863 98,871,175 37,773 23,214 0.1 128
2S '12 Res. & Farm Gen. Service 1,822,21'l 161,059,383 2,814 647,552 0.0884
3C 16 MOPS ll Commercial
3l ''l 9 Contrac{-General Service
32 21 La1ge General Service
5J 25EAra Lg. Gen. Service 356,984 22,769,089 13 27,46030e 0.0638
a 28 Contrac{-Extra Large Serv
CE 31 Pumping Service 95,763 8,168,172 't , 185 80,813 0.0853
3€47 Area Lighting-Sod. Vap 6,028 1,416,031 0.2349
37 49 Area Lighting-High-Press.2,567 615,958 0.2400
3€56 Centralia Refune
2C 95 Wind Power 89,690
4C 74 Large General Service
41 TOTAL BiIIed 1't,683,35(874,88/.,U7 374,501 31,19i 0.074s
42 Total Unbilled Rev.(See lnstr. 6)50,278 4,906,228 ((0.097€
43 TOTAL 11,733,62e 879,791,075 374,50i 31,33'1 0.075c
FERC FORM NO.1 (ED.12-95)Page 304
Name
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
SALES OF ELE,L; I RICI I Y tsY RA I E SUHELIULE,S
1. Report below for each rate schedule in effect during the year the MWH of eleclricity 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. Wrere 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.
Ltne
No.
t\utlilJet an(] I tue or Kare scneoute
(a)
MWn 50to
(b)
Kevenue
(c)rs TWrTS"oE"'(0
1 75 Large General Service
76 Large General Service
77 General Service
4 58A Tax Adjustment 40,75e
E 58 Tax Adjustment 10,875,50C
€SubTotal 3,160,41€303,824,242 41 .785 75,635 0.0961
Commercial-Unbilled 22,17t 1 ,788, 1 6€0.0806
€Total Commercial 3,182,594 305,612,41C 41.785 76,16€0.0960
c
1C TNDUSTRTAL SALES (442)
11 2 General Service
12 3 General Service
4a I Lg Gen Time of Use
14 11 General Service '10,97€'t,265,558 257 42.708 0.1 1 53
1!12 Res. & Farm Gen. Service
1€21 Large General Service 185,61€16,169,058 145 1.280.11C 0.0871
17 25EAra Lg. Gen. Service 1,478,492 81,603,848 19 77.815.368 0.0552
1e 28 Contract - Extra Large Service
19 29 Contract Lg. Gen. Service
2E 30 Pumping Service - Special 22,18i 1,571,018 31 715.71C 0.0708
21 31 Pumping Service 62,709 5,442,976 762 82,295 0.0868
22 32 Pumping Svc Res & Firm 4,185 380,708 128 32,695 0.0910
z!47 Area Lighting-Sod. Vap 179 38,418 0.2146
24 49 Area Lighting - High-Press 68 15,076 0.2217
2a 95 \Mnd Power 898
26 48 Area Lighting-Sod. Vap.1 238 0.2380
27 73 General Service
28 T4Large General Service
29 75 Large General Service
30 76 Pumping Service
31 77 General Service
32 58A Tax Adjustment -1,'t85
e?58 Tax Adjustment 876,163
v SubTotal 1,764,413 107,362,774 1,U2 1,314,7U 0.060€
35 lndustrial-Unbilled -1,'165 -66,527 0.0571
36 Total lndustrial 1,763,248 107,296,247 1,342 1,313,896 0.0609
37
38 STREETAND H\ rY LTGHTTNG (444)
?o 6 Mercury Vapor St. Ltg.
40 7 HP Sodium Vap. St. Ltg
41 TOTAL Billed 11,683,35C 874,88/.,Ui 374,501 31,19;0.074(
42 Total Unbilled Rev.(See lnstr.6)50,27e 4,906,228 (0.097(
43 TOTAL 11,733,62e 879,791,074 374,50i 31.33'0.075(
FERC FORM NO.1 (ED.12-9s)Page 304.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn orisinat(2) l-lA Resubmission
Date of Reoort
(Mo, Da, Yi)
03t3112017
Year/Period of Report
End of 2O16lQ4
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 ac@unt 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.
Lrne
No.
r\umoer ano r me or KaIe scneoute
(a)
MVVn DOlo
(b)
Kevenue
(c)FEYt:j.i"li"TWflS%6"'(0
1 11 General Service
2 41 Co-Owned St. Lt. Service 19€38,96€13 15,077 0.1 988
42 Co-Owned St. Lt. Service 19,33€6,964,04i 43S M,052 0.3601
4 High-Press. Sod. Vap.
E 43 Cust-Owned St. Lt. Energy
€and Maint. Service
7 rt4 Cust-Owned St. Lt. Energy 62C 92,952 2e 22,'143 0.'t499
I and Maint. Svce - High-Pres
I Sodium Vapor
1C 45 Cust. Owned St. Lt. Energy Svc 1 ,019 78,351 14 72,786 0.0769
11 46 Cust. Owned St. Lt. Energy Svc 2,'t4?213,883 64 33,4U 0.0998
12 58A Tax Adjustment -797
13 58 Tax Adjustment 274,73e
14 SubTotal 23,317 7,662,13e 558 41,787 0.328€
15 Street & Hwy Lighting-Unbilled
16 Total Street & Hwy Lighting 23,317 7,662,138 558 41,78i 0.328€
17
18 OTHER SALES TO PUBLIC
19 (445)
2A None
21
22 INTERDEPARTMENTAL SALES 12,464 1 , 193,923 123 101,33:0.09s8
23 58 Tax Adjustment
24 Total lnterdepartmental 12,464 1 ,1 93,923 123 101,33:0.0958
25
26 SALES FOR RESALE (447)
21 61 Sales to Other Utilities (NDA)3,224,296 1 18,81 5,965 0.0369
2t
2S
3(Total Sales for Resale 3,224,296 1 1 8,815,965 0.0369
31
5z
3a
a
AE
3€
3i
3€
?c
4C
41 TOTAL BiIIed 11,683.35(874,88/..U7 374.50i 31,'t97 0.074s
42 Total Unbilled Rev.(See lnstr. 6)50,271 4,906,228 c (0.097€
43 TOTAL 11,733$21 879,791,075 374,50i 31,331 0.075c
FERC FORM NO.1 (ED.12-9s)Page 304.2
This Page Intentionally Left Blank
Name s:
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
nt
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electrici$ ( 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-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-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
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVgt aug
Monthly NCF Deman,
(e)
Averaoe
Monthly CFrDemand
(f)
1 Avangrid Renewables, LLC SF Tariff 9
2 LLC SF Tariff 9
3 BP Energy Company SF Tariff 9
4 Black Hills Power, lnc.SF Tariff 9
5 Bonneville Power Administration LF Tariff 8
6 Bonneville Power Administration LF ACS-06
7 Bonneville Power Admin istration SF Tariff 9
8 Bonneville Power Admin istration larifl 12
I Brookfield Energy Marketing, LP SF Tariff 9
't0 California lndependent System Operator 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 Coung PUD No. 1 LF Tarifl 12
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90)Page 310
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t31t2017
Year/Period o, Report
End of 20161Q4
OS - for other service. use this €tegory 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 repo(ed 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
($)
(D
Other Charges
($)
0)
323,403 5,201,s28 5,201,s2e 1
345,56C 345.56C 2
27,990 729.972 729,972 3
40 400 40c 4
17,O75 370,504 370,504 5
4,244 67,783 67,783 6
104,200 1,884,526 1.884.52e 7
280 6,436 6,43€8
56 1.542 1,542 9
262 7.374 7,374 10
26,288 422,295 422,29r 11
11.816 182,978 182,978 12
10,405 358,861 358,861 13
1 18 18 14
0 0 0 0 0
3,224,296 22,274,812 51,281,232 4s,259,921 118,815,965
3,224,296 22,274,8'.12 51,281,232 45,259,921 't 18,815,965
FERC FORM NO. 1 (ED. 12-90)Page 311
Name of Respondent
Avista Corporation (1)
(2)
Original
Resubmission
Date of ReDort(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 20161Q4
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 service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term flrm 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 reliabilig 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
Monthly Billing
Demand (MW)
(d)
Actual Demand
(e)(D
1 Citigroup Energy, lnc.SF Tariff 9
2 City of Redding SF Tariff 9
3 Clark County PUD No. 1 SF Tariff 9
4 Clatskanie Peoples PUD SF Tariff 9
5 ConocoPhillips SF Tariff 9
b Douglas County PUD No. 1 SF Tariff 9
7 Douglas County PUD No. 1 LF TariIf 12
I EDF Trading North America, LLC SF Tariff 9
9 Energy America, LLC LF Tarifi 9
10 Energy Keepem, lnc.SF Tariff 9
11 Eugene Water & Electric Board SF Tarifi 9
12 Exelon Generation Company, LLC SF Tariff 9
13 Gridforce Energy Management, LLC Tarill 12
14 ldaho Power Company SF Tariff 9
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
\ FERc FoRM No.1 (ED. i2-eo)Page 310.'l
Name of Respondent
Avista Corporation
S:
(1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Y0
03t31t2017
Year/Period of Report
End of 20'l6lQ4
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 (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 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 (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
4Ol,iine 24.
10. Footnote entries as required and provide explanations following all required data.
Megawatt Hours
Sold
(s)
REVENUE rotal($)
(h+i+j)
(k)
Line
No.Demand Charges
($)
(h)
Energy Charges
($)
(i)
Other Charges
($)
(i)
25,570 656,505 656,505 1
640 13,800 13,80C 2
7,888 168,125 1 68,1 2f 3
4,653 93,195 93,1 9!4
7,800 150,340 150,34C 5
3,095 65,960 65,96C 6
4 77 77 7
105,912 2,269,106 2,269,10€I
585,570 13,462,495 13,462,495 9
2,702 76,U1 76,U1 10
23,218 3il,077 3il,077 11
36,831 709,404 709,404 12
52 1,317 1,317 13
1,450 28,928 28,928 14
0 0 0 0 0
3,224,296 22,274,812 51,281,232 45,259,921 118,815,965
3,224,296 22,274,812 51,281,232 45,259,921 118,815,965
FERC FORM NO. 1 (ED.12-90)Page 311.1
s:
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
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 repo(ed 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 seryice. 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{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{erm 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" rneans
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
MonthV Billing
Demand (MW)
(d)
Actual Demand (MW)
AVetaoe
Monthly NCF Demanr
(e)
AveraoeMonthly CPDemanc
(0
1 ldaho Power Company LF Taritl 12
2 ldaho Power Balancing SF Tariff 9
3 Kootenai Electric Cooperative LF Tariff 8
4 Macquarie Energy, LLC SF Tariff 9
5 Mizuho Securities USA, lnc.SF ISDA
6 Morgan Stanley Capital Group, lnc.SF Tariff 9
7 Morgan Stanley Capital Group, lnc.SF Tariff 9
I Morgan Stanley Capital Group, lnc.SF Tariff 9
I Morgan Stanley Capital Group, lnc.SF Tariff 9
'10 NaturEner Power Watch, LLC SF Tariff 9
11 NaturEner Power Watch, LLC Tarifi 12
12 NaturEner Power Watch, LLC SF Tariff 9
13 NaturEner Power Watch, LLC SF Tariff 9
14 NaturEner Power Watch, LLC SF Tariff 9
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total c 0 0
FERC FORM NO.1 (ED.12-90)Page 310.2
s:
Avista Corporation
(1)
(2)
Original
Resubmission
Date of Reoort
(Mo, Da, Yi)
03t31t2017
Year/Periocl of Report
End of 20161Q4
OS - for other service. use this category only for those serviees 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 (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
4O1,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
($)
(i)
Other Charges
($)
0)
69 1,574 1,574 1
30,729 717,225 717,225 2
2,032 40,596 40,596 3
96,529 1 ,904,1 1 3 1,904,1 13 4
't8,982,975 18,982,975 5
183,514 3,385,750 3,385,750 6
276,696 276,696 7
938,732 938,732 I
181,146 181,146 I
7,465 149,017 149,017 't0
32 767 767 11
179,214 179,214 12
276,696 276,696 13
574 570 14
0 0 0 0 0
3,224,296 22,274,812 51,281,232 45,259,921 1 18,81 5,96s
3,224,296 22,274,812 51,281,232 45,259,921 118,81s,965
/
FERC FORM NO. 1 (ED. 12-90)Page 3'11.2
Respondent S:
Avista Corporation (1)
(2)
Original
Resubmission
Date of ReDort
(Mo, Da, Yi)
03t31t2017
Year/Penod of Report
End of 2O16lQ4
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 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.
Line
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)
AVeraoe
Monthly NCF Deman,
(e)
Averaoe
Monthly CPDemand
(0
1 Nevada Power Company SF Tariff 9
2 Nevada Power Company dba NV Energy SF Tariff 9
3 Noble America Gas & Power SF Tariff 9
4 NorthWestern Energy LLC SF Tariff 9
5 NorthWestern Energy LLC LF Tarill 12
6 NorthWestern Energy LLC LF Tariff 9
7 NorthWestern Energy LLC SF Tariff 10
8 Okanogan County PUD SF Tariff 9
I PacifiCorp SF Tariff 9
10 PacifiCorp Itr larill 12
11 PacifiCorp LF Tariff 9
12 Pend Oreille Public Utility District IF Tariff 9
13 Pend Oreille Public Utility District IF Tariff 9
14 Pend Oreille Public Utility District SF Tariff 9
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
:RC FORM NO. 1 (ED. 12-90)Page 310.3
Name of Respondent
Avista Corporation (1)
(2\
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
o3t31t2017
Year/Period of Report
End of 20161Q4
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 0). 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
4O1jine 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
($)
(i)
other charges
($)
fi)
1,675 10,992 10,992 1
21,2U 334,562 3y,562 2
400 6,960 6,96C 3
155,280 4,307,064 4,307,064 4
76 2,009 2,009 5
7,493 139.778 139,778 6
2,86C 2,860 7
3,6't4 97,314 97,314 8
145,053 2,652J62 2,652,162 9
286 7,076 7,076 10
4,771 88,949 88,949 11
600,528 600,528 12
20,357 389,516 389,516 13
137,395 3,290,502 3,290,502 14
0 0 0 0 0
3,224,296 22,274,812 51,281,232 45,259,921 1 18,81 5,96s
3,224,296 22,274,812 51,281,232 45,259,92',1 118,815,965
FERC FORM NO. 1 (ED. 12-90)Page 311.3
S:
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2016/Q4
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 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. "Longterm" 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
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
Monthly Dema
1 Portland General Electric Company SF Tariff 9
2 Portland General Electric Company LF Taritf 12
3 Portland General Electric Company IF Tariff 9
4 Powerex SF Tariff 9
5 Public Service Company of Colorado SF Tariff 9
6 Puget Sound Energy LF Tariff 9
7 Puget Sound Energy SF Tariff 9
8 Puget Sound Energy Tariff 12
9 Rainbow Energy Marketing SF Tariff 9
10 Sacramento Municipal Utility District SF Tariff 9
11 Sacramento Municipal Utility District LF Taritl 12
12 Seattle City Light SF Tariff 9
13 Seattle City Light LF Tarift 12
14 SG Americas Securities, LLC SF ISDA
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total (0 0
RC FORM NO. 1 (EO. 12-90)Page 310'4
Avista Corporation (1)
(2)
An Original
A Resubmission
Dale of ReDort
(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2O16lQ4
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 (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,iine24.
10. Footnote entrles 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
($)
(i)
Other Charges
($)
o
101,170 1,939,979 1,939,97S 1
72 1,852 1,852 2
19,278,000 19,278,000 3
124,U8 1,900,8'10 1,900,810 4
17,000 u2,310 v2,310 5
21.799 406,626 406,626 b
72,195 1,615,185 1,615,185 7
23 384 384 8
6,389 '170,749 170,749 9
668 9,533 9,533 10
4 109 109 1'l
19.743 355,869 35s,869 12
3 80 80 13
7,987,108 7,987,108 14
0 0 0 0 0
3,224,25fi 22,274,812 51,28'1,232 45,259,921 118,815,965
3,224,296 22,274,812 s1,281,232 45,259,921 118,815,965
FERC FORM NO. r (ED. r2-90)Page 311.4
Name of Respondent
Avista Corporation
ron ls:
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
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 electricig ( 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{erm" 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 or
Tariff Number
(c)
Averaoe
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW)
AVeraoe
Monthly NCF Demanr
(e)
AveraoeMonthly CFrDemanc
(f)
1 Shell Energy N.A.SF Tariff 9
2 Shell Energy N.A.SF Tariff 9
3 Sierra Pacific Power Company LF Tarifi 12
4 Snohomish County PUD SF Tariff 9
5 Sovereign Power Tariff 9
6 Sovereign Power LF Tariff 9
7 Tacoma Power SF Tariff 9
8 Tacoma Power LF Tarifl 12
I Tacoma Power Tariff 9
10 Talen Energy Marketing, LLC SF Tariff 9
11 Talen Energy Montana, LLC Tariff 9
12 The Energy Authority SF Tariff 9
13 TransAlta Energy Marketing SF Tariff 9
14 Turlock lrrigation District SF Tariff 9
Subtotal RQ c 0 0
Subtotal non-RQ c 0 0
Total 0 0 0
FERC FORM NO.1 (ED. 12-90)Page 310'5
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t3112017
Year/Period of Report
End of 20161Q4
OS - for other service. use this category only for those services which ca nnot 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 LongeQ 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,iine24.
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
($)
(i)
Other Charges
($)
fi)
v3,023 6,487,697 6,487,69i 1
M,274 44,27C 2
68 1 ,318 1 ,31f 3
12,440 346,265 346,26!4
150,492 150,492 5
14,070 276FU 276,534 6
13,534 247,372 247.372 7
4 64 64 I
4e 4t I
39,493 620,601 620,601 10
't7,028 317,676 317,67e 11
22,050 429,234 429,234 12
248,423 4,415,602 4,415,602 13
800 't4,660 14,66C 14
0 0 0 0 0
3,224,296 22,274,812 51,281,232 45,259,921 1 18,815,965
3,224,296 22,274,812 51,28',t,232 45,259,921 118,81s,96s
FERC FORM NO. 1 (ED. 12-90)Page 311.5
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 20161Q4
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, capaci$, 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 purchaset.
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 "intqrmediate-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
Monthly
1 Wells Fargo securities, LLC SF ISDA
2 lntraCompany Wheeling LF
3 lntraCompany Generation
4
5
b
7
8
I
10
11
12
13
14
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. r (ED.12-90)Page 310.6
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 20161Q4
nt
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 (D. For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-mlnute 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)
Other Charges
($)
(i)
3,037,91€3,037,916 1
-13,429,090 13,429,09C 2
1,822,832 1,822,832 3
4
5
6
7
8
9
10
11
12
13
14
0 0 0 0 0
3,224,296 22,274,812 51,281,232 45,259,921 118,815,965
3,224,296 22,274,812 51,281,232 45,259,921 118,815,965
FERC FORM NO. 1 (ED. 12-90)Page 311.6
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQl A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule 310 Line No.: 7 Column: a
Name chan in 2076. Formerl I r aRe ES LLC.310 Line No.: 2 Column: a
Name c an n 1 Formerl-Iberdrol-a Renewables, LLC.
cit
,Schedule 310 Line No.: 5 Column: b
BPA Contract Terminates ember 30 2028.
BPA Contract Term ates Janua 1
310 Line No.: I Column: b
NWPP Reserve Shar:-Sales
Schedule 310 Line No.: 14 Column: b
NWPP Reserve Shari Sales
Schedule 310.1 Line No.:7 Column: b
NlrlPP Reserve Shari Sales
Ene Amer LLC contract term ates 1 1
Schedule 310.1 Line No.: 13 Column: b
NWPP Reserve Shar Sales
NWPP Reserve Shar:-n Sales
310.2 Line No.: 3 Column: b
Kootenai Contract Terminates March 31,20L9
Schedute Page: 310.2 tine Nc-: { Cotumni
SWAP
Schedule Pase: 310.2 Line No.:7 Column: b
C ci.t
Ca cit
NWPP Reserve S ar Sa ES
Ca Lt
Ca cit
NWPP Reserve Shari Sales
Northwestern Ene LLC s res Oct r31 018 .
NWPP Reserve
Schedule 310.3 Line No.: 11 Column: b
Pac sal-e terminates October 31 2018
Contract ex ires 9 2071
310.3 Line No.: 13 Column: b
Contract e ires 9/30 /2071
NWPP Reserve ar n S al-e s
Contract res 12 31 201,6.
FERC FORM NO.1 (ED. 12-871 Paqe 450.1
310 Line No.:2 Column: b
310 Line No.: 6 Column: b
310.1 Line No.: 9 Column: b
310.2 Line No.: 1 Column: b
310.2 Line No.:8 Column: b
310.2 Line No.: 11 Column: b
310.2 Line No.: 13 Column: b
310.2 Line No.: 14 Column: b
310.3 Line No.: 5 Column: b
310.4 Line No.: 2 Column: b
310.4 Line No.: 3 Column: b
310.4 Line No.: 6 Column: b
Puget Sound Energy safe terminates October 31, 201,8.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
201.6tA4
FOOTNOTE DATA
Schedule Pase: 310.4 Line No.: I Column: b
NWPP Reserve Shari-Sales
NWPP Reserve Shar SaIes
NWPP Reserve Sharl Safes
310.4 Line No.: 14 Column: b
SWAP - Formerl Newe USA, LLC
NWPP Reserve ar SaIes
Sovere Power contract te nates 9-
Sovere Power Contract te nates
0-
79
310.4 Line No.: 11 Column: b
310.4 Line No.: 13 Column: b
310.5 Line No.: 3 Column: b
310.5 Line No.: 5 Column: b
310.5 Line No.: 6 Column: b
310.5 Line No.: I Column: b
NWPP Reserve Shari Sales
Sale termi-nates October 31 2018.
310.5 Line No.: 11 Column: b
310.6 Line No; 1 Column: b
SWAP
310.6 Line No.: 2 Column: b
Intracompany Wheel ang te nates
310.6 Line No.: 3 Column: b
IntraCompany Generation - Sal-e o An I ary Serv
FERC FORM NO.1 (ED. 12-871 Page 450.2
Name of Respondent
Avista Corporation
This Reoort ls:(1) E]An Orisinar(2) nA Resubmission
Date of Reoort
(Mo, Da, Yi)
o3t3112017
Year/Period of Report
End of 2016/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
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 Suoervision and Enqineerino 282.011
5 (501) Fuel 30.il2,478 30,794,427
6 (502) Steam Expenses 4,462,449 5,199,150
7 (503) Steam from Olher Sources
I (Less) (504) Steam Transferred-Cr
o (505) Electric ExDenses 1 't,228,906
10 (506) Miscellaneous Steam Power Expenses 3,277,448 2,967,067
11 (507) Rents 41,383 33,667
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4lhtu 12\39,843,511 40,505,228
14 Maintenance
15 (510) Maintenance SuDervision and Enoineerinq 582.812 613,157
16 (51 1) Maintenance of Structures 705,123 758,347
17 (512) Maintenance of Boiler Plant 7.206.9U 4,760.690
18 (513) Maintenance of Electric Plant 2,43',t,5s1 601,012
19 (514) Maintenance of Miscellaneous Steam Plant 1.707.818 954.982
20 TOTAL Maintenance (Enter Total of Lines 1 5 thru 19)12,634,208 7,688,188
21 TOTAL Power Produclion Expenses-Steam Power (Entr Tot lines 13 & 20)52.477.719 48.193.416
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Enqineerinq
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24lhru 32)
34 Maintenance
35 (528) Maintenance Supervision and Enqineerinq
36 (529) Maintenance of Struclures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Produclion Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 (535) Operation Supervision and Engineering 2,884,533 2,107,Ue
45 (536) Water for Power 1.081.024 1.300.90c
46 (537) Hydraulic Expenses 7,226,698 7,201,534
47 (538) Electric ExDenses 7.143.773 6.559.863
48 (539) Miscellaneous Hydraulic Power Generation Expenses 909,432 876,50S
49 (540) Rents 6.760.553 7.10926C
50 TOTAL Operation (Enter Total of Lines 44 thru 49)26,006,013 25,155,713
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering 904,296 1,616,897u(542) Maintenance of Structures 514.792 326.758
55 (543) Maintenance of Reservoirs. Dams. and Watenrvavs 2.372.453 1,375,773
56 (544) Maintenance of Elec{ric Plant 3,060,034 2.663.275
57 (545) Maintenance of Miscellaneous Hydraulic Plant 723,863 696,377
58 TOTAL Maintenancr (Enter Total of lines 53 thru 57)7.575.438 6,679,080
59 TOTAT Power Production Expenses-Hydraulic Power (tot of lines 50 & 58)33,581,451 31,834,793
FERC FORM NO.1 (ED. 12-93)Page 320
Avista Corporation
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 20161Q4
lf the amount for previous year is not derived from previously reported figures, explain in footnote
Line
No.
Account
(a)
Amount forPrevious Year
(c)
60 D. Other Power Generation
61 Operation
62 (546) Ooeration Suoervision and Enqineerinq 1,218,661 1.179.973
63 (547) Fuel 77,198,987 91,777,298u(548) Generation Exoenses 1.58r'..424 2,016,313
65 (549) Miscellaneous Other Power Generation Expenses 595,889 461,399
bt)(550) Rents -33,671 -33,315
67 TOTAL Operation (Enter Total of lines 62 thru 66)80,564,290 95,401,668
68 Maintenance
69 (551) Maintenance Suoervision and Enqineerinq 631,364 625,187
70 (552) Maintenance of Structures 127.'t87 1 10.380
71 (553) Maintenance of Generatinq and Electric Plant 3,'t97,659 2,317,590
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 270,149 453.4'13
73 TOTAL Maintenance (Enler Total of lines 69 thru 72)4,226,359 3.506,570
74 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73)84,790,649 98,908,238
75 E. Other Power Suoolv Exoenses
76 (555) Purchased Power 147,226,728 172.688.007
77 (556) System Control and Load Disoatchinq 750,333 1.0/,9.171
78 (557) Other Expenses 79,059,451 84,496,4'1€
79 TOTAL Other Power Suoolv Exp (Enter Total of lines 76 thru 78)227.036.512 258,233,594
80 TOTAL Power Produc{ion Exoenses fiotal of lines 21 , 41 , 59,74 & 79)397,886,331 437,170,041
81 2. TRANSMISSION EXPENSES
82 Operation
83 (560) Operation Supervision and Engineering 2.540,071 2,1 1 9,61 8
84
85 (561.1 ) Load Dispatch-Reliabilitv 58,701 94,738
86 (561.2) Load Dispatch-Monitor and Operate Transmission System 1,533,643 1,377 ,187
87 (56'1.3) Load Dispatch-Transmission Service and Scheduling 1,241.357 1.082.332
88 (561.4) Schedulinq, Svstem Control and Dispatch Services
89 (561 .5) Reliability, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation lnterconnection Studies
92 (561.8) Reliability, Planninq and Standards Development Services
93 (562) Station Expenses 436,845 532,894
94 (563) Overhead Llnes Exoenses 513,129 458,587
95 (564) Underground Lines Expenses
96 (565) Transmission of Electricitv bv Others 17,251,359 17,389,891
97 (566) Miscellaneous Transmission Expenses 2.431.975 2.162,711
98 (567) Rents 190,703 153,599
99 TOTAL Operation (Enter Total of lines 83 thru 98)26,197,783 25.371.557
100 Maintenance
101 (568) Maintenance Supervision and Engineering 1,019,083 808,914
102 (569) Maintenance of Structures 673,664 737,752
'103 (569.1) Maintenance of Computer Hardware
't04 (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 1,331,446 1,358,489
108 (571) Maintenance of Overhead Lines 1,783,246 1,147,565
109 (572) Maintenance of Underqround Lines 1,656 9,887
110 (573) Maintenance of Miscellaneous Transmission Plant 83,000 107,904
111 TOTAL Maintenance (Total of lines 101 thru 110)4,892,095 4,170,511
112 TOTAL Transmission Expenses (Total of lines 99 and 1 1 1)31,089,878 29,542,068
FERC FORM NO. I (ED. 12-93)Page 321
Name of Respondent
Avista Corporation
This
(1)
(2)
Reoort ls:
E]An Original
nA Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Yeer/Period of Report
End of 20'16/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount forPrevious Year(c)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
116 (575.2) Dav-Ahead and Real-Time Market Facilitation
117 (575.3) Transmission Rights Market Facilitation
118 (575.4) Caoacitv Market Facilitation
't 19 (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 1 5 thru 122)
124 Maintenance
't25 (576.1) Maintenance of Struclures and lmprovements
126 (576.2) Maintenancc of Computer Hardware
127 (576.3) Maintenancc of Computer Soflware
't28 (576.4) Maintenancc of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Reoional Transmission and Market Op Expns fiotal 123 and 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
1v (580) Operation Supervision and Engineering 4,319.006 4.112.229
135 (581) Load Dispatchinq
't36 (582) Station Expenses 726,116 742,05C
137 (583) Overhead Line Expenses 2,193,999 1,999,534
138 (5M) Underground Line Expenses 1,259,690 1.425.474
139 (585) Street Liqhtinq and Sional Svstem Exoenses 13,783 12,58i
140 (586) Meter Expenses 1.814j82 1.973.573
141 (587) Customer lnstallations Expenses 760,909 610,596
142 (588) Miscellaneous Exoenses 8,042,296 7.3U.740
143 (589) Rents 350.728 262,687
144 TOTAL Operation (Enter Total of lines 134 thru 143)19.480,709 18,473,470
145 Maintenance
146 (590) Maintenance Suoervision and Enoineerino 1,459,904 2,167,990
147 (591) Maintenance of Structures 464,296 388,297
148 (592) Maintenance of Station Eouioment 922,580 1,079,662
149 (593) Maintenance of Overhead Lines 7,888,006 10,4U,367
150 (594) Maintenance of Underqround Lines 663,260 839.424
151 (595) Maintenance of Line Transformers 376,486 674.935
152 (596) Maintenance of Street Liohtino and Sional Svstems 308,865 692,950
153 (597) Maintenance of Meters 23,1il 25,403
1il (598) Maintenance of Miscellaneous Distribution Plant 605,435 1,073,353
155 TOTAL Maintenance (Total of lines 146 thru 154)12,711,986 17,426,381
156 TOTAL Distribution Expenses fiotal of lines 144 and 155)32.192.695 35,899,851
'157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 338,763 3fi,243
160 (902) Meter Reading Expenses 3.314.512 3.082,621
161 (903) Customer Records and Collection Expenses 9,634,087 8,795,51C
162 (9O4) Uncollectible Accounts 3,170,040 3.M1.287
163 (905) Miscellaneous Customer Accounts Expenses 245,092 263,64€
1U TOTAL Customer Accounts Expenses (Total of lines 159 thru 163)1 702 15,539,307
FERC FORM NO. 1 (ED. 12-93)Page 322
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn Original(2) jA Resubmission
Date of Report(Mo, Da, Y0
03t31t2017
Year/Period of Report
End of 2016/Q4
lf the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
Amount forCurrent Year
(b)
Amount forPrevious Year(c)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses 23,708,390 24.624,682
169 (909) lnformational and lnstructional Expenses 960,519 880,400
170 (910) Miscellaneous Customer Service and lnformational Expenses 236,300 107.115
171 TOTAL Customer Service and lnformation Expenses (Total 162 thru 170)24,905,209 25,612.197
172 7. SALES EXPENSES
173 Ooeration
174 (91 1) Supervision
175 (912) Demonstratino and Sellinq ExDenses
176 (913) Advertisinq Expenses
177 (916) Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries 33,574,zffi 32.024.875
182 (921) Ofiice Supplies and Expenses 4,377,759 4,229,702
183 (Less) (922) Administrative Expenses Transferred-Credit 125.486 118.479
1U (923) Outside Services Employed 7,629,675 9,631,716
185 (924) Property lnsurance 1,275.339 't.3't3.970
186 (925) lniuries and Damaqes 3,364,064 3,473,339
187 (926) Employee Pensions and Beneftts 1,337,953 't,594,960
188 (927) Franchise Requirements 4,607 3,927
189 (928) Regulatory Commission Expenses 6,138,496
190 (929) (Less) Duplicate Charqes-Cr
191 (930.1 ) General Advertising Expenses 2.207
192 (930.2) Miscellaneous General Expenses 3,880,076 3,633,056
193 (931) Rents 1.07't.360 1,017,563
194 TOTAL Operation (Enter Total of lines 181 thru 193)62,558,160 62,945,332
195 Maintenance
196 (935) Maintenance of General Plant 't't,428,338 10,677,749
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196)73,986,498 73,623,081
198 TOTAL Elec Op and Maint Expns (Total 80,112,'131,156,164,171 ,178,197\576,763,105 617,386,545
FERC FORM NO.1 (ED. 12-93)Page 323
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2O16lQ4
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 flrm 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 Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand
Monthly
(0
Monthly
(e)
1 ATCO Power Canada Ltd.SF WSPP
2 Avangrid Renewables, LLC SF WSPP
3 BP Energy Company SF WSPP
4 Black Hills Power. lnc.SF WSPP
5 Bonneville Power Administration LF Wt,lP#3 Agr
6 Bonneville Power Admin istration SF WSPP
7 Bonneville Porer Administration LF N\A/PP
8 Bonneville Pou/er Administration LF Tarifi 8
9 Bonnevilb Poryer Administration os BPA OATT
10 Bonneville Porer Admin istration LF BPA OATT
11 Brookfield Energy Marketing LP SF WSPP
12 California lndependent System Operator SF Tariff 9
13 Calpine Energy Services LP SF WSPP
14 Cargill Power Markets SF WSPP
Total
FERC FORM NO. 1 (ED. 12-90)Page 326
Name of Respondent
Avista Corporation
s:
(1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
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.Megawatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)o
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (l+k+l)
of Settlement ($)
(m)
10c 3,40(3,400 1
1M,78i 3,186,81S 3,186,819 2
4,60C 77,12(77,124 3
1,40C 36,50(36,500 4
398,391 15,636,54t 15,636,548 5
160,35S 2,667,96t 2,667,964 6
107 2,79i 2,793 7
17,529 u7,381 u7,387 I
48,630 48,630 9
2,97(147.12(117,028 10
4l 1,05t 1,058 11
50{13,06!13,069 12
21,06{562,202 562,202 13
14J&339,43t 339,438 14
4,823,114 528,878 525,942 't3,815,788 114,871,821 1 8,539, 1 19 147,226,72e
FERC FORM NO. 1 (ED. 12-90)Page 327
Respondent s:
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
03t3'U2017
Year/Period of Report
End of 20161Q4
PURCHASED POWER (Account
(lncluding power exchanges)555)
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 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 Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand
Monthly
(e)(f)
1 City of Spokane LU PURPA
2 City of Spokane IU PURPA
3 Chelan County PUD IU Rocky Reach
4 Chelan County PUD SF WSPP
5 Chelan County PUD LF NWPP
b Chelan County PUD IU Chelan Sys
7 Citigroup Energy SF WSPP
I Clark County PUD No. 1 SF WSPP
9 Clatskanie PUD SF WSPP
10 Community Solar LU PURPA
1',l Douglas County PUD No. 1 LU Wells
12 Douglas County PUD No. 1 LU Wells Settlement
13 Douglas County PUD No. 1 IF Wells
14 Douglas County PUD No. 1 SF WSPP
Total
FERC FORM NO.1 (ED. 12-90)Page 326.1
S:
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2016/Q4
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, tarlffs 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 suppliels 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)
Megawatt Hours
Delivered
(i)
Demand Charges
($)o
Energy Charges
($)
(k)
Other Charges
($)
(l)
Total (+k+D
of Settlement ($)
(m)
57,674 3,001,55t 3,001,558 ,|
122,48!5,663,55t 5,663,558 2
-24,41e 3
38,00c u0,21t uo,21e 4
I 4i 42 5
4il,42e 12,043,582 't2,043,582 6
9,00c 197,28C 197,28C 7
5,06:98,124 98,123 I
2,30€24,281 24,281 9
27,962 27,962 10
129,13!1,771,508 1,771,508 11
31,45i '1,081,25!1 ,081,255 12
13
31,291 816,09:816,093 14
4,823,114 528,878 525,942 13,815,788 114,871,821 1 8,539, 1 19 147,226,72e
FERC FORM NO.1 (ED.12-90)Page 327.1
Avista Corporation Original
Resubmission
(1)
(2)o3t31t2017
Date of(Mo, Da
Report
,Y0
Year/Period of Report
End of 2O16lQ4
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, cpacity, 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 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 flrm 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 Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MVV)
(d)
Aclual Demand (MW)
AVerage
Monthly NCP Demanr
(e)
AVerage
Monthly CP Demand
(0
1 Douglas County PUD No. 1 EX 305
2 EDF Trading No America SF WSPP
3 Energy Keepers, lnc.SF WSPP
4 Eugene Water & Electric Board SF WSPP
5 Exelon Generation Company, LLC SF WSPP
6 Ford Hydro Limited Partnership LU PURPA
7 Grant County PUD No. 2 LU Priest Rapids
I Grant County PUD No. 2 LF NWPP
I Grant County PUD No. 2 EX FERC #1M
10 Gridforce Energy Management, LLC LF N\APP
11 Hydro Technology Systems IU PURPA
12 ldaho County Power & Light LU PURPA
''t 3 ldaho Power Company SF WSPP
14 lnland Porer & Light Company RQ 208
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.2
Name of Respondent
Avista Corporation
s:
(1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t3'U20'17
Year/Period of Report
End of 20161Q4
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 (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. 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)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
o
Energy Uharges
($)
(k)
other charges
($)
(t)
Total (J+k+l)
of Settlement ($)
(m)
77,49C 77,490 610,50(. 293 610,793 1
67,50C 1,791,50(1.791.50C 2
8,1 07 68,92t 68,928 3
7,432 141,30t 141,308 4
21.8r'9,357,82!357,825 5
3,621 228,33i 228,333 6
u3,75i 6,800,63t 6,800,638 7
(17(174 8
1 9
I 2t 2A 10
9,87:457,034 457,034 11
3,26t 128,25i 128,253 12
96,75(1,500,49f 1,500,495 13
10:7,67C 7,670 14
4,823,114 528,87e 525,942 13,815,788 114,871,821 18,539,11!147,226,72e
FERC FORM NO.1 (ED. 12-90)Page 327.2
Avista Corporation
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2016/Q4
runt 555)es)
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 projecls 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 flve years or longer and "flrm" 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{erm 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 flrm 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 Afiiliations)
(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)
Average
Monthly CP Demand
(0
1 Jim \Mrite LU PURPA
2 Kootenai Electric Cooperalive LF Tariff 8
3 Macquarie Energy LLC SF WSPP
4 Mizuho Securities USA, lnc.SF ISDA
5 Morgan Stanley Capital Group SF WSPP
6 SG Americas Securitbs, LLC SF ISDA
7 NextEra Energy Power Marketing LLC SF WSPP
I NorthWestern Energy LLC SF WSPP
I NorthWestem Energy LLC LF N\A/PP
10 Okanogan County PUD No. 1 SF WSPP
11 PacifiCorp SF WSPP
12 PacifiCorp LF N\A/PP
13 Palouse Wind LLC LU PPA
14 Pend Oreille County PUD No. 1 SF Pend O'
Total
FERC FORM NO.1 (ED. 12-90)Page 326.3
Avista Corporation
(1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
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 (fl. 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 gpes 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)
Megawatt Hours
Delivered
(i)
Demand Charges
($)
0)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
1,23i 132,50:132,503 1
2,054 39,36i 39,36i 2
56,953 1,309,851 1.309.851 3
11,143,081 1 1 ,143,081 4
53,60i 1,080,14i 1,080J42 5
3,828,613 3,828,613 6
14,05C 208,99t 208,998 7
10,933 205,75t 205,756 I
(22t 228 I
11,64t 167,49t 167,496 10
67,25(1,249,53t 1,249,s38 11
1i 432 432 12
u9.771 20,524,991 20,524,997 13
71,021 't,202,88C 1,202,880 14
4,823,114 528,878 525,942 13,815,788 114,871,821 't8,539, 1 1 9 147,226,72t
FERC FORM NO.1 (ED. 12-90)Page 327.3
Name of Respondent
Avisla Corporation
Reoort ls:
finn originat
l-lA Resubmission
This
(1)
(2)
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 20161Q4
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 transaclion 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 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{erm" 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 Affiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (M\[f
(d)
Actual Demand (MMr')
AVerage
Monthly NCP Deman
(e)
AVerage
Monthly CP Demand
(f)
1 Pend Oreille County PUD No. 1 IF Pend O'
2 Phillips Ranch LU PURPA
3 Portland General Electric Company EX 3(M
4 Portland General Electric Company EX 178
5 Portland General Electric Company SF WSPP
b Portland General Eleclric Company LF N!A/PP
7 Powerex Corp SF WSPP
8 Public Service Company of Colorado SF WSPP
9 Puget Sound Energy SF WSPP
10 Puget Sound Energy LF NWPP
11 Rathdrum Power LLC LF Lancaster
12 Sacramento Municipal Utility District SF WSPP
't3 Seattle City Light SF WSPP
14 Seattle Cig Light LF NWPP
Total
FERC FORM NO. 1 (ED. 12-90)Page 326.4
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03l3'U2017
Year/Period of Report
End of 2O16lQ4
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. Repo( in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (J), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. 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)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
o
E.nergy Charges
($)
(k)
otner unarges
($)
(t)
I otal 0+K+lof Settlement
(m)
)($)
14.31(.269,47i 269,473 1
4i 2,01t 2,0't6 2
441,852 438,82s 3
9,536 9,535 5't,160 51,160 4
14,94 241,OOt 241,004 5
1t 40t 408 6
138,80t 3,926,24i 3,926,243 7
2,00(62,00(62,00c 8
84,66(1,706,40{1,706,40f 9
1t 441 444 10
1,307,452 25,358,63i 25,358,63i 11
72!25,',17!25,174 12
32,771 572,30a 572,30!13
C 20t 20e 14
4,823,114 528,87t 525,942 13,815,788 114,871,821 18,539,1 1 !147,226,72t
FERC FORM NO. 1 (ED. 12-90)Page 327'4
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
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 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 longterm 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 expecl that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electrici$. 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 Afiiliations)
(a)
Statistical
Classifi-
cation
(b)
FERC Rate
Schedule or
Tariff Number
(c)
Average
Monthly Billing
Demand (MW)
(d)
Actual Demand (MW
Average
Monthly NCP Demanr
(e)
Average
Monthly CP Demand
(0
1 Sheep Creek Hydro LU PURPA
2 Shell Energy SF WSPP
3 Snohomish County PUD No. 1 SF WSPP
4 Southern California Edison Company SF WSPP
5 Sovereign Power LF Sovereign
6 Spokane County LU PURPA
7 Slimson Lumber IU PURPA
8 Tacoma Power SF WSPP
I Tacoma Porrver LF NWPP
10 Tacoma Power SF WSPP
11 Talen Energy Marketing SF WSPP
12 The Energy Authority SF WSPP
13 TransAha Energy Marketing SF WSPP
14 TransAlta Energy Marketing SF WSPP
Total
FERC FORM NO. 1 (ED.12-90)Page 326.5
Avista Corporation
(1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Yr)
03R1t2017
Year/Penod of Report
End of 2O16lQ4
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 Dellvered 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)
Megawatt Hours
Delivered(i)
Demancl Charges
($)
(i)
Energy Charges
($)
(k)
Other Charges
($)
(t)
Total (i+k+l)
of Settlement ($)
(m)
10,50:330,29'330,291 1
161,17i 3,442,261 3,442,262 2
38,60(549,86(549.86C 3
4
5,53S 108,68:108,685 5
92t 55,36i 55,367 6
33,19S 1,856,221 1,856,224 7
26,742 513,34t 513,348 I
I 8(8C I
48 48 10
18,471 380,74t 380,746 11
22,884 392,06:392,063 12
76,98:2,037,93(2,037,930 13
65C 650 14
4,823,114 528,878 525,942 13,815,788 114.871,821 't8,539,119 147,226,72t
FERC FORM NO. 1 (ED. 12-90)Page 327.5
Name of
Avista Corporation (1)
(2)
Original
Resubmission
Dale of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2016/Q4
'l . 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, €pacity, 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 flrm 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 availabili$ 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 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 Demanr
(e)
Average
Monthly CP Demand
(0
1 Turlock lrrigation District SF WSPP
2 Vitol lnc.SF WSPP
3 Wells Fargo Securities, LLC SF ISDA
4 lntraCompany Generation Services OS OATT
5 Other - Inadvertent lnterchange EX
6
7
8
9
10
11
12
13
14
Total
FERC FORM NO. 1 (ED.12-90)Page 326.6
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
0313112017
Year/Period of Report
End of 2O16lQ4
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.Megawatt Hours
Received
(h)
MegaWatt Hours
Delivered
(i)
Demand Charges
($)
o
Energy L;narges
($)
(k)
uther charges
($)
(D
Iotal (J+K+l)
of Settlement ($)
(m)
40(14,80(14,80C 1
1,60(39,20(39,20C 2
1,674,6U 1,674,604 3
1,822,833 1,822,833 4
92 5
6
7
I
9
10
11
12
13
14
4,823,114 528,878 525,942 13,815,788 114,871,821 18,539, 1 19 147,226,72e
FERC FORM NO.1 (ED.12-90)Page 327.6
Name of Respondent
Avista Comoration
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
326 Line No.: 5 Column: a
BPA Contract Termr-na tes June 30, 2019
Schedule Paqe: 326 Line No.:7 Column: a
Reserve Shari under the Northwest Power Pool Reserve Sharin reement
Schedule 326 Line No.: 8 Column: a
BPA Contract Terminates S ember 30 on10
326 Line No.:9 Column: a
Anc Serv &S lemental-
BPA Contract Terminates Janua 07,2036
umn:a
-
,Reserve Sharin under the NorthWest Power Pool- Reserve Sharin reement
Schedule 326.2 Line No.: 1 Column: I
326 Line No.: 10 Column: I
Non Moneta
326.2 Line No.:8 Column: a
326.2 Line No.: 9 Column: I
Reserve Shari under the NorthWest Power Pool- Reserve Sharin reement
Non Moneta
Reserve Shari-under the NorthWest Power Poo Reserve S reement
Service to Deer Lake from Inland Power and L ght. No demand charges associated with the
Schedule Page: 32 mn: aKootenai Contract Terminates March 31 2079
Financiaf SWAP
326.2 Line No.: 10 Column: a
326.2 Line No.: 14 Column: a
326.3 Line No.:4 Column: a
326.3 Line No.: 6 Column: a
nanc aI SWAP - Formerl known as Newe USA, LLC
Reserve Shar under the NorthWest Power Pool- Reserve Shari reement
326.3 Line No.: 12 Column: a
Reserve Shari under the NorthV'iest Power Poof Reserve Sharin reement
Non Moneta
Reserve Shari under the NorthWest Power Poo Reserve S ar
"Schedule
326.4 Line No.: 10 Column: a
Reserve Shar under the NorthWest Power Pool Reserve Shara reement.
reement
326.4 Line No.: 4 Column: I
326.4 Line No.: 6 Column: a
326.4 Line No.: 14 Column: a
Reserve Shari under the NorthWest Power Pool Reserve Sharln reement.
Schedule 326.5 Line No.: 5 Column: aSovereiContract Terminates ember 30 2019
326.5 Line No.:9 Column: a
Reserve Shari under t
Ancillary Serv ces
NorthWest Power Po Reserve S ement
FERC FORM NO.1 (ED. 12-871 Page 450.'l
This Page Intentionally Left Blank
Name of s:
Avista Corporation (1)
(2)
Original
Resubmission
Dale of(Mo, Da
Report
,YO
03t3112017
Year/Period of Report
End of 20161Q4
I KAN!as 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.
Line
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 PacifiCorp PacifiCorp PacifiCorp OLF
2 Seattle City Light Seattle City Light Grant County PUD OLF
3 Tacoma Power Tacoma Power Grant County PUD OLF
4 Grant County Public Utility District Grant County PUD Grant County PUD OLF
5 Spokane Tribe Bonneville Power Administration Spokane Tribe of lndians LFP
6 East Greenacres Bonneville Power Administration East Greenacres LFP
7 Consolidated lrrigation District Bonneville Power Administration Consolidated I rrigation Districl LFP
8 Bonneville Power Administration Bonneville Power Administration Bonneville Power Admin istration FNO
9 City of Spokane City of Spokane Avista Corporation OLF
10 Stimson Plummer Avista Corporation OLF
11 Hydro Tech lndustries Meyers Falls Avista Corporation OLF
12 First \Mnd Energy Marketing Palouse Wind Avista Corporalion OLF
13 Deep Creek Hydro Deep Creek Avista Corporation OLF
14 Shell Energy North America (US) LP Bonneville Power Administration ldaho Power Company SFP
15 Shell Energy North America (US) LP Grant County PUD ldaho Power Company SFP
16 Morgan Stanley Capital Group Avista Corporation Bonneville Power Administration SFP
17 Morgan Stanley Capital Group Avista Corporation ldaho Power Company SFP
18 Morgan Stanley Capital Group Avista Corporation Northwestern Montana SFP
19 Morgan Stanley Capital Group Bonneville Power Administration ldaho Power Company SFP
20 Morgan Stanley Capital Group Bonneville Power Administration Northwestern Montana SFP
21 Morgan Stanley Capital Group Northwestern Montana Avista Corporation SFP
22 Morgan Stanley Capital Group Northwestern Montana Bonneville Power Admin istration SFP
23 Morgan Stanley Capital Group Northwestern Montana Chelan County PUD SFP
24 Morgan Stanley Capital Group Northwestem Montana ldaho Power Company SFP
25 Morgan Stanley Capital Group Northwestem Montana Grant County PUD SFP
26 Morgan Stanley Capital Group Northwestem Montana Pacificorp SFP
27 Morgan Stanley Capital Group Pacificorp ldaho Power Company SFP
28 Morgan Stanley Capital Group Puget Sound Energy ldaho Power Company SFP
29 Morgan Stanley Capital Group Grant County PUD ldaho Power Company SFP
30 Morgan Stanley Capital Group Grant Coung PUD Northwestern Montana SFP
31 Morgan Stanley Capital Group ldaho Power Company Bonneville Power Administration SFP
32 Morgan Stanley Capital Group ldaho Power Company Northwestern Montana SFP
33 Morgan Stanley Capital Group Chelan County PUD ldaho Power Company SFP
u Morgan Stanley Capital Group Chelan County PUD Northwestern Montana SFP
TOTAL
FERC FORM NO.1 (ED. 12-90)Page 328
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
as
r 45OXUOnUnUeO)
5. ln 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
(MVV)
(h)
TRANSFER OF ENERGY Line
No.Megawa[ Hours
Received(i)
Megawan nours
Delivered(i)
FERC No. 182 Dry Gulch Dry Gulch 54.38!54,3&1
FERC Trf No. 8 Chelan-Stratford Stratford 240,085 240,084 2
FERC Trf No. 8 Chelan-Stratford Sratford 240,06:240,06:3
FERC Trf No. 8 Stratford Coulee CityMilson 81,519 81,51S 4
FERC Trf No. I AVA.BPAT AVA.SYS a 3,1 81 3,181 5
FERC Trf No. 8 AVA.BPAT AVA.SYS a 2,833 2,83?6
FERC Trf No. 8 AVA.BPAT AVA.SYS 2 6,001 6,001 7
FERC Trf No. 8 AVA.BPAT AVA.SYS 1,853,977 1,853,97i 8
FERC No. 155 I
FERC Trf No. 8 10
FERC Trf No. 8 11
FERC Trf No. 8 12
FERC Trf No. 8 13
FERC Trf No. 8 5,861 5,86',14
FERC Trf No. 8 13,397 13,39;15
FERC Trf No. 8 7A 7('16
EERC Trf No. I 719 711 17
FERC Trf No. 8 25 2a 18
FERC Trf No. I 30,917 30,91i 19
FERC Trf No. 8 625 62!20
FERC Trf No. I 16 1(21
FERC Trf No. 8 75,998 75,99t 22
FERC Trf No. I 3,152 3,151 23
FERC Trf No. 8 134,167 1U,16i 24
FERC Trf No. 8 352 35i 25
FERC Trf No. 8 1,608 1,60t 26
FERC Trf No. I 43 41 27
FERC Trf No. 8 151 151 28
FERC Trf No. 8 4,321 4,321 29
FERC Trf No. I 11S 11S 30
FERC Trf No. 8 11C 11(31
FERC Trf No. 8 76e 76€32
FERC Trf No. 8 15,65r 15,65a 33
FERC Trf No. 8 7,492 7,492 v
12 3,149,076 3,149,07(
FERC FORM NO.1 (ED.12-90)Page 329
Name
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
to as
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). If no monetary settlement was made, enter zero (1101 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 ELECTRICIW FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(t)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Lrne
No.
217,930 217,930 1
146,370 59,26 205,616 2
216,000 59,26 27s,246 3
27,684 27,6U 4
28,800 5,398 34,198 5
10,80(4,954 15,754 6
32,UC 38,379 7
6,232,63:8,021,475 8
27,973 27,973 9
9,480 9,480 't0
6,120 6,120 11
200,000 200,000 12
603 603 13
25,123 25J23 14
59,424 59,424 15
39€398 16
3,58C 3,580 17
12C 120 18
132,054 132,0U 't9
2.742 2,742 20
77 77 21
322,464 322,464 22
14,621 14,621 23
604,335 604,335 24
1,681 1,681 25
5,582 5,582 26
206 206 27
75C 750 28
19,131 1 9,1 31 29
561 561 30
436 436 3't
3,646 3,646 32
70,828 70,828 33
37,428 37,428 u
9,957,008 0 5,378,145 15,335,'153
FERC FORM NO.1 (ED. 12-90)Page 330
This Page Intentionally Left Blank
Name
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 20161Q4
It(AN!
AS
ccount 456.1 )
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities,
qualiffing 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.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affil iation)
(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 Morgan Stanley Capital Group Portland General Electric ldaho Power Company SFP
2 Morgan Stanley Capital Group Avista Corporation ldaho Power Company SFP
3 Puget Sound Energy Northweslern Montana Bonneville Power Administration SFP
4 Bonneville Power Admin istration Bonneville Power Administration ldaho Power Company SFP
5 ldaho Power Company Avista Corporation Bonneville Power Administration SFP
6 ldaho Power Company Bonneville Power Administration ldaho Power Company SFP
7 ldaho Power Company Northwestern Montana ldaho Power Company SFP
8 ldaho Power Company Pacificorp ldaho Power Company SFP
9 ldaho Power Company Chelan County PUD ldaho Power Company SFP
10 ldaho Power Company Portland General Electric ldaho Power Company SFP
't1 Kootenai Electric Kootenai Electric ldaho Power Company LFP
12 Nevada Power Company Bonneville Power Administration ldaho Power Company SFP
13 Shell Energy North America (US) LP Bonneville Power Administration ldaho Power Company NF
14 Shell Energy North America (US) LP Grant County PUD ldaho Power Company NF
15 Morgan Stanley Capital Group Bonneville Power Administration ldaho Power Company NF
16 Morgan Stanley Capital Group Bonneville Power Administration Northwestern Montana NF
17 Morgan Stanley Capital Group Northwestem Montana Bonneville Power Administration NF
18 Morgan Stanley Capital Group Northwestem Montana Chelan County PUD NF
19 Morgan Stanley Capital Group Northwestem Montana ldaho Power Company NF
20 Morgan Stanley Capital Group Northwestern Montana Grant County PUD NF
2'l Morgan Stanley Capital Group Northwestern Montana Pacific Corp NF
22 Morgan Stanley Capital Group Pacific Corp ldaho Power Company NF
23 Morgan Stanley Capital Group Puget Sound Energy ldaho Power Company NF
24 Morgan Stanley Capital Group Grant County PUD ldaho Power Company NF
25 Morgan Stanley Capilal Group Grant County PUD Northwestern Montana NF
26 Morgan Stanley Capital Group ldaho Power Company Bonneville Power Administration NF
27 Morgan Stanley Capital Group Chelan County PUD ldaho Power Company NF
28 Morgan Stanley Capital Group Chelan County PUD Northwestern Montana NF
29 Puget Sound Energy Northwestern Montana Bonneville Power Administration NF
30 Powerex Bonneville Power Administration ldaho Power Company NF
31 Transalta Energy Marketing Bonneville Power Adm inistration ldaho Power Company NF
32 Pacific Corp Pacific Corp ldaho Power Company NF
33 Pacific Corp ldaho Power Company Bonneville Power Administration NF
v Bonneville Power Administration Bonneville Power Administration ldaho Power Company NF
TOTAL
FERC FORM NO. 1 (ED. 12-90)Page 328.1
Name of Respondent
Avista Corporation
S:
(1)
(2)
Original
Resubmission
Date of Reoort(Mo, Da, Yi)
03t3112017
Year/Period of Report
End of 2O16lQ4
as
r 4coxuonunueo)
5. ln 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)
(f)
Point of Delivery
(Substation or Other
Designation)
(s)
Billing
Demand
(MW
(h)
TRANSFER OF ENERGY Line
No.Megawa[ Hours
Received
(D
Megawafl Hours
Delivered(i)
FERC Trf No. I 12A 12(1
FERC Trf No. 8 44 4 2
FERC Trf No. 8 44,419 44,411 3
FERC Trf No. 8 26,274 26,27(4
FERC Trf No. 8 2j25 2,'t2!5
FERC Trf No. 8 97,018 97,01t 6
FERC Trf No. 8 2,632 2,631 7
FERC Trf No. 8 13,357 13,35i 8
FERC Trf No. 8 9,889 9,88S I
FERC Trf No. I 45(45(10
FERC Trf No. 8 ?10,82:10,82:11
FERC Trf No. I 2,50C 2,50(12
FERC Trf No. 8 4,47i 4,471 13
FERC Trf No. 8 9,70C 9,70(14
FERC Trf No. 8 3.732 3,732 15
FERC Trf No. 8 6€6t 16
FERC Trf No. 8 4,272 4,272 17
FERC Trf No. I 1,072 1,072 18
FERC Trf No. 8 25,923 25,924 19
FERC Trf No. 8 ozt 622 20
FERC Trf No. 8 7a 1E 21
FERC Trf No. 8 4C 4C 22
FERC Trf No. 8 853 85:23
FERC Trf No. 8 244 244 24
FERC Trf No. 8 4C 4C 25
FERC Trf No. 8 187 187 26
FERC Trf No. 8 1,041,1,041 27
FERC Trf No. 8 196 't9(28
FERC Trf No. I 214 21(29
FERC Trf No. 8 3,952 3,95i 30
FERC Trf No. 8 35 at 31
FERC Trf No. 8 4,il7 4.il1 32
FERC Trf No. I 1 ,185 't,'18r 33
FERC Trf No. 8 94,914 94,911 v
12 3,149,076 3,149,071
FERC FORM NO. 1 (ED.12-90)Page 329.1
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03R1t2017
Year/Period of Report
End of 20161Q4
to as
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 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)
(s)
(m)
Total.Revenues ($)
(k+l+m)
(n)
Ltne
No.
53C 530 1
147 147 2
138,45C 138,450 3
71,994 71,994 4
7,85C 7,850 5
359.718 359,718 6
9,878 9,878 7
62,303 62,303 8
36,145 36,145 I
2,'t54 2.154 10
72.00c 90,244 11
18,46C 18,460 12
24,74C 24,740 13
61,35C 61.350 14
24,421 24,425 15
454 454 16
27,92e 27,926 17
6,733 6,733 18
171,91e 171,916 19
3,78C 3.780 20
461 461 21
307 307 22
5,64€5,646 23
1,55€1,556 24
26a 265 25
1,23e 1,236 26
6,663 6.663 27
1,365 1,365 28
6,059 6,059 29
22,82e 22,826 30
427 427 31
34,55C 34,550 32
12,493 12,493 33
516,865 516,865 34
9,957,008 0 5,378,145 't5,33s,'ts3
FERC FORM NO. 1 (ED.12-90)Page 330.1
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t3112017
Year/Penod of Report
End of 2O16lQ4
I KANI as ccounl 4co.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 pald for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments, Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for
each adjustment. See General lnstruction for definitions of codes.
Line
No.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Afiiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 ldaho Power Company Bon neville Power Administration ldaho Power Company NF
2 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS
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
33v
TOTAL
FERC FORM NO. 1 (ED. 12-90)Page 328.2
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Y0
03R1t2017
Year/Period of Report
End of 2O16lQ4
AS
t 456)(Uonttnued)
5. ln 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 contracl. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC 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.Megawatt Hours
Received
(D
Megawatt Hours
Delivered(i)
FERC Trf No. 8 4,337 4,331 1
FERC Trf No. 8 2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
't8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33v
12 3,149,076 3,149,07(
FERC FORM NO.1 (ED. t2-90)Page 325.2
Name of Respondent
Avisla Corporation
S:
(1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
es
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
chargeshownonbillsrenderedtotheentityListedincolumn(a). lfnomonetarysettlementwasmade,enterzero(11011)incolumn
(n). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service
rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
I 1. 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)
Lrne
No.
27,592 27,592 1
3,192,0m 3,192,000 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
3'l
32
33
34
9,957,008 0 5,378,145 15,335,153
FERC FORM NO. 1 (ED. 12-90)Page 330.2
Name of Respondent
Avista Comoration
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
20't6tQ4
FOOTNOTE DATA
,Schedule Page: 328 ,Use of facilities.
Schedule Pase: 328 Line No.: 3 Column: m
Use of faciliti-es.
Schedule Paqe: 328 Line No.: 5 Column: m
Ancilf servt-ces.
Anc serv ces .
328 Line No.:7 Column: m
328 Line No.: 6 Column: m
An 11 servlces.cl-328 Line No.: 8 Column: m
Ancl11 SEI\/-1CES.
Use of facilities.328 Line No.: 9 Column: m
328 Line No.: 10 Column: m
Use of fac I t328 Line No.: 11 Column: m
Use of fac l_ties.1l_
Deferral fee for l-o term f r-rm se328 Line No.: 13 Column: m
Use of facilities.
reement.
Schedule Paoe: 328.1 Line No.: 11 Column: m
Ancifla servr,ces .
328.2 Line No; 2 Column: m
Parallel Capacity Support Agreement.
FERC FORM NO.1 (ED. 12.871 Paqe 450.1
Name of Respondent
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03131t2017
Year/Period of Report
End of 2016/Q4
TRANSMISSION OF ELECTRICIry 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 Classiflcation 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.
Line
No.Name of Company or Public
Authority (Footnote Affiliations)
(a)
Statistical
Classification(b)
TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERI
Maoawa[-_hbursRecervecl
(c)
rvlagawall-noursDelivered
(d)
uemana
Charoes($r
(e)
Enetov
Charo-ds($r
(f)
Total cost of
Translgission
(h)
1 Bonneville Power Admin LFP 1,498,566 1,498,566
2 Bonneville Power Admin LFP 10,189,227 2,059,743 12,248,970
3 Bonneville Power Admin LFP 943,401 943,401
4 Bonneville Power Admin OS 24,360 24,360
5 Bonneville Power Admin FNS 1,067,305 193,296 1,260,601
6 Bonneville Power Admin NF 585 585 3,014 3,014
7 Kootenai Eleclric Coop LFP 45,222 45,222
I Northern Lights LFP 134,277 134,277
9 NorthWestem Energy SFP 198,521 19,986 218,507
't0 NorthWestem Eneqy NF 45,352 45,352 196,374 1 96,374
11 Portland General Elec LFP 628,000 14,989 642,989
12 Portland Cieneral Elec SFP 199 3 202
'13 Portland General Elec NF 1,253 1,253 1,523 1,523
14 Puget Sound Energy NF 100 100 263 19 282
15 Seatte City Light NF 12,394 12,354 14,903 14,903
16 Shell Eneqy North Amer NF 338 338 375 375
TOTAL 71,12(71J20 14,7U,718 2y,245 2,312,396 17 ,251,359
FERC FORM NO. 1/3-Q (REV.02-04)Page 332
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn Orisinat(2) J-1A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
TRANSMISSION OF ELECTRICIry BY OTHERS (Account 565)
(lncluding transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electrlcity 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. Repofi 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.
Line
No.Name of Company or Public
Authority (Footnote Affiliations)
(a)
Statistical
Classification(b)
TRANSFER OF ENERG\EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERI
Maoawatt-
h-oursReceived
(c)
Maoawall-h-oursDelivered
(d)
EnerovCharoEs($r
(0
UINETCharoes($r
(o)
Total Cost of
rranslgission
1 Snohomish County PUD NF 8,949 8,949 11 ,891 11,891
2 Talen Energy Marketing NF 2,149 2,149 5,902 5,902
3
4
5
o
7
8
I
10
11
12
13
14
'15
16
TOTAL 71,12(71J20 14/M,718 2v,245 2,312,396 17 ,251,359
FERC FORM NO. 1r3-Q (REV. 02-04)Page 332.1
Name of Respondent
Avista Corporation
This Report is:
(1) X An Originale\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016/Q4
FOOTNOTE DATA
332 Line No.:2 Column:Ancill Servi-ces
Use o Fac t ES
332 Line No;4 Column:
332 Line No.:5 Column:
Anciff Services
Ancil1 Services
Anci Serv ces
Anc 11 Servl-ces
Anc 11ary Servicesa
332 Line No.:9 Column:
332 Line No.: 11 Column:
332 Line No.: 12 Column:
332 Line No.: 14 Column:
FERC FORM NO.1 1 450.1
This Page Intentionally Left Blank
Name of Responclent
Avista Corporation
This &Dort ls:
(1) lxl An Original
(2) f] A Resubmission
uate ot HeDon(Mo, Da, Yi)
03t31t2017
YeailPenoo or Kepon
End of 2O16lQ4
MISCELI-ANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line
No.
Amount
(b)
1 lndustry Association Dues 585,379
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist lnfo to Stkhldrs...expn servicing outstanding Securities 405,940
5 Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 692,873
6 Community Relations 28,502
7 Director Fees and expenses 711,328
8 Educational & lnformational expenses 44,167
9 Rating agency fees 181,881
10 Aircraft operations and fees 174,836
11 Other Misc general expenses 1 ,055,1 70
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
v
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 3,880,076
FERC FORM NO. 1 (ED. 12-94)Page 335
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(21 A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016/Q4
FOOTNOTE DATA
'Schedule Line No.: 13 Column: a
Vendor Name Electric Amt
SUM
{DVENTURES IN ADVERTI SING 6,834.06
{LLURESOFT LLC 6,573.61
A.ndre4 MichaelG 18,307.96
BAKER BOTTS LLP 30,000.00
BANK OF NEW YORK MELLON 6,275.26
]EATI INTERNATIONAL INC 35,816.6s
]ITIBANKNA 60,389.81
COMMON GROUND ALLIANCE .00
COMPLIANCE WAVE LLC 10,931.93
CORP CREDIT CARD 150,979.12
Durkin, Marian McMahon 7,212.47
E SOURCE COMPANIES LLC 5,621.02
ENCOMPASS NW SERVICES LLC 6,283.98
ENTERPRISE RENT A CAR 7,453.33
Faulkenberry, Michael J 00
GARTNER INC 29,410.10
GUCKENHEIMER SERVICES LLC 8,5s8.39
TNLAND NORTHWEST PARTNERS s,886. r 6
Kimmell, PaulJ 6,156.74
KLUNDT HOSMER DESIGN 35,295.21
MDC RESEARCH 6,241.03
MEDIA WORKS RESOURCE GROUP 19,703.42
N4ERIDIAN COMPEN SATION PARTNERS
LLC
33,848.46
MITCHELL HAMLINE SCHOOL OF LAW 4,775.99
NATIONAL COLOR GRAPHICS INC 3,767.72
NORTHWEST GAS ASSOCIATION .00
PCAOB 11,483.49
ROCKY MOUNTAIN INSTITUTE 20,000.00
SCOTT H MAW 23,480.85
]TRATEGIC RESEARCH ASSOCIATES 6,604.87
faylor, Brian A .00
Ihackston, Jason R 14,347.73
IHE COEUR D ALENE RESORT 12,564.43
Ihies, Mark T 10,039.97
LINION BANK OF CALIFORNIA 25,820.01
LINIVERSITY OF ILLINOIS 25,000.00
VOLT MANAGEMENT CORP 29,911.68
WILMINGTON TRUST COMPANY 3,566.30
Wood, Pahicia Prouty 3,731.64
Total 692.873.39
FERC FORM NO.1 (ED. 12.871 Page 450.1
Name of Respondent
Avista Corporation
This
(1)
(2\
Reoort ls:
5]Rn Originat
nA Resubmission
Date of Reoort(Mo, Da, Yi)
o3t31t2017
Year/Peraod of Report
End of 2O16lQ4
DEPRECTATTON AND AMORTTZATTON OF ELECTRTC 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. ldentify 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 Classiflcations 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 related,
A. Summary of Depreciation and Amortization Charges
Line
No.Functional Classification
(a)
DeoreciationExoense(Account 403)(b)
ueprecratron
Expense for Asset
Retirement Costs
(Account 403.'l)(c)
Amonrzatron ot
Limited Term
Electric Plant(Account 404)(d)
Amortization ofOther Eleclric
Plant (Acc 405)
(e)
Total
(f)
1 lntangible Plant 2,7U,388 2,7U,388
2 Steam Production Plant 7,896,219 7,896,219
2 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 10,4't5,486 10,415,486
E Hydraulic Production Plant-Pumped Storage
6 Other Production Plant 9,555,302 2,450,031 12,005,333
7 Transmission Plant 11,798,387 1 1,798,387
8 Distribution Plant 44,087,002 44,087,002
o Regional Transmission and Market Operation
10 General Plant 4,047,612 4,047,612
11
12
Common Plant-Electric
TOTAL
13,969,323
101,769,331
14,871,968
17,656,356 2,450,031
28,U1,291
121,875,718
B. Basis for Amo(ization Charges
FERC FORM NO. t (REV. 12-03)Page 336
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn originat(2) ;-1A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Faclors Used in Estimating Depreciation Charges
Lrne
No.Account No.
(a)
uepreclaDre
Plant Base(ln Thousands)(b)
ESIIMAIEO
Avo. Service- Life(c)
t\eI
Salvaoe
(Perce-nt)(d)
Appfleo
Depr. rates
(Percent)(et
MOnarlly
Curvetffi"
I\Verage
Remainino
Life(o)
12 STEAM PLANT
13 Colstrip No. 3
14 311 51,805 70.0c -10.00 1.56 s1.5 22.10
15 312 77,199 60.0c -10.00 1.93 R1 21.50
16 313
17 314 27,U8 40.0c -s.00 2.79 R0.5 't9.4C
18 315 9,541 50.0c 1.73 R3 21.0C
19 316 10,129 53.0C 1.46 R2 20.9C
20 Subtotal 't76,525
21
22 Colstrip No.4
23 3't 1 52,929 70.0c -10.00 1.68 s1.5 23.9C
24 312 56,047 60.00 -10.00 2.20 R1 23.3C
25 313 ?
26 314 13,749 40.00 -5.00 2.88 R0.5 20.9C
27 315 6,673 50.00 1.88 R3 22.9C
28 316 4,930 53.00 1.62 R2 22.7C
29 Subtotal 134,331
30
31 Kettle Falls 0
32 310 148 1.45 SQ 18.0C
33 311 28,546 70.00 -10.00 1.51 s1.5 17.14
u 312 44,488 60.00 -10.00 1.93 R1 16.70
EE 314 14,06t 40.00 -s.00 2.12 R0.5 14.90
36 315 r,25e 50.00 1.56 R3 16.40
37 316 2,601 53.00 1.74 R2 16.80
38 Subtotal 101,10i
eo
40 HYDRO PLANT
41 Cabinet Gorge
42 330 8,233 100.00 2.OO R4 43.24
43 331 13,6't7 1 10.00 -20.0c 1.50 R2 5'1.50
44 332 41,767 100.00 1.13 R1 47.70
45 333 45,65.00 -10.0c 2.04 R1.5 43.90
46 334 6,38.0C -5.0c 2.97 R2.5 19.70
47 335 4,421 65.0(0.38 R1.5 49.90
48 336 1,671 55.0C 1.96 S2 19.00
49 Subtotal 122,549
50
FERC FORM NO. r (REV. 12-03)Page 337
Name of Respondent
Avista Corporation
This
(1)
(2)
Reoort
E]nn
IS:
Original
nA Resubmission
Date of Reoort(Mo, Da, Yi)
03131t2017
Year/Period of Report
End of 2O16lQ4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No.Account No.
(a)
ueprecraDle
Plant Base(ln Thousands)(b)
ESIrmaIeo
Avo. Service- Life(c)
NEI
Salvaoe(Perceht)(d)
Appleo
Deor. rates(Percent)(e)
MOnarlly
Curve
'1,1"
AVerage
Remaining
(o)
12 Noxon Rapids
13 330 30,477 100.00 1.80 R4 48.80
14 331 18,904 110.00 -20.00 1.48 R2 58.40
15 332 34,943 100.00 1.12 R1 52.60
16 333 88 65.00 -10.00 1.98 R1.5 47.54
't7 334 12,794 38.00 -5.00 2.79 R2.5 29.50
18 335 3,255 65.00 0.80 R1.5 53.60
19 336 247 55.00 1.89 S2 32.00
20 Subtotal 189,601
21
22 Post Falls
23 330 2.908 75.00 2.81 R3 25.20
24 331 3,169 110.00 -20.00 2.09 R2 45.60
25 332 26,932 100.00 1.71 R1 44.70
26 333 2,2U 65.00 -10.00 2.42 R1.5 29.60
27 334 38.00 -5.00 2.78 R2.5 18.20
28 335 464 65.00 1.15 R1.5 42.10
29 Subtotal 36,43i
30
31 Long Lake
32 330 41e 75.00 4.42 R3 11.00
33 33'l 6,12t 110.00 -20.00 1.99 R2 38.90
34 332 33,853 100.00 1.65 R1 40.00
35 333 8,738 65.00 -10.00 2.46 R1.5 33.30
36 334 3,398 38.00 -5.00 2.63 R2.5 22.50
37 335 516 65.00 1.22 R1.5 39.40
38 Subtotal 53
39
40 Little Falls
41 330 4,217 100.00 3.35 R4 24.40
42 331 2,959 1 10.00 -20.00 't.94 R2 42.30
43 332 5,065 100.00 1.72 R1 43.60
44 333 18,80€65.00 -10.00 2.40 R1.5 33.60
45 334 8,627 38.00 -5.00 2.74 R2.5 22.20
46 335 65.00 0.69 R1.5 40.60
47 Subtotal 39,914
48
49 Upper Falls
50 330 64 100.0(3.66 R4 22.2C
FERC FORM NO.1 (REV.12-03)Page 332.1
Name of Respondent
Avista Corporation
This(1)
(2)
ReDort
Enn
ls:
Original
llA Resubmission
Date of Reoorl(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2O16lQ4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Fac{ors Used in Estimating Depreciation Charges
Line
No.Account No.
(a)
ueprecraole
Plant Base(ln Thousands)(b)
trsIrmaIeo
Avo. Service- Life(c)
NEI
Salvaoe(Perce-nt)(d)
Apptleo
Depr. rates(Percent)
1e)
rvrorla[[y
Curvetl,Y"
f\verage
Remaining
(o)
12 331 982 1 10.00 -20.00 1.77 R2 41.44
13 332 7,607 100.00 1.85 R1 45.24
14 333 1,166 65.00 -10.00 2.53 R1.5 30.00
15 334 4,269 38.00 -5.00 2.81 R2.5 35.10
16 335 1U 65.00 1.05 R1.5 41.20
17 336 50€55.00 1.94 S2 26.20
18 Subtotal 14,70C
19
20 Nine Mile
21 330 11 100.0(2.48 R4 35.90
22 331 18,41C 110.0c -20.0(1.98 R2 46.50
23 332 't9,zil 100.0c 1.83 R1 45.10
24 333 40,2U 65.0C -10.0c 2.17 R1.5 40.30
25 334 18,892 38.0C -5.0c 2.80 R2.5 22.5C
26 335 3,105 65.0C 0.88 R1.5 41.2C
27 336 595 55.0C 1.93 S2 36.2C
28 Subtotal 100,551
29
30 Monroe Street
31 331 't1,979 1 10.0c -20.00 1.71 R2 56.90
32 332 10,096 100.00 1.39 R1 53.20
33 333 11,031 65.00 -10.00 1.95 R1.5 45.50u3342,273 38.00 -5.00 2.82 R2.5 23.4A
?E 335 u 65.00 1.19 R1.5 48.30
36 336 50 55.00 '1.86 S2 36.60
37 Subtotal 35,463
38
3S OTHER PRODUCTION
40 Northeast Turbine
41 u1 751 55.0(1.64 S4 8.00
42 342 3'l 55.0C -10.0c 2.93 R3 8.00
43 343 9,058 55.0C 0.81 s2.5 8.00
M u4 2,6U 45.0C 2.50 R1 7.40
45 345 1,243 20.0c -5.0c 12.49 S2 7.90
46 346 39S 35.0C 2.51 R3 7.8C
47 Subtotal 14,086
48
49 Rathdrum Turbine
50 u1 3,532 55.0C 3.12 S4 24.0C
FERC FORM NO. I (REV. t2-03)Page 337.2
Name of Respondent
Avista Coporation
This Reoort ls:(1) 5]An Originat(2) EA Resubmission
Date of Report
(Mo, Da, Yr)
03t31120'17
Year/Period of Report
End of 2016/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Faclors Used in Estimating Depreciation Charges
Lrne
No.Account No.
(a)
uepreuraI',le
Plant Base(ln Thousands)(h\
ESIIMAIEO
Avo. Service- Life(c)
NCI
Salvaoe
(Perce-nt)
rd)
Apprleo
Depr. rates(Percent)
/e)
MOnarly
Curve
'ffi"
AVerage
Remaining
(o)
12 342 1,69€55.00 -10.00 3.57 R3 23.50
13 343 5,722 55.00 2.77 s2.5 23.50
14 344 49,618 45.00 3.77 R1 21.60
15 345 2,20.00 -5.0c 5.89 S2 15.20
16 346 294 35.00 2.51 R3 7.80
17 Subtotal 63,633
18
19 Kettle Falls CT
20 342 89 55.0C -10.0c 3.66 R3 17.74
21 343 9,071 55.0C 3.24 s2.5 17.84
22 u4 4 45.0C 4.09 R,I 16.60
23 345 14 20.0c -5.0c 6.68 S2 t.4a
24 Subtotal 9,1 78
25
26 Boulder Park
27 u1 't,267 55.0C 2.54 S4 31.90
28 342 166 55.0C -10.0c 2.62 R3 30.40
29 343 57 55.0C 2.52 s2.5 30.9C
30 y4 30,877 45.0C 2.94 R1 26.90
31 345 646 20.0c -5.0c 6.03 S2 14.3C
32 346 41 35.0C 2.87 R3 26.2C
33 Subtotal 33,054v
35 Coyote Springs 2
36 u1 11,402 55.0C 2.U S4 32.8C
37 342 19,305 55.0C -10.00 2.72 R3 31.4C
38 344 135,050 45.0C 3.00 R1 27.9C
39 345 15,855 20.0c -5.00 6.14 S2 13.4C
40 346 99€35.0C 2.95 R3 27.4C
41 Subtotal 182,608
42
43 Solar Power
M 344 & 345 482 25.0C 5.30 s2.5 17.9C
45 Subtotal 482
46
47 Lancaster
48 342 92 55.0C -10.00 3.67 R3 29.4C
49 344 209 45.0C 3.70 R1 26.60
50 345 49
FERC FORM NO.1 (REV. 12-03)Page 332.3
Name of Respondent
Avista Corporation
This
(1)
(2)
ReDort ls:
5]Rn Originat
;-1A Resubmission
Date of Reoort(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2O16lQ4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No.Account No
(a)
uepreqaole
Plant Base
(ln Thousands)(b)
trsltmareo
Avo. Service- Life(c)
t\et
Salvaoe
(Perce-nt)(d)
Apprleo
Depr. rates
(Percent)(e)
MOrlarlly
Curve,If,"
AVerage
Remaining
(o)
12 Subtotal 35C
13
14 TRANSMISSION PLANT
15 350 21,29C 75.0C 1.30 R4 56.80
16 352 24,161 60.0c -5.0c 1.65 S2 48.00
17 353 253,211 45.0C -10.0c 2.33 R2.5 33.10
18 354 17,',174 70.0c -15.0C 1.80 R4 41.00
19 355 211,928 65.00 -15.00 1.38 R2.5 54.7C
20 356 137,30S 65.0C -10.00 '1.59 R2.5 50.2C
21 357 2,987 60.00 1.64 R4 51.7C
22 358 2,U3 50.00 2.02 S2 35.4C
23 359 2,098 65.00 1.66 R4 39.7C
24 Subtotal 672,499
25
26 DISTRIBUTION PLANT
27 360 2,864 75.00 1.34 R4 74.44
28 361 21,071 60.00 -10.00 1.62 R2.5 47.34
29 362 126,639 45.00 1.97 R1.5 34.24
30 363 2,598
31 364 358,1 56 55.0(-25.00 2.31 R2.5 41.10
32 365 230,658 50.0c -20.0c 2.82 R3 32.70
33 366 103,752 50.0c -25.0C 2.71 S2 37.60
u 367 1U,275 28.0C -20.0c 5.63 S2 16.80
35 368 242,124 44.0C -s.0c 2.11 R2 33.00
36 369 157,073 55.0C -40.0c 2.70 R4 37.55
37 370 - AN 157 15.0C 7.65 s2.5 12.50
38 370.2 - tO 22,569,15.0C 7.65 s2.5 12.50
39 370.3 - WA 28.O',t',!35.0C 3.39 s0.5 23.60
40 37'l 219
41 373 19,413 35.0C -25.0C 1.91 R2.5 26.45
42 373.4 27,087 35.0C -25.0C 3.48 R2.5 26.8C
43 373.5 9,202
44 Subtotal 1,535,868
45
46 GENERAL PLANT
47 390.1 8,095 48.00 -5.00 1.67 S2 39.0C
48 391.1 8,382 5.00 21.28 SQ 3.30
49 393 401 25.00 4.58 SQ '19.40
50 394 3,723 20.00 4.78 SQ 10.24
FERC FORM NO.1 (REV.12-03)Page 331.4
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An Originat(2) jA Resubmission
Date of Reoort
(Mo, Da, Yi)
0313112017
Year/Period of Report
End of 20'l6lQ4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Lrne
No.Account No.
(a)
uepreGraDre
Plant Base
(ln Thousands)(h'l
trSlrrnaleu
Avo. Service- Life
/c)
t\eI
Salvaoe
(Perce-nt)
(rl )
APprleu
Deor. rates(Percent)
/e)
MOnarry
Curvetl,f"
AVerage
Remaini ng
Life(o)
12 395 621 '15.0c 13.73 SQ 4.00
13 397 63,729 '15.0C 2.81 SQ 11.70
14 398 141 10.0c 13.31 SO 7.00
15 Subtotal 85,092
16
17 MISC POWER
18 392 6,276 15.0C 20.0c 1.83 L2.5 13.70
1S 396 3,033 16.0C 5.0c 5.79 s0.5 11.80
20 Subtotal 9,309
21
22
23
24
25
26
27
28
29
30
31 TOTAL COMPANY 3,610,387
32
33
u
2E
36
37
38
20
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. I (REV. 12-03)Page 337.5
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn Orisinat(2) 1-1A Resubmission
Date of Report
(Mo, Da, Yr)
03t3'U2017
Year/Period of Report
End of 20161Q4
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 c€lses in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Line
No.
Description
(Furnish name of reoulatorv commission or bodv the
dbcket or case numb-er and'a description of the rhse)
(a)
Assessed bv
Eegulatoryuommtsston
(b)
h.xpenses
of
Utility
(c)
lotal
Exoense forCuirent Year(b) + (c)
(d)
ueTerreoin Account_ 182.3 al..tsegrnnrng ot 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 Projecl and the Noxon Rapids Project.2,246,10?-106,164 2,139,939
5
6
7
I
I Washington Utilities and Transportation
10 Commission: includes annual fee and various
11 other electric dockets 1,032,05€1,236,417 2,268,472
12
't3 lncludes annual fee and various other natural
14 gas dockets 304,371 334,817 639.188
15
't6 ldaho Public Utilities Commission
17 lncludes annual fee and various other electric
18 dockets 471,762 340,209 811.971
19
20 lncludes annual fee and various other natural
21 gas dockets 116,264 98,22C 214,4U
22
23 Public Utility Commission of Oregon
24 lncludes annual fees and various other natural
25 gas dockets 562,683 448,061 1,010,744
26
27 Not directly assigned eleclric 948,16€948,16€
28 Not directly assigned natural gas 386,585 386,585
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 4,733,238 3,686,311 8,419,549
FERC FORM NO. I (ED. 12-96)Page 350
Name Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Reoorl
(Mo, Da, Yi)
03R1t2017
Year/Period of Reporl
End of 2O16lQ4
REGULATORY 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, (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
(i)
contra
Account
(i)
Amount
ft)
lJeferred rnAccount 182.3
End ofYear
fl)
Line
No.uepanmenl
(f)
^uKluur rr
(q)
AmounI
(h)
1
2
3
Electric 928 2,139,939 4
5
6
7
I
I
10
Electric 928 2,268,472 't'l
12
13
Gas 928 639,188 14
15
't6
17
Electric 928 811,971 18
19
20
Gas 928 214/U 21
22
23
24
Gas 928 1,010,7U 25
26
Electric 928 948,1 66 27
Gas 928 386,585 28
29
30
31
32
33
u
35
36
37
38
39
40
41
42
43
44
45
8,419,54S 46
FERC FORM NO. I (ED. 12-96)Page 351
Name of Respondent
Avista Corporation
This
(1)
(2)
Reoort ls:
5]Rn Originat
nA Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 20161Q4
IH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
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. Reporl 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:
(1) Generation
a. hydroelectric
i. Recreation fish and wildlife
ii Other hydroelectric
b. Fossil-fuel steam
c. lnternal combustion or gas turbine
d. Nuclear
e. Unconventional generation
f. Siting and heat rejection
(2) Transmission
a. Overhead
b. Underground
(3) Distribution
(4) Regional Transmission and Market Operation
(5) Environment (other than equipment)
(6) Other (Classify and include items in excess of $50,000.)
(7) Total Cost lncurred
B. Electric, R, D & D Performed Externally:
('t) Research Support to the electrical Research Council or the Electric
Power Research lnstitute
Line
No.
Classification
(a)
Description
(b)
1 A 3 Electric - Distribution Battery Storage and Electric Vehicle Supply Equipment
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
FERC FORM NO.1 (ED.12A7)Page 352
Name of Respondent
Avista Corporation
This Reoort ls:(1) fiRn Originat(2) jA Resubmission
Date of Report
(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 2O16lQ4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
(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 intemally and in column (d) those items performed outside the company costing $50,000 or more,
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).
Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D &
D activity.
4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,
listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. 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 Internally
currlnlYear Costs lncurred Externally
Current Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(s)
Line
No.Account
(e)
Amount
(0
355,061 1,067,281 107 1,422,U2 1
'1,655 108 1,655 2
31.795 5U 31,795 3
1,076 56,'t06 587 57,182 4
21 13,664 909 13,685 5
11,390 920 11,390 6
2,235 930 2,235 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
FERC FORM NO.1 (ED. 12-87)Page 353
Avista Corporation (1)
(2)Resubmission
Date of Reoort
(Mo, Da, Yi)
o3t31t2017
Year/Period of Report
End of 2016/Q4
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.
Line
No.
Classification
(a)
Direct PavrollDistribution
(b)
Total
(d)
1 Electric
2 Operation
3 Production 't 1,358,057
4 Transmission 3,220,245
5 Regional Market
6 Distribution 8,375,670
7 Customer Accounts 7,757,556
8 Customer Service and lnformational 630,144
9 Sales
10 Administrative and General 19,U2,6U
11 TOTAL Operation (Enter Total of lines 3 thru 10)50,684,356
12 Maintenance
13 Production 3,887,678
14 Transmission 1,311,928
15 Regional Market
16 Distribution 3,397,070
17 Administrative and General
't8 TOTAL Maintenance Ootal of lines 13 thru 17)8,s96,676
19 Total Operation and Maintenance
20 Production (Enter Total of lines 3 and 't3)15,245,735
21 Transmission (Enter Total of lines 4 and 14)4,532,173
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16)11,772,740
24 Customer Accounts (Transcribe from line 7)7,757,556
25 Customer Service and lnformational (Transcribe from line 8)630,144
26 Sales (Transcribe from line 9)
27 Administrative and General (Enter Total of lines 10 and 1 7)19,y2,684
28 TOTAL Oper. and Maint. (Total of lines 20 lhru 27)59,281,032 11,930,143 71,21',1,175
29 Gas
30 Operation
31 Production-Man ufactured Gas
32 Production-Nat. Gas (lncluding Expl. and Dev.)
33 Other Gas Supply 898,67suStorage, LNG Terminaling and Processing 7,675
35 Transmission
36 Distribution s,389,950
37 Customer Accounts 8,470,701
38 Customer Service and lnformational 387,720
39 Sales
40 Administrative and General 24,859,969
4'.!TOTAL Operation (Enter Total of lines 31 thru 40)40,014,690
42 Maintenance
43 Production-Manufactured Gas
M Production-Natural Gas (lncluding Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission 1,210,234
FERC FORM NO. I (ED.12{8)Page 354
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn Original(2) ;lA Resubmission
Date of Reoort
(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2O16lQ4
DISTRIBUTION OF SALARIES AND WAGES (Contlnued)
Line
No.
Classification
(a)
Direct Pavroll
Distribution
(b)
Total
(d)
48 Distribution 3,426,536
49 Adminiskative and General
50 TOTAL Maint. (Enter Total of lines 43 thru 49)4,636,766
51 Total Operation and Maintenance
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (lncluding Expl. and Dev.) (fotal lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45)898,675
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru 7,675
56 Transmission (Lines 35 and 47)1,210,230
57 Distribution (Lines 36 and 48)8,816,486
58 Customer Accounts (Line 37)8,470,701
59 Customer Service and lnformational (Line 38)387,720
60 Sales (Line 39)
61 Administrative and General (Lines 40 and 49)24,859,969
62 TOTAL Operation and Maint. (Total of lines 52 thru 61)44,651,456 8,894,311 53,545,767
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28,62, and il)103,932,488 20,824,454 124,756,942
66 Utility Plant
67 Construction (By Utility Departments)
68 Electric Plant 38,997,474 11,373,996 50,371,470
69 Gas Plant 13,947,088 10,382,141 24,329,229
70 Other (provide details in footnote)
71 TOTAL Construction (Total of lines 68 thru 70)52,944,562 21,756,137 74,700,699
72 Plant Removal (By Utility Departments)
73 Elec{ric Plant 2,293,857 452,76 2,746,563
74 Gas Plant 250,212 49,380 299,592
75 Other (provide details in footnote)
76 TOTAL Plant Removal (Total of lines 73 thru 75)2,il4.069 502,086 3,046,155
77 Other Accounts (Specifo, provide details in footnote):
78 Stores Expense 2,233,289 -2,233,289
79 Preliminary Survey and lnvestiqation 1,540 1,540
80 Small Tools Expense 3,799,506 -3,799,506
81 Misc Deferred Debits 1,066,955 1,066,955
82 Non-Operating Expenses 830,650 830,650
83 Retirement Bonus/SERP/HRA Setllement s1,826 51,826
84 Activities 745,317 745,317
85 Employee lncentive plan 13,148,430 -13,148,430
86 DSM Tariff Rider and Payroll Equalization Liabli$21,331,594 -19,414,518 1,9't7,076
87 lncentive / Stock compensation '136,247 136,247
88
89
90
91
92
93
94
95 TOTAL Other Accounts 43,y5,354 -38,595,743 4,749,611
96 TOTAL SALARIES AND WAGES 202,766,473 4,486,934 207,253,407
FERC FORM NO. I (ED. 12-88)Page 355
Name of Respondent
Avista Corporation
This Report ls:
(1) m An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2016/Q4
COMMON UTILITY PI.ANTAND 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 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 amorlization 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.
7 & 2. Common Plant in service and accumufated provision for depreciation
Acct. No
303
389
390
391
392
393
394
39s
396
397
398
399
Descript ion
Intangible
Land and Land Rights
Structures and Improvements
Office Eurniture and Equipment
Transportation Equipment
Stores Equipment
TooIs, Shop & Garage Equipment
Laboratory Equipment
Power Operated Equipment
Comunications Equipment
Miscellaneous Equipment
Asset Retirement Cost
1.'t 9 , 6LL ,'7 88
11,551,591
t27 ,421,28t
59, 955,230
1L,994,460
4, L96, 439
1"4, 095, 551
384,822
1,793,595
s8,736, 930
395,331
0
Total- Common PIant
Const. Work in Progress
410,143,L07
52,864, 427
Total Util,ity Plant
Acc. Prov. for Dep. & Amort
523,001 ,534
179,879, 417
Net Utility Plant 403,188,057
3. Comon Expenses allocated to Electric and Gas departments:
Acct. No Description TotaI
Al-location to
ELectric Dept
Allocated to
Gas Dept
Basis of
Allocation
901 Cust acct,/collect 641,031
supervisi,on
Meter reading expenses 5,389,094
Cust rec and 17,346,209
collection expenses
90-99A,/R misc fees 0
Uncollectible accounts 6,000,000
Misc cust acct expenses 463t897
Cust svce & Info exp 0
supervision
Cust assistance expenses 905,793
Info & instruct expenses 1,509,2'10
Misc cust serv & info 447,25L
exPenses
338,763 302,268 #of cust G yr end
902
903
3,310,789
9,388, 641
2,078,305
7 ,951 ,568
#of cust @ yr end
*of cust 0 yr end
903
904
90s
901
0
3,170,040
245,092
0
0
2,829,960
21,8 ,198
0
net direct plant
*of cust I yr end
*of cust G yr end
*of cust G yr end
908
909
910
556, 47 4
927 ,220
236,300
349,319
582,050
210,950
#of cust @ yr end
#of cust @ yr end
#of cust G yr end
FERC FORM NO. I (ED. 12{7)Page 356
Name of Respondent
Avista Corporation
This Report ls:
(1) m An Original
(2) tr A Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 2016tQ4
COMMON UTILITY PLANT AND EXPENSES
1. Describe the property carried in the utilig'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 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. Fumish 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 classifled 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.
911
9L2
913
916
920
921
922
923
Sales expense -supervision 0
Demo & selling expenses 0
Advertising expenses 0
Misc sales expenses 0
Admin & gen sal-aries 44,206,850
Office supplies expenses 5,892,154
Admin expenses tranf-credit 0
Outside services 9,898,620
employed
Property insurance 1,55L,439
Injuries and damages 6,035,531
Employee pensions 1 4,336,423
& benefits
Franchise requirement 0
Regulatory commission 2,695,961
expense s
Duplicate charges-credit 0
General advertj-slng expenses 0
Misc aeneral expenses 3,998,111
Rents l, 422,968
Maint of general- plant 1.3,642,952
Depreciation l-9,455,318
Amort of LTD term plant 20,846,903
0
0
0
0
37,630,949
4 ,212, 936
0
7,068,105
0
0
0
0
t2, 57 5,901
7, 67 9,218
0
2,830,515
#of cust G yr
#of cust G yr
#of cust @ yr
#of cust @ yr
four factor
four factor
four factor
four factor
end
end
end
end
924
925
926
t-,106,579
4,404,596
53,029,084
444,860
1,630,935
2r,301,339
four factor
four factor
four factor
921
928
0 0
61 4,3).6
four factor
four factor2, O2r, 5A4
929
930.1
930.2
931
935
403
404
0
0
2t875,433
t,036,285
o o?1 0ro
L3,969,323
t4,871.968
0
0
t, ).23,338
386,683
3,t11,122
5,486,054
5,91 4,935
four
four
four
four
fact or
factor
fact or
factor
four factor
four factor
Note 1: The four factor al-l,ocator is made up of 25 percent each of customer counts, direct labor, direct
O&M & Net direct plant
4, Letters of approval received from staffs of State Regulatory Comissions in 1993
FERC FORM NO.1 (ED.12{7)Page 356.1
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This
(1)
(2)
Reoort ls:
fiRn Originat
nA Resubmission
Date of Report
(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 20161Q4
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Accounl 447, Sales for
Resale, for items shown on ISO/RTO Seftlement Statements. Transactions should be separately netted for each ISO/RTO administered energy market
for purposes of determining whether an entity is a net seller or purchaser in a given hour. Net megawatt hours are to be used as the basis for determlning
whether a net purchase or sale has occurred. ln each monthly reporting period, the hourly sale and purchase net amounts are to be aggregated and
separately reported in Account 447, Sales for Resale, or Account 555, Purchased Power, respectively.
Line
No.
Llescnption of ltem(s)
(a)
tsalance at End ol
Quarter 1
(b)
tsalance at Encl ot
Quarter 2
(c)
Balance at End ot
Quarter 3
(d)
Balan@ at End of
Year
(e)
1 Enerqv
2 Net Purchases (Account 555)2,254 1 1,69i 13.2U
3 Net Sales (Account 447)( 2.463)( 7.374\( 7.374)
4 Transmission Riqhts
5 Ancillary Services I 52 82
6 Other ltems (list separatelv)
7 Access Charqe 835 3,06C 4.707
8 Cost Recovery aa 265 282
9 Day Ahead Enerqy-Conqestion Losses (96)( 375)( 495)
10 FERC Fees E 17 28
11 GMC 2,062 4.229 7.302
12 Hour Ahead Schedulinq Process-RT Se (15)(321 (121
't3 Other (2\(20)
14
15
16
17
'18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33v
35
36
37
38
39
40
41
42
43
M
45
46 TOTAL 2,6'19 11 17,7U
FERC FORM NO. 1/3-Q (NEW. 12-05)Page 397
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn original(2) nA Resubmission
Date of Reoorl(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2016/Q4
PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
ln columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 'l 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), (0, and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (O) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during
the year. lnclude in a footnote and specifo 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
Linr
No
Type of Ancillary Service
(a)
Number of Units
(b)
Unit of
Measure
(c)
Dollars
(d)
Number of Units
(e)
Unit of
Measure
(0
Dollars
(s)
1 Schedulirg, System Control and Dispatch 599 MW 209,484
I Reaciive Supply and Voltage
Regulation and Frequency Response 43,367 MWh 5,203 72,338 MW 739,370
4 Energy lmbalance 559 MW 2,189,496
C Operating Reserve - Spinning 1,075 MWh 23,480 69,510 MWh 1,147,936
€Operating Reserve - Supplement 1,081 MWh 23,528 31342 MWh 742,265
7 Other 1,286,802 MW 12,983,404 1,286,802 MW 12,983,404
I Total (Lines 1 thru 7)1,332,924 13,245,099 1,460,551 17,802,471
FERC FORM NO. I (New 2-04)Page 398
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original(2\ A Resubmission
Date of Report
(Mo, Da, Yr)
43t31t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
No.:7 Column: bIntepartmental frequency and regulation spinning non-sp n ng reserve serv ce
for Native Load.398 Line No.:7 Column: dIntepartmental frequency and regulation a spinning non-sp ng reserve serv cefor Native Load.398 Line No.:7 Column: eInterdepartmental f requencyfor Native Load.
at on an sp n ng and non-sp nn ng reserve servregu ce
398 Line No.:7 Column:
Interdepartmental frequency and regulatlon anfor Native 1oad.
ng and non-sp n ng reserve sespn ce
FERC FORM NO.1 (ED. 12471 Page 450.1
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of(Mo, Da
Report
, Yr)
03t3112017
Year/Period of Report
End of 20161Q4
MONTHLY TRANSMISSION 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, fumish 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 (i) 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 for
Others
(f)
Long-Term Firm
Pointtopoint
Reservations
(s)
Oher Long-
Term Firm
Service
(h)
Short-Term Firm
Pointtopoint
Reservation
(i)
Other
Service
0)
1 January 2,101 2!1 900 1,384 26t tot '18 288 246
2 February 2,11(1t 1 000 1,36S 231 162 11 348 443
1 March 1,861 1t 700 1,294 26:175 '16 127 84
4 Total for Quarter 1 I 4,04i 764 499 45 763 773
E April 1,7lt t 800 1,151 24(.171 10 148 31
6 May 1,741 1600 1,18i 211 18(1i 168 189
7 June 2,31C 2a 1700 '1,49!283 17.JJ 352
I Total lor Quarter 2 3,837 7A 53,4 EI 668 220
o July 2,25i 21 't 800 1,4U 265 171 2i 407 377
10 August 2,18t 1€1700 1,52i 281 17a 2!202 110
11 September 1,81(2e 2000 1,16i 219 16t 2t 256 27
12 Total for Ouarter 3 4,09t 765 52C 74 865 514
13 October 1,86;210C 1,15t 215 17r.23 325 61
14 November 1,94(17 1 90C 1,33€246 162 202 123
15 December 2,28(17 1 80C 1,608 368 162 'lg 142 302
16 Total ,or Quarter 4 4,102 829 4U 43 669 486
11 Total Year to
Date/Year 16,084 3,092 2,047 217 2,965 1,993
FERC FORM NO. 1/3-Q (NEW. 07-04)Page 400
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn orisinat(2) 1-1A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
End of 20161Q4
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)
I SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use):22 Sales to Ultimate Consumers (lncluding
lnterdepartmental Sales)
8,509,330
3 Steam 1,797,20e
4 Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 311.)5 Hydro-Conventional 3,836,11(
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
3,224,296
7 Other 1,828,9v
8 Less Energy for Pumping 25 Energy Furnished Without Charge
I Net Generation (Enter Total of lines 3
through 8)
7,462,25e 26 Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
11,494
10 Purchases 4,823,11t 27 fotal Energy Losses 543, t 86
11 Power Exchanges:28 fOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL L|NE 20)
12,288,306
12 Received 528,87t
13 Delivered 525,942
14 Net Exchanges (Line 12 minus line 13)2,93(
15 Transmission For Other (Wheeling)
't6 Received 3,149,07(
17 Delivered 3,149,07(
18 Net Transmission for Other (Line 16 minus
line'17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
12,288,30t
FERC FORM NO. I (ED. 12-90)Page 401a
Name Respondent
Avista Corporation (1)
(2)
An Original
Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
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 minule integration) associated with the system.
5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
NAME OF SYSTEM:
Line
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
(0
29 January 1 ,1 58,940 273,890 1,511 2 1900
30 February 1,066,834 306,567 1,427 3 0800
31 March 1,061,538 301.737 1,275 16 0800
32 April 963,340 301,281 1.141 5 0800
May 1,002,992 326,304 1,'t65 3 1600
u June 981,870 276,sil 1,541 6 1 800
CE July 946,212 188,730 1,587 28 1 700
36 August 989,20C 198,317 1,546 16 1 800
37 September 875,73t 214,089 1,180 27 't700
38 October 933,26:222,908 1,238 12 0800
39 November 1,080,771 343,851 1,377 29 1800
40 December 1,227,60t 270,068 1,655 17 1800
41 TOTAL 12,288,306 3,224,296
FERC FORM NO. r (ED. 12-90)Page 401b
Name of Respondent
Avista Corporation
ThiS Reoort ls:
5]nn originat(1
(2 aA Resubmission
Date of Report
(Mo, Da, Yr)
03R1t2017
Year/Period of Report
End of 20'l6lQ4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. lndicate by a footnote any plant leased or operated
as a joint facility. 4. lf net peak demand for 60 minules 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 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 Springs2
(b)
Plant
Name: Spokane /V.E,
(c)
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear Gas Turbine Gas Turbine
2 Type of Consk (Conventional, Outdoor, Boiler, etc)Not Applicable Not Applicable
3 Year Originally Constructed 2003 1 978
4 Year Last Unit was lnstalled 2003 1 978
5 Total lnstalled Cap (Max Gen Name Plate Ratings-MW)295.00 61.80
6 Net Peak Demand on Plant - MW (60 minutes)3'19 62
7 Plant Hours Connected to Load 6838 15
I Net Continuous Plant Capability (Megawatts)295 65
9 When Not Limited by Condenser Water 295 0
10 When Limited by Condenser Water 295 0
11 Average Number of Employees 15 1
12 Net Generation, Exclusive of Plant Use - KWh 1 765406000 1 087000
13 Cost of Plant: Land and Land Rights 0 157277
14 Structures and lmprovements 11402122 751025
15 Equipment Costs 17126209 13343481
16 Asset Retirement Costs 351682 0
17 Total Cost 182960013 14251783
't8 Cost per KW of lnstalled Capacity (line 17l5) lncluding 620.2034 230.6114
't9 Produclion Expenses: Oper, Supv, & Engr 1061403 6824
20 Fuel 42164697 44014
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 1 031 499 21836
26 Misc Steam (or Nuclear) Power Expenses 117722 187217
27 Rents 151 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 167363 2905
30 Maintenance of Structures 120798 888
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 2896860 1 5766
33 Maintenance of Misc Steam (or Nuclear) Plant 75589 20155
34 Total Production Expenses 47636082 29960s
35 Expenses per Net KVvh 0.0270 0.2756
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)GAS GAS
37 Unit (Coal-tons/Oil-barreUGas-mcf/N uclear-indicate)MCF MCF
38 Quantity (Units) of Fuel Burned 1 1870089 0 0 14020 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1 020000 0 0 1 020000 0 0
40 Avg Cost of FueUunit, as Delvd f.o.b. during year 3.552 0.000 0.000 3.139 0.000 0.000
41 Average Cost of Fuel per Unit Burned 3.552 0.000 0.000 3.1 39 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 3.483 0.000 0.000 3.078 0.000 0.000
43 Average Cost of Fuel Burned per K\Mr Net Gen 0.024 0.000 0.000 0.040 0.000 0.000
M Average BTU per KWh Net Generation 6858.000 0.000 0.000 13156.000 0.000 0.000
FERC FORM NO. 1 (REV. 12-03)Page 402
Name of Respondent
Avista Corporation
This
(1)
(2)
Reoort ls:
fiRn Originat
!A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
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, Accounl 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 planls. 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. lf 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 unils
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 phvsical and operatinq characteristics of plant.
Plant
Name: Keffle Fal/s
(d)
Plant
Name: Colsfrip
(e)
PIant
Name: Rafhdrum
(0
Line
No.
Steam Steam Gas Turbine 1
Conventional Conventional Not Applicable 2
1 983 't984 1 995 3
1 983 1 985 1 995 4
50.70 233.40 166.50 5
51 229 161 6
7647 7558 345 7
54 222 167 8
54 222 0 I
54 222 0 10
29 340 2 11
341 370000 14ss836000 4061 5000 12
2289077 1288706 621682 13
28546092 104732913 3531838 14
72412319 206122851 601 01 253 15
450687 1 1845908 0 16
1 036981 75 323990378 64254773 17
2045.3289 't388.1336 385.9146 18
1537',18 164961 37076 19
7813269 22729210 1555824 20
0 0 0 21
749196 3713253 0 22
0 0 0 23
0 0 0 24
1083273 117801 200024 25
477382 2552363 1 9966 26
0 41383 0 27
0 0 0 28
1 55845 416303 12255 29
103188 601935 0 30
1773275 5400671 0 31
233469 2198082 57514 32
946939 760879 73909 33
1 3489554 38696841 1956568 34
0.0395 0.0266 o.0482 35
WOOD GAS COAL orL GAS 36
TON MCF TON BBL MCF 37
547411 3883 0 929720 2504 0 497330 0 0 38
8600000 1020000 0 16970000 5880000 0 1020000 0 0 39
14.246 3.854 0.000 24.2U 79.309 0.000 3.128 0.000 0.000 40
14.246 3.854 0.000 24.234 79.309 0.000 3.128 0.000 0.000 41
1.656 3.779 0.000 1.428 13.488 0.000 3.067 0.000 0.000 42
0.023 0.046 0.000 0.015 0.000 0.000 0.038 0.000 0.000 43
13804.000 0.000 0.000 10847.000 0.000 0.000 12490.000 0.000 0.000 M
FERC FORM NO.1 (REV. 12-03)Page 403
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An orisinat(2) f]A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2016/Q4
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 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:Boul&rPart
(b)
Plant
Name:
(c)
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear lnternal Comb
2 Type of Constr (Conventional, Outdoor, Boiler, etc)Conventional
3 Year Originally Constructed 2002
4 Year Last Unit was lnstalled 2002
5 Total lnstalled Cap (Max Gen Name Plate Ratings-MW)24.60 0.00
6 Net Peak Demand on Plant - MW (60 minutes)25 0
7 Plant Hours Connected to Load 877 0
8 Net Continuous Plant Capability (Megawatts)25 0
I \r'Uhen Not Limited by Condenser Water 0 0
10 \Nhen Limited by Condenser Water 0 0
11 Average Number of Employees 2 0
12 Net Generation, Exclusive of Plant Use - K\Nh 1 8358000 0
13 Cost of Plant: Land and Land Rights 1 85629 0
14 Structures and lmprovements 1266746 0
15 Equipment Costs 3178763/0
16 Asset Retirement Costs 0 0
17 Total Cost 33240009 0
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 1351 .21 99 0
19 Production Expenses: Oper, Supv, & Engr 13707 0
20 Fuel 564207 0
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (C0 0 0
25 Electric Expenses 268639 0
26 Misc Steam (or Nuclear) Power Expenses ',l55439 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 12015 0
30 Maintenance of Structures 5249 0
3'1 Maintenance of Boiler (or reaclor) Plant 0 0
32 Maintenance of Electric Plant 205429 0
33 Maintenance of Misc Steam (or Nuclear) Plant 85586 0
34 Total Produc{ion Expenses 1310271 0
35 Expenses per Net KWh 0.0714 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)GAS
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/N uclear-indicate)MCF
38 Quantity (Units) of Fuel Burned 165305 0 0 0 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)1 020000 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 3.413 0.000 0.000 0.000 0.000 0.000
41 Averaqe Cost of Fuel per Unit Burned 3.413 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 3.346 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Burned per K\M Net Gen 0.031 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 9185.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO. 1 (REV.12-03)Page 4O2.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]Rn originat(2) aA Resubmission
Date of Report(Mo, Da, Y0
03t31t2017
Year/Period of Report
End of 2016/Q4
STEAM-ELECTRIC GENERATI NG 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 Accounl 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. lf 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
reoort oeriod and other ohvsical and ooeratino characteristics of olant.
Plant
Name:
(d)
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 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 v
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. I (REV.12-03)Page 403.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An Originat(2) flA Resubmission
Date of Reoort
(Mo, Da, Yi)
03R1t2017
Year/Period of Report
End of 2016/Q4
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, speciffing period. 5. lf any employees aftend
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) musl be consistent with charges to expense accounts 50'l 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:
(b)
Plant
Name:
(c)
1 Kind of Plant (lnternal Comb, Gas Turb, Nuclear
2 Type 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)000 0.00
6 Net Peak Demand on Plant - MW (60 minutes)0 0
7 Plant Hours Connected to Load 0 0
8 Net Continuous Plant Capability (Megawatts)0 0
I Vvhen Not Limited by Condenser Water 0 0
10 \r'/hen Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - K/Uh 0 0
13 Cost of Plant: Land and Land Rights 0 0
14 Structures and lmprovements 0 0
15 Equipment Costs 0 0
16 Asset Retirement Costs 0 0
17 Total Cost 0 0
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 0 0
19 Production Expenses: Oper, Supv, & Engr 0 0
20 Fuel 0 0
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transfened (C0 0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 0 0
27 Renls 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 0 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 0 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0uTotal Production Expenses 0 0
35 Expenses per Net K\y'Utr 0.0000 0.0000
36 Fuel: 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 Average Cost of Fuel Burned per K\Mt Net Gen 0.000 0.000 0.000 0.000 0.000 0.000
M Average BTU per KV/h 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 Reoort ls:(1) 51Rn Originat(2) !A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
STEAM-ELECTRIC GENERATI NG PLANT STATISTI CS (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. 1'1. 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{urbine with the steam plant. 12. lf a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cosl 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
reoort oeriod and other ohvsical and ooeratino characteristics of olant.
Plant
Name:
(d)
Plant
Name:
(e)
Plant
Name:
(f)
Line
No.
1
2
3
4
0.00 000 0.00 5
0 0 0 6
0 0 0 7
0 0 0 8
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 't8
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 u
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 Reoort ls:(1) 5]An original(2) l*lA Resubmission
Date of Reoort
(Mo, Da, Yi)
o3t31t2017
Year/Period of Report
End of 2O16lQ4
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 altend
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 lhe gas and the quantity of fuel burned converted lo Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41 ) musl 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:
(b)
Plant
Name:
(c)
,|Kind of Plant (lnternal Comb, Gas Turb, Nuclear
2 Type 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
8 Net Continuous Plant Capability (Megawatts)0 0
9 \Mren Not Limited by Condenser Water 0 0
10 \r'r'hen Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Nel Generation, Exclusive of Plant Use - KWh 0 0
13 Cost of Plant: Land and Land Rights 0 0
14 Structures and lmprovements 0 0
15 Equipment Costs 0 0
16 Asset Retirement Costs 0 0
17 Total Cost 0 0
18 Cost per KW of lnstalled Capacity (line 17l5) lncluding 0 0
19 Production Expenses: Oper, Supv, & Engr 0 0
20 Fuel 0 0
21 Coolants and Water (Nuclear Plants Only)0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr)0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 0 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 0 0
31 Maintenance of Boiler (or reaclor) Plant 0 0
32 Maintenance of Electric Plant 0 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Produc{ion Expenses 0 0
35 Expenses per Net K\Mr 0.0000 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-ba rrel/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 Fueyunit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Bumed per KVV} Net Gen 0.000 0.000 0.000 0.000 0.000 0.000
44 Average BTU per K\Ml Net Generation 0.000 0.000 0.000 0.000 0.000 0.000
FERC FORM NO. 1 (REV. 12-03)Page 402.3
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An orisinal(2) 3A Resubmission
Date of Report
(Mo, Da, YQ
o3t31t2017
Year/Period of Report
End of 20161Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
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-turbine unit functions in a combined
cycle operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. lf 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 operatinq characteristics of plant.
Plant
Name:
(d)
Plant
Name:
(e)
Plant
Name:
(0
Line
No.
1
2
3
4
0.00 0.00 0.00 5
0 0 0 b
0 0 0 7
0 0 0 8
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 v
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.'r (REV.12-03)Page 403.3
Name of Respondent
Avista Corporation
This Report is:
(1) X An OriginalQ\ A Resubmission
Date of Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
2016tQ4
FOOTNOTE DATA
Schedule Paqe:402 Line No; -1 Column: bratedPortland General E1ectric.
Des ed for eak load service
Joint ro ect o rated Ta1en Montana LLC.
Des e or e oad serv ce
Des gned for peak load service
402 Line No.: -1 Column: c
403 Line No.: -1 Column: e
403 Line No.: -1 Column: f
402.1 Line No.: -1 Column: b
FERC FORM NO.1 (ED. 12471 Page 450.'l
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
ThiS
(1)
(2)
Reoort
Enn
ls:
Original
IA Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
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. ll 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 foolnote. lf licensed project, give project number.
3. lf net peak demand for 60 minutes is not available, give that which is available specifring 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. 2545
Plant Name: Monroe Street
(b)
FERC Licensed Project No. 2545
Plant 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)Conventional Conventional
3 Year Oriqinally Constructed 1 890 1922
4 Year Last Unit was lnstalled 1 992 1922
5 Total installed cap (Gen name plate Rating in MVV)14.80 10.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)19 12
7 Plant Hours Connect to Load 8,1 03 8,239
8 Net Plant Capability (in megawatts)
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 3
12 Net Generation. Exclusive of Plant Use - Kwh 96,851,000 62,708,000
13 Cost of Plant
14 Land and Land Rights 0 1,081,854
15 Structures and lmprovements 11,979,462 981,771
't6 Reservoirs, Dams, and Watenrays 10,095,955 7,607,241
17 Equipment Costs 13,337,503 5,539,522
18 Roads, Railroads, and Bridges 50,448 508,242
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)35,463,368 15,718,630
21 Cost per KW of lnstalled Capacity (line 20 / 5)2,396.1735 1,571.8630
22 Production Expenses
23 Operation Supervision and Engineering 22 750
24 Waler for Power 0 0
25 Hydraulic Expenses 32 3,569
26 Electric Expenses 590,525 595,252
27 Misc Hydraulic Power Generation Expenses 51,265 49,703
28 Rents 0 0
29 Maintenance Supervision and Engineering 721 1.929
30 Maintenance of Structures 23,434 3,721
31 Maintenance of Reservoirs, Dams, and WateMays 97,316 125,750
32 Maintenance of Eledric Plant 63,926 76,011
33 Maintenance of Misc Hydraulic Plant 4,552 12sfiuTotal Production Expenses (total 23 thru 33)831,793 869,041
35 Expenses per net KWh 0.0086 0.0139
FERC FORM NO.1 (REV.12-03)Page 406
Name of Respondent
Avista Corporation
This(1)
(2)
ReDort ls:
fiRn Originat
aA Resubmission
Date of ReDort
(Mo, Da, Yi)
0313112017
Year/Period of Report
End of 2016/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 Accounls. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Suppty 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. zils
Plant Name: Nine Mile Falls
(d)
FERC Licensed Project No. 2545
Plant Name: post Falls
(e)
FERC Licensed Project No. 2OSB
Plant Name: Cabinet Gorge(fl
Line
No.
Run-of-River Storage Storage 1
Conventional Conventional Outdoor 2
1 908 1 906 1952 3
1 994 1 980 1 953 4
36.80 14.80 265.00 5
31 20 265 6
5,876 6,562 5,283 7
8
32 18 255 9
32 18 295 'to
4 4 12 11
108,780,000 88,444,000 1,075,975,000 12
13
33,429 3,570,115 14,782,260 14
18,048,120 3,168,954 13,616,960 15
19,253,432 26,933,827 41,767,408 16
62,281,0U 3,426,839 57,211,930 17
594,870 0 1,670,911 18
0 0 0 19
100,210,885 37,099,73s 129,049,469 20
2,723.12',19 2,506.7389 486.9791 21
22
71 60 96,717 23
0 0 0 24
4,595 2,037 0 25
609,213 696,180 1 ,515,004 26
43,921 96,899 91,838 27
0 0 0 28
7,141 13,001 50,913 29
't3,182 89,570 177,412 30
490,562 76,493 13,910 31
123,197 575,433 299,384 32
12,U8 14,771 56,602 33
1,304,830 1,564,444 2,301,780 34
0.0120 0.0177 0.0021 35
FERC FORM NO. 1 (REV. 12-03)Page 407
Name of Respondent
Avista Corporation
This
(1)
(2)
ReDort ls:
5]Rn originat
l-lA Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
End of 2O16lQ4
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 speciffing period.
4. lf a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 2058
Plant Name: Noxon Rapids
(b)
FERC Licensed Project No. 2545
Plant Name: Long Lake
(c)
1 Kind of Plant (Run-of-River or Storage)Storage Storage
2 Plant Construction type (Conventional or Outdoor)Outdoor Conventional
3 Year Originally Construcled 1 95S 1915
4 Year Last Unit was lnstalled 1977 1924
E Total installed cap (Gen name plate Rating in MW)487.80 70.00
6 Net Peak Demand on Plant-Megawatts (60 minutes)539 90
7 Plant Hours Connect to Load 5,220 6,573
8 Net Plant Capability (in megawatts)
9 (a) Under Most Favorable Oper Conditions 581 90
10 (b) Under the Most Adverse Oper Conditions 623 90
11 Average Number of Employees 12 b
12 Net Generation, Exclusive of Plant Use - Kwh 1,695,642,000 525,331,000
13 Cost of Plant
14 Land and Land Rights 35,772,759 2,128,013
15 Structures and lmprovements 't8,904,320 6,1 19,005
16 Reservoirs, Dams, and Watenrvays 34,943,300 33,852,969
17 Equipment Costs 104,963,765 12,515,354
18 Roads, Railroads, and Bridqes 246,561 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19)194,830,705 54,615,341
21 Cost per KW of lnstalled Capacity (line 20 / 5)399.4069 780.2',t92
22 Production Expenses
23 Operation Supervision and Enqineering 101,290 5,846
24 Water for Power 0 0
25 Hydraulic Expenses 104,450 10,534
26 Electric Expenses 1,548,274 830,1 17
27 Misc Hydraulic Power Generation Expenses 172,229 53,6s9
28 Rents 0 0
29 Maintenance Supervision and Engineering 147,U3 533
30 Maintenance of Structures 65,141 43,283
31 Maintenance of Reservoirs, Dams, and Wateruays 863,883 37,925
32 Maintenance of Electric Plant 869,784 324,561
33 Maintenance of Misc Hydraulic Plant 57,197 29,182vTotal Production Expenses (total 23 thru 33)3,929,891 '1,335,640
35 Expenses per net KWh 0.0023 0.0025
FERC FORM NO.1 (REV.12{3)Page 406.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]An Originat(2) f]A Resubmission
Date of Report(Mo, Da, Yr)
03131t2017
Year/Period of Report
End of 20161Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Larse 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 conlrol 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. 2il5
Plant Name: Little Falls
(d)
FERC Licensed Project No.
Plant Name:
(e)
0 FERC Licensed Project No.
Plant Name:
(fl
0 Line
No.
Run-of-River 1
Conventional 2
1910 3
191 't 4
32.00 0.00 0,00 5
37 0 0 6
7,194 0 0 7
8
37 0 0 I
37 0 0 10
5 0 0 11
182,385,000 0 0 12
13
4,325,371 0 0 14
2,958,816 0 0 15
5,065,492 0 0 16
27,672,656 0 0 17
0 0 0 18
0 0 0 19
40,022,335 0 0 20
1,250.6980 0.0000 0.0000 21
22
48 0 0 23
0 0 0 24
10,663 0 0 25
713,417 0 0 26
22,315 0 0 27
812,U2 0 0 28
7,327 0 0 29
35,062 0 0 30
567,U1 0 0 31
317,466 0 0 32
9,303 0 0 33
2i%,284 0 0 v
0.0137 0.0000 0.0000 35
FERC FORir NO. 1 (REV.12-03)Page rO7.1
Avista Corporation (1)
(2)
Original
Resubmission
Date of(Mo, DaReport
, Yr)
03t31t2017
Year/Period of Report
End of 2016/Q4
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. lf licensed project,
give project number in footnote.
Line
No.
Name of Plant
(a)
Year
Orio.
Con-st.
(b)
rnslafleo uapacly
Name Plate Ratin!
(ln MW)
(c)
NET PEAKDemand
MW(60,9in.)
Net Generation
ExcludinoPlant UsE
(e)
Cost of Plant
(f)
1 Kettle Falls CT 2002 7.20 8.C 3,468,00C 9,204,197
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
'19
20
21
22
23
24
25
26
27
28
29
30
31
32
33v
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03)Page 4'10
Name of Respondent
Avista Corporation
(1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t3112017
Year/Period of Report
End of 2O16lQ4
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
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)
Proouctron Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
o
Line
No.FUet
(i)
Marnlenance
0)
1,274,698 144,390 130,67:35,921 Nat Gas 322 1
2
3
4
5
6
7
I
I
10
11
12
13
14
15
16
17
't8
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
u.
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. r (REV. 12-03)Page 4'11
Name of Respondent
Avista Corporation
This ReDort ls:
5.1Rn originat
1-lA Resubmission
(1)
(2)
Date of Report(Mo, Da, Yr)
o3t31t2017
Year/Period of Reporl
End of 2016/Q4
TRANSMISSION LINE STATISTICS
1 . Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. 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 designaled; 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 IION Type of
Supporting
Structure
(e)
LENGTH (Pole miles)(ln the Case.ofunoerorouno lrnesreport Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
of LineDesionated
r0
un Srrucluresof AnotherLine(s)
1 Group Sum 60.0(60.00 1.00
2
3 Group Sum 1 15.0(115.00 1,542.00
4
5 Beacon Sub #4 BPA Bell Sub 230.0(230.00 Steel Tower 1.00 1
6 Beacon Sub BPA Bell Sub 230.0(230.00 H Type 5.00 1
7 Beacon Sub #5 BPA Bell Sub 230.0(230.00 Steel Pole 3.00 1
8 Beacon Sub #5 BPA Bell Sub 230.0(230.00 H Type 3.00 1
9 Beacon Cabinet Gorge Plant 230.0(230.00 Steel Tower 1.00 1
10 Beacon Cabinet Gorge Plant 230.0(230.00 Steel Pole 27.04 2
11 Beacon Cabinet Gorge Plant 230.0(230.00 H Type 53.00 1
12 Beacon Sub Lolo Sub 230.0(230.00 Steel Tower 1.00 1
13 Beacon Sub Lolo Sub 230.0(230.00 Steel Pole 12.00 1
't4 Beacon Sub Lolo Sub 230.0(230.00 H Type 90.00 1
15 Benewah Shawnee 230.0(230.00 Steel Pole 1.00 1
16 Benewah Shawnee 230.0(230.00 Steel Pole 59.00 1
17 Noxon Plant Pine Creek Sub 230.0(230.00 Steel Pole 29.00 I
18 Noxon Plant Pine Creek Sub 230.0i 230.00 H Type 1.00 1
19 Noxon Plant Pine Creek Sub 230.0t 230.00 H Type 14.00 1
20 Cabinet Gorge Plant Noxon 230.0(230.00 H Type 2.0(1
21 Cabinet Gorge Plant Noxon 230.0(230.00 H Type 17.0(1
22 Benewah Sw. Station Pine Creek Sub 230.0(230.00 Steel Tower 1
z3 Benewah Sw. Station Pine Creek Sub 230.0(230.00 H Type 43.0(1
24 Divide Creek Lolo Sub 230.0(230.00 Steel Tower 1
25 Divide Creek Lolo Sub 230.0(230.00 H Type 43,0(1
26 N. Lewiston Walla Walla 230.0(230.00 H Type 39.0(1
2t N. Lewiston Walla Walla 230.0(230.00 H Type 4.0(1
28 N. Lewiston Walla Walla 230.0(230.00 Steel Pole 4.0(1
29 N. Lewiston Shawnee 230.0(230.00 Steel Pole 7.0(1
30 N. Lewiston Shawnee 230.0(230.00 H Type 27.0(1
31 Walla Walla Wanapum 230.0(230.00 Alum.1
32 Walla Walla Wanapum 230.0(230.00 H Type 15.0(
33 Walla Walla Wanapum 230.0(230.00 H Type 63.0(u BPA (Libby)Noxon Plant 230.0(230.00 Steel Tower 1.0(
?E BPtuHot Springs #1 Noxon Plant 230.0(230.00 Steel Tower 1.0(
36 IOTAL 2,205.0C 3.00 41
FERC FORM NO. I (ED. 12-87)Page 422
S:
Avista Corporation
(1)
(2)
Original
Resubmission
Date ot Report
(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
I RANSMTSSTON LINE S tA I tS I tCS (Conttnued)
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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing
expenses ofthe Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specifu 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 (i) to (l) on the book cost at end of year.
Size of
Conductor
and Material
(i)
uu|i I (.)F LINE (lncluoe ln uorumn u) Lano
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
0)
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses
(m)
Maintenance
Expenses(n)
Rents
(o)
Total
Expenses(p)
136,03t 650,395 786,433 1
2
11,120,91i 1 70,003,916 181,124,828 382,274 1,038,851 1,421,12!3
4
I272 ACSS a
t272 ACSS 17,91i 1,429,56(1,447 ,472 1,192 1,19i b
t272 ACSS 7
I272 ACSS 30,32:3,275,35i 3,305,680 876 87t I
t272 ACSS I
I59O ACSS '10
r590 ACSR 1 ,1s6,19t 41,995,911 43,152,10i 31,060 31,06(11
t590 ACSS 12
r590 ACSS 13
1272 MoMAL 456,16i 20,352,35!20,808,521 782 8,245 9,O2i 14
r622 ACSS 15
I59O ACSS 570,207 48,481,65:49,051,86(16
r272 ACSR 17
| 590 ACSS 18
354 McMAL 1,097,67(1 9,135,051 20,232,73r,5,87S 115,924 12't,803 19
795 ACSR 20
154 MoMAL 1U,21'1,768,027 1,952,23t 50,23€50,23€tt
1622 ACSS 22
154 MoMAL 350,32r 4,789,076 5,139,401 112,009 112,00(23
1272 McMAL 24
1272 McMAL 86,22t 5,359,151 5,445,37e 2,485 2,48!25
1272 MoMAL 26
r272 ACSR 27
1272 ACSR 623,9&7 ,831,213 8,455,197 1,U3 886 2,221 28
1272 ACSR 29
1272 ACSR 872,15(10,046,522 10,918,672 242 24i JU
1272 MoMAL 31
t272 ACSR 32
1272 MoMAL 205,34i 6,820,219 7,025,566 2,348 2,34t 33
t272 ACSR 34
1272 ACSR 19,s21 19,521 2,318 2,31t 35
21,395,525 385,944,773 407,340,29t 462,686 1,592,436 89,06(2,144,181 36
FERC FORM NO. 1 (ED. 12-87)Page 423
Name of Respondenl
Avista Corporation
This Reoort ls:(1) 5l1Rn orisinat(2) 11A Resubmission
Date of Report(Mo, Da, Yr)
o3t31t2017
Year/Period of Report
End of 20161Q4
TRANSMISSION LINE STATISTICS
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines forwhich plant costs are included in Account 121, Nonutility Properg.
5. lndicatewhetherthetypeofsupportingstructurereportedincolumn(e)is: (1)singlepolewoodorsteel; (2)H-framewood,orsteel 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 (0 and (g) the lotal 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.
UtrSlLrNA I IUN VULIAUE (KV}
(lndicate wherdbther than
60 cvcle. 3 ohase)
Type of
Supporting
Structure
(e)
LENGTH (POIE MiIES)(ln the Case.ofunoerorouno Itnes
report Eircuit miles)
Number
of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
of LineDesionated
fo
UtI JII UUIUIESof AnotherLine
(s)
1 BPA/Hot Springs #2 Noxon Plant (dead)230.0(230.00 Steel Tower 2.00 1
2 BPtuHot Springs #2 Noxon Plant 230.0(230.00 Steel Pole 2.00 1
BPA/Hot Springs #2 Noxon Plant 230.0(230.00 H Type 66.0(1
4 Coulee West Side Sub 230.0(230.00 Steel Pole 1.0(2
E BPA Line West Side Sub 230,0(230.00 Steel Pole 1.0(2
6 Hatwai N. Lewiston Sub 230.0(230.00 H Type 7.0(I
7 Divide Creek lmnaha 230.0(230.00 H Type 20,0(1
I Colstrip Plant Broadview 500.0(500.00
o
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33v
35
36 TOTAL 2,205.04 3.00 41
FERC FORM NO.1 (ED.12-87)Page 422.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) finn origlnat(2) nA Resubmission
Date of Reoort(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 20161Q4
7. Do not reporl 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 property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for
which the respondent is not the sole owner but which the respondent operates or shares in the operation of furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondenl 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. Speciff 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. Specifo whether lessee is an associated company.
10. Base the plant cost figures called for in columns O to (l) on the book cost at end of year.
Size of
Conduclor
and Material
(i)
cos I oF LINE (lnclude tn uolumn 0) Lano,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
o
Construction and
Other Costs(k)
Total Cost
(t)
Operation
Expenses(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses
1272 MoMAL 1
t272 ACSR 2
1272 MoMAL 3,536,54r 8,148,083 11,684,62t 8,292 84,582 92.871 3
t272 ACSR 8,481 8,482 4
t272 ACSR 27,975 594,652 622,631 4,51C 4,51(5
I59O ACSR 1 13,79t 2,626,745 2,740,544 292 29i b
1272 MoMAL 205,26i 1,325,464 1,530,726 7
595,78!31 ,291,898 31,887,687 61,768 138,728 89,060 289,55(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
21,395,525 385,944,773 407,340,298 462,68e 1592,$e 89,060 2,144,18i 36
FERC FORM NO.1 (ED.12{7)Page 423.1
Name of Respondent
Avista Corporation
This Reoort ls:(1) 5]nn Origlnal(2) ;-1A Resubmission
Date of Reoort
(Mo, Da, Yi)
03131t20't7
Year/Period of Report
End of 20161Q4
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.
LINtr UtrSIUNA IIUN LI t9Length
tnMiles
(c)
CIFTCUI IS PER S IRUC IUR
From
(a)
To
(b)
Type
(d)
Numbeiper
Miles
(e)
Present
(0
Ultimate
(s)
1 No new transmission lines added in 2016
2
,e
4
E
€
7
I
I
1C
11
't2
13
14
15
16
17
18
1€
2C
21
zt
23
24
2a
2e
27
2e
29
3C
31
32
aa
u
AE
3€
37
38
39
4C
41
42
43,
44 TOTAL
FERC FORM NO.1 (REV. 1243)Page 424
S:
Avista Corporation (1)
(2)
Original
Resubmission
Date of Report(Mo, Da, Yr)
03t3112017
Year/Period of Report
End of 20161Q4
I RANSMTSSTON LtNtS AIJUED UUR|NG YEAR (C;onttnued)
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.
CUNUUUIORS Voltage
KV
(oee[3tins)
LINE UUs I Line
NoSize
(h)
Specification
(i)
Confiouration
and Spacing
(i)
Land and
Land,Rights
Poles, Towers
and Fixtures
(m)
Conductors
and Devices(n)
Assel
Retire. Costs(o)
Total
(p)
1
2
3
4
5
6
7
I
c
1C
11
t2
13
14
'15
1€
17
18
19
2C
21
22
ZJ
24
25
26
2t
28
29
30
31
32
33
u
35
36
37
38
39
40
41
42
43
44
FERC FORM NO.1 (REV. 12-03)Page 425
Avista Corporation
(1)
(2)
An Original
A Resubmission
Date of Report
(Mo, Da, Yr)
03131t2017
Year/Period of Report
End of 20161Q4
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).
Line
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 Ainrvay Heights Distr. Unattended 1 15.0C 13.80
4 Barker Road Distr. Unattended 115.0C 13.80
5 Beacon Trnsm. & Disk Unatt 230.0c 1 15.00 13.80
6 Boulder Trnsm. Unattended 230.0c 1 15.00 13.80
7 Chester Distr. Unattended 115.0C 13.80
8 Chewelah 115Kv Distr. Unattended 115.0C 13.80
9 Colbert Distr. Unattended 't 15.0c 13.80
10 College & Walnut Distr. Unattended 1 15.0C 13.80
11 Colville 115Kv Distr. Unattended 115.0C 13.80
12 Critchfield Distr. Unattended 1 15.0C 13.80
13 Deer Park Dist. Unattended 115.0C 13.80
14 Dry Creek Transm. Unattended 230.0c 't 15.00 13.80
15 Dry Gulch Distr. Unattended 1 15.0C 13.80
16 East Colfax Distr. Unattended 't 't5.0c 13.80
17 East Farms Distr. Unattended 1 15.0C 13.80
18 Fort Wright Distr. Unattended 1 15.0C 13.80
19 Francis and Cedar Distr. Unattended 1 15.0C 13.80
20 Gifford Distr. Unattended 1 15.0C 34.00
2'l Glenrose Distr. Unattended '1 15.0C 13.80
22 Greenwood Distr. Unattended 1 15.0C 13.80
23 Hallett & \Mite Distr. Unattended 1 15.0C 13.80
24 lndian Trail Dist. Unattended 1 15.0C 13.80
25 lndustrial Park Dist. Unattended 1 15.0C 13.80
26 Kettle Falls Distr. Unattended 1 15.0C 13.80
27 Lee & Reynolds Distr. Unattended 1 15.0C 13.80
28 Liberty Lake Distr. Unattended 115.0C 13.80
29 Little Falls 1 '15/34Kv Distr. Unattended 115.0C 34.00
30 Lyons & Standard Distr. Unattended I 15.0C 't3.80
31 Mead Distr. Unattended 1 15.0C 13.80
32 Metro Distr. Unattended 1 15.0C 13.80
33 Milan Distr. Unattended 1 15.0C 13.80
34 Millwood Dist. Unattended 1 15.0C 13.80
35 Ninth & Central Distr. Unattended 1'15.0C 13.80
36 Northeast Distr. Unattended 1 15.0C 13.80
37 Northwest Distr. Unattended 1 15.0C 13.80
38 Opportunity Dist. Unattended '1 15.0C 13.80
39 Othello Distr. Unattended 1 15.0C 13.80
40 Post Street Distr. Unattended 1 15.0C 13.80
FERC FORM NO.1 (ED.12-96)Page 426
Name
Avista Corporation
(1)
(2)
An Original
A Resubmission
Date of Reoort
(Mo, Da, Yi)
03t3112017
Year/Period of Report
End of 2O16lQ4
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)
(0
Number ot
Transformers
ln Service
(q)
NumDer ot
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total
(ln
Capacity
MVa)
(k)
1
2
24 2 Frcd Oil&Air Fan&Cap ?o 4C 3
12 1 Two Stage Far 1 2C 4
536 4 Two Stage Far 2 56C 5
300 2 Two Stage Far 2 50c 6
24 2 Frcd Oil & Air Far 2 4C 7
12 1 Two Stage Far 1 2C E
12 1 Frcd Oil & Air Far 16 2C 9
36 2 Two Stage Far 2 6C 10
32 ,l Frcd Oil & Air Fan e 4a 11
12 1 Two Stage Far 1 2C 12
12 1 Two Stage Far 1 2C 13
150 1 Two Stage Fan & Caps 22?25C 14
24 2 Frcd Oil & Air Fan 4C 15
12 1 FroiUAir Far 1 2C 16
12 1 Two Stage Far 1 2C 1t
24 2 ,|Fr Oil/Air/2StgFan z 4C 18
36 2 Two Stage Far z 6C 19
12 1 20
12 1 Frcd Oil & Air Fan 1 2C 21
12 1 Two Stage Far 1 2C 22
12 1 Two Stg Far 1 2C 2J
12 1 Two Stage Far 1 2A 24
24 2 Two Stg/PVFrcd Oil 14 4A 25
12 1 Frcd Oil & Air Fan 1 2A 26
12 1 Two Stage Far 1 2A 27
24 2 Two Stage Fan 40 2E
12 1 29
36 2 Two Stage Fan z 60 30
18 1 Two Stage Fan 1 30 31
24 2 Two Stage Fan 2 4A 32
24 2 Frcd Oil & Air Fan I 4A 33
24 2 2 Two Stage Fan 2 4A 'J4
24 2 1 Frcd & Two Stage Fan I 40 35
24 2 Two Stage Fan 2 40 36
24 2 Two Stage Fan 2 40 37
12 1 Two Stage Fan 1 20 3E
24 2 FrOil/AirFan z 40 39
36 Frcd Oil & Wt Fan 60 40
FERC FORM NO. I (ED. r2-96)Page 427
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
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).
Line
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 15.00 13.80
2 Ross Park Distr. Unattended I 15.00 13.80
3 Roxboro Distr. Unattended 1 15.00 24.00
4 Shawnee Trans. Unattended 230.00 115.00 13.80
5 Silver Lake Distr. Unaftended 1 15.00 13.80
b Southeast Distr. Unattended 1 15.00 13.80
7 South Othello Distr. Unattended 115.00 13.80
8 South Pullman Distr. Unattended 1 15.00 13.80
I Sunset Distr. Unattended "t 15.00 13.80
10 Terre View Dist. Unattended 1 15.00 13.80
11 Third & Hatch Distr. Unattended 1 15.00 13.80
12 Turner Dist. Unattended 1 15.00 13.80
13 Waikiki Distr. Unattended I 15.00 13.80
14 West Side Trans. Unattended 230.00 115.00 13.80
15 Other: 28 substa less than 1OMVA Distr. Unattended
16
't7 STATE OF IDAHO
18 Appleway Dist. Unattended 115.00 13.80
19 Avondale Dist. Unattended 1 15.00 13.80
20 Benewah Trans. Unattended 230.00 115.00 13.80
21 Big Creek Distr. Unattended 1 15.00 13 80
22 Blue Creek Distr. Unattended 1 15.00 13.80
23 Bunker Hill Limited Distr. Unattended 115.00 13.80
24 Cabinet Gorge (Switchyard)Trans. Unattended 230.0c 1 15.00 't3.80
25 Clark Fork Distr. Unattended 115.0C 21 .80
26 Coeur d'Alene 15th Ave Distr. Unattended 115.0C 13.80
27 Cottonwood Distr. Unattended 115.0C 24.90
28 Dalton Distr. Unattended 't15.0c 13.80
29 Grangeville Distr. Unattended 115.0C 13.80
30 Holbrook Distr. Unattended 115.0C 't3.80
31 Huetter Distr. Unaftended 115.0C 13.80
32 ldaho Road Distr Unattended 1 15.0C 13.80
33 Juliaetta Distr. Unattended I 15.0C 13.80
34 Kamiah Dist. Unattended 1 15.0C 13.80
35 Kooskia Distr. Unattended 1 15.0C 13.80
36 Lewiston Mill Rd Distr. Unattended 1 15.0C 13.20
37 Lolo Tran & Dist Unattnd 230.0c 115.00 13.80
38 Moscow Distr. Unattended 1 15.0C 13.80
39 Moscow 230Kv Tran & Dist Unattnd 230.0c 1 15.00 13.80
40 North Moscow Distr. Unattended 1't5.0c 13.80
FERC FORM NO.1 (ED. r2-96)Page 426.1
Name Respondent
Avista Corporation
(1)
(2)
Original
Resubmission
Date of Report
(Mo, Da, Y0
03t31t2017
Year/Period of Report
End of 2016/Q4
5. Show in columns (l), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otheruise 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)
(0
Number of
Transformers
ln Service
(q)
Number ot
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
fi)
Total Capacity
(ln MVa)
(k)
24 2 Two Stage Fan I 4C 1
30 2 Two Stage Far z 54 2
24 2 Two Stage Far 4C 3
150 1 Two Stage Far 1 25C 4
12 1 Two Stage Far I 2C 5
30 2 Two Stage Far I 5C 6
12 1 Two Stage Far 1 2C 7
30 2 Two Stage Far 5C I
33 2 Two Stage Fan & Caps 5C EE 9
12 1 Two Stage Far 1 2C 10
54 3 Two Stg Fan & Cap 103 9C 11
36 2 Two Stg Far z 6C 't2
24 2 Two Stage Far I 4C 't3
250 2 14
166 v 15
16
17
36 2 Two Stage Far z 6C 16
12 1 Two Stage Far 1 2C 19
75 ,|Two Stage Fan & Caps 223 125 20
18 2 Portable Far I 22 21
12 1 Two Stage Far 1 2C 22
12 1 Frcd Air Far 1 16 23
75 1 Two Stage Far 1 125 24
10 1 Frcd Air Far 1 13 25
36 2 Two Stage Far I 60 26
'12 1 Two Stage Far 1 2A 27
24 2 FrcOil/Ai12StgFan z 40 2E
25 4 FrcdOiUAir/Pt Fan&C 17 34 29
't2 ,|Two Stage Far 1 2A 30
't2 1 Two Stage Fan 1 2A 31
12 1 Two Stage Fan ,|2A 32
12 1 Frcd Oil & Air Fan 1 2A 33
12 1 Two Stage Far 1 2A 34
15 3 Frcd Air Fan ?2A 35
18 1 Two Stage Far 1 30 36
262 3 Frcd Oil/Air/Two Stg 1 270 37
24 2 FrOiUAir/2Stg Fan 2 4A 3E
162 2 Frcd Air Fan & Caps 76 270 39
12 ,|Two Stage Fan 1 20 40
FERC FORM NO. I (ED. 12-96)Page 427.1
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 20161Q4
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).
Line
No.Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (ln MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 North Lewiston 230kV Tran & Dist Unattnd 230.0c 1't5.00 13.80
2 Oden Distr. Unattended 1 15.0C 21.80
3 Oldtown Distr. Unattended 1 15.0C 21.80
4 Orofino Distr. Unattended 1 15.0C 13.80
5 Osburn Distr. Unattended 115.0C 13.80
6 Pine Creek Tran & Dist Unatlnd 230.0c 115.00 13.80
7 Pleasant View Distr. Unatlended 1 1 5.0C 13.80
I Plummer Dist Unattended 1 15.0C 13.80
9 Post Falls Distr. Unattended 115.0C 13.80
10 Potlatch Distr. Unattended 115.0C 13.80
11 Prarie Distr. Unattended 115.0C 13.80
12 Priest River Distr. Unattended 1 15.0C 20.80
13 Rathdrum Trans & Distr Unattd 230.0c 1 15.00 13.8C
14 Sagle Dist. Unattended 115.0C 20.80
15 Sandpoint Distr. Unattended 115.0C 20.80
16 South Lewiston Distr. Unattended 115.0C 13.80
17 Sweetwater Distr. Unattended 115.0C 24.90
18 St. Maries Distr. Unaftended 115.0C 23.90
19 Tenth & Stewart Distr. Unattended '1 15.0C 13.80
20 Wallace Distr. Unattended 1 15.0C 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 115.00 13.80
29 Kettle Falls Trans. Aftended 115.00 '| 3.80
30 Long Lake Trans. Attended 't15.00 4.00
31 Nine Mile Trans. Attended 't15.00 13.80
32 Little Falls Trans. Attended 115.00 4.00
33 Northeast Trans. Attended 1 15.00 13.80
u Post Street Trans. Attended 13.80 4.00
35
36 STATE OF IDAHO
37 Cabinet Gorge (HED)Trans. Attended 230.00 13.80
38 Post Falls Trans. Attended 't15.00 2.30
39 Rathdrum Trans. Attended 1 15.00 13.80
40 STATE OF MONTANA
FERC FORM NO. I (ED. 12-96)Page 426.2
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 2O16lQ4
5. Show in columns (l), (i), 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
(ln Service) (ln MVa)
(0
Number of
Transformers
ln Service
(q)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
258 2 Frcd Air Fan & Caps 48 26C 1
10 1 Frcd Air Far 1 1:2
18 2 Frcd Air Far 2 22 3
2A 2 Frcd Oil & Air Fan 1 2t 4
12 I Portable Far 1 15 5
212 ?Two Stg Fan/Capacitc 4!27C 6
12 1 Two Stage Far 1 2C 7
12 1 Two Stage Far 1 2C I
18 1 Two Stage Far 1 3C 9
15 2 Portable Far 19 10
12 1 Frcd Oil & Air Fan 1 2C 11
10 1 Frcd Air Far 1 '13 12
474 4 Frcd Oil & Air Fan 5C 49C 13
12 1 Two Stage Far 1 2C 14
30 a Frcd Air Far 38 15
27 4 Port Fan/FrcdOil/Air 4 ?c 16
12 1 Frcd Oil & Air Fan 1 2C 17
24 2 Two Stage Far 2 4C 1E
30 2 Frcd Oil/Airffwo Stg 5C 19
10 a 20
65 13 21
22
23
5 I 24
25
26
27
36 1 Two Stage Fan 1 60 28
v 1 1 Two Stage Fan 1 62 29
80 4 1 30
12 1 31
24 2 Frcd Oil & Air Fan z 40 32
36 1 Two Stage Fan 1 60 33
35 2 u
35
36
300 6 1 Frcd Oil and Air Fan 37
16 2 Frcd Air/Oil/Air Fan 2 21 38
114 2 1 Two Stage Fan 2 190 39
40
FERC FORM NO. 1 (ED. 12-96)Page 427.2
Name of Respondent
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of Report(Mo, Da, Yr)
03t31t2017
Year/Period of Report
End of 20161Q4
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).
Line
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 13.80
2
3 STATE OF OREGON
4 Coyote Springs ll Trans. Attended 500.0c 13.80 18.0C
5
6 SUMMARY:
7 Washington:
8 4 subs Trans. Unattended
I 75 subs Distr. Unattended
10 1 subs Tran & Dist Unattnd
11 7 subs Trans. Attended
12 ldaho:
13 2 subs Trans. Unattended
14 48 subs Distr. Unattended
15 5 subs Tran & Dist Unattnd
16 3 subs Trans. Attended
17 Montana: 'l sub Trans. Attended
18 1 sub Distr. Unattended
19 Oregon: 'l sub Trans. Unattended
20 System: 148 subs
21
22
23
24
25
26
27
28
29
30
31
32
33
v
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-s6)Page 426.3
Name
Avista Corporation (1)
(2)
An Original
A Resubmission
Date of ReDort(Mo, Da, Yi)
03t31t2017
Year/Period of Report
End of 2O16lQ4
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 ftom 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)
(f)
Number of
Transformers
ln Service
(q)
Number ot
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.Type of Equipment
(i)
Number of Units
(i)
Total Capacity
(ln MVa)
(k)
435 I 1 Two Stage Far z 635 1
2
3
213 1 1 Two Stage far 1 355 4
5
6
I
850 E
118/I
s36 10
257 11
12
150 13
663 14
1368 15
430 't6
435 17
5 18
213 19
6090 20
21
22
23
24
25
26
2t
28
29
30
31
32
33
v
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) 5l1rn orisinat(2) []A Resubmission
Dete of Report(Mo, Da, Yr)
03131t2017
Year/Period of Report
End of 2O16lQ4
TRANSACTIONS WITH ASSOCIATED (AFFIL
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3. Wrere amounls 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/Afiiliated
Company
(b)
Account
Charged or
Credited
(c)
Amount
Charged or
Credited
(d)
1 Non-power Goods or Services Provided by Affiliated
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21 Corporate Support Salix lnc.146000 759,855
22 Corporate Support Avista Development 146000 346,058
23
24
25
26
27
28
29
30
31
32
33v
35
36
37
38
39
40
41
42
FERC FORM NO.'l (New)
FERC FORM NO. 1-F (New)
Page 429
At)rl-E
Avista Corp.
2016
IDAHO
State Electric Annual Report
(IC 61-405)
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation x
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
3t31t2017
Year / Period of Report
End of 2UO lA4
STATEMENT OF UT]LITY OPERATING INCOME.IDAHO
lnstructions
'l . For each account below, report the amount attributable to the state of ldaho based on ldaho jurisdictional 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
Line
No Account
(a)
Refer to
Form 1
Page
(b)
TOTAL SYSTEM - IDAHO
Cunent Year
(c)
Prior Year
(d)
1 UTILITY OPERATING INCOI\'E
2 Ooeratino Revenues (400)300-301 422 534 944 438 862 gg3
3 Ooeratino Exoenses
4 1 320-323 242.634.836 281.095.309
5 Maintenance Exoenses (402)320-323 21.529.102 19.716.641
6 336-337 41 .899.969 39.168.371
7 Deoreciation ExDense for Asset Retirement Costs (403.'l )336-337
8 of 336-337 6.813.05'1 5.806.994
g of Plant ent 336-337 (130.82S)67.304
10 Amort. of Prooertv Losses. Unrecov Plant and Reoulatorv Studv Costs (407)
11 Amortization of Conversion ExDenses (407)
12 Requlatorv Debits (407.3)201.332 (1.905.433)
13 (Less) Reoulatorv Credits (407 4l (1.069.637)(6.951.798)
14 Taxes OtherThan lncome Taxes {408.1)262-263 17 246 129 17,489.467
15 lncome Taxes - Federal (409.1))62-263 (16777 837\2 975 069
16 - Other {409.1)262-263
17 Provision for Deferred lncome Taxes (410.1)234.272-277 42.055.1 95 18.662.907
18 (Less) Provision for Defened lncrme Taxes-Cr- G1'1.1\234 272-277
19 lnvestment Tax Credit Adiustment - Net (41 1.4)266 n77.062\(77.379\
?o (Less) Gains from Disoosition of Utilitv Plant (411.6)
21
22 (Less) Gains from Disposition of Allowances (4'l I .8)
23 Losses from Disposition of Allowances (41 'l .9)
24 Accretion Exoense (41 1.10)
25 TOTAL Utilitv Ooeratino Exoenses lTotal of line 4 throuoh 24)354.224.249 376 047.452
26 Net Utilitv ODeratino lncome fTotal line 2 less 25)58.314.695 62 815 s41
IDAHO STATE ELECTRIC ANNUAL REPORT (lC 61.405)E.1D.114-115
Name of Respondent
Avista Corporation x
This Report is:
An Original
I n Resubmission
Date of Report
mm/dd/ywy
3131t2017
Year / Period of Report
End of 2016 I Q4
STATEMENT OF UTILITY OPERATING INCOME - IDAHO
lnstructions
or in a separate schedule.
3. Explaininafootnoteifthepreviousyear'sfiguresaredifferentfromthosereportedinpriorreports
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY Line
No.Current Year
(e)
Prior Year
(0
Current Year
(q)
Prior Year
(h)
Cunent Year
(i)
Prior Year
o
1
327.785,819 331 ,496,092 94 753 '.t25 107 366 901 2
175.575,735 195,428,588 67.059.10'l 85.666.721 4
17 939 683 16.713j24 3.589.419 3.003.517 q
35.446 852 33.285.897 6.453.1 17 5.882.474 b
7
5.493.620 4.756.344 1.319.431 1.050.650 8
67.304 67.304 (1 98.1 33)9
10
11
33.1 96 (875.823)168.1 36 (1 .029.610)12
(1.069.637)(6.279.256)(672 542\13
14.563.595 14,785,601 2 642 534 2 703.866 14
(15.820.01 3)3,447,734 (957 424\(472.665\15
'16
37.444.693 15,094,760 4.610.502 3.568.147 17
,,1 8
(1 69.388)(67.203)(7.674\( 1 0.1 76)19
20
21
22
23
24
269.505.640 276.357,070 84,7'18,609 99,690,382 25
58.280.179 55.139.022 '10 034 516 7 676 519 26
IDAHO STATE ELECTRIC ANNUAL REPORT (lc 61.405)E.lD.'114-1 15
Name of Respondent
Avista Corporation
This Report is:EE An Original
A Resubmission
Date of Report
mm/dd/yyyy
3t31t2017
Year / Period of Report
End of 2016 I Q4
SUMMARY OF UTILITY PLANT AND ACCUi,IULATED PROVISIONS FOR DEPRECIATION, A]YIORTIZATION AND DEPLETION - IDAHO
lnstructions
'l . 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 in 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 Utilitv Plant
2 ln Service
J Plant in Service (Classified)1.668.908.657 1.304.S63.369
4 ProDertv Under Caoital Leases 166.781 91 .823
5 Plant Purchased or Sold
6 Comoleted Construction not Classified
7 Exoerimental Plant Unclassified
8 Total fiotal lines 3 throuoh 7)1.66S.07s.438 '1 .305.055.1 92
o Leased to Others
10 Held for Future Use 352.937 162.352
11 Construction Work in Prooress 41.415.218 26.776.O14
12 Acouisition Adiustments
13 Total utilitv Plant (Total lines 8 throuoh 12)1 710 843 593 1 331 993 558
14 Accumulated Provision for Depreciation, Amortization, and Deoletion 542.567 602 469 712 345
'15 Net LJtilitv Plant (Line 13less line 14)1 124275991 462241 173
16 Detail of Accumulaled Provision for Deorecialion. Amortization. and Deoletion
17 ln Service
18 Deoreciation 564.438.471 465.274.982
19 Amortization and Deoletion of Producino Natural Gas Lands / Land Riohts
20 Amortization of Underoround Storaoe Lands / Land Riohts
21 Amortization of Other Utilitv Plant 18.129.131 4.437.403
22 Total (Total lines 18 throuqh 21)582.567,602 469.712.385
23 Leased to Others
24 Deoreciation
25 Amortization and Deoletion
26 Total Leased to Others
27 Held for Future Use
28 Deoreciation
29 Amortization
30 Total Held for Future Use
31 Abandonment of Leases (Natural Gas)
32 Amortization of Plant Acquisition Adiustment
33 Total Accumulated Provision Clotal lines 22,26,30,31 ,321 582 547 602 469 712 385
(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 ELECTRTC ANNUAL REPORT (tC 61.405)E.tD.200-201
Name of Respondent
Avista Corporation x
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/ywy
3t3112017
Year / Period of Report
End of 2C16 I A4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION.IDAHO
lnstructions
and in column (h) common funclion.
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)
(s)
Common
(h)
Line
No.
1
224,078.244 13S.867.044 3
74,958 4
5
6
7
224.1s3.202 139.867.044 8
I
190.585 10
724.402 13.914,802 11
12
225.068.1 89 153 781 846 13
75,993.123 36 862 094 14
149,075.066 116.919 752 15
16
17
75 678 555 23.484.934 18
19
20
314.568 '13.377.160 21
75.953.123 36,862.094 22
23
?4
25
26
27
2A
29
30
31
32
75.993.123 36,862,094 JJ
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61405)E.tD.200-201
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/Ww
3t31t2017
Year / Period of Report
End of 201O lA4
ELECTRIC PLANT lN SERVICE - IDAHO (Account 101.1O2.103 and 106)
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. lnadditiontoAccount'101 ,ElectricPlantinService(Classified),thispageandthenextincludeAccountl02,ElectricPlantPurchasedorSold;
Account 103, Experimental Elec{ric Plant Unclassified; and Account '1 06, 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 adjustments of plant accounts to indicate the negative effect of such amounts.
6.ClassifyAccountl06accordingtoprescribedaccounts,onanestimatedbasisifnecessary,andincludetheentriesincolumn(c). Alsotobeincluded
in column (c) are entries for reversals of tentative distributions of prior year in column (b). Likewise, if the respondent has a signiflcant 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 l.INTANGIBLE PLANT
2 301 Oroanization
3 302 Franchises and Consents '15, 1 39,7'16
4 303 Miscellaneous lntanqible Plant 4,522,813 257 139
5 TOTAL lntanoible Plant fTotal of lines 2 3 and 4)19 662 529 257 139
6 2. PRODUCTION PLANT
7 A- Steam Produclion PlantI310 Land and Land Riohts 1.225.818 n.214.122\
I 31 1 Struclures and lmorovements 45.129.795 533.226
10 312 Boiler Plant Eouioment 59.741 .654 1.755.692
11 313 Enoines and Enoine-Driven Generators 2.327
12 314 TurbooeneratorUnits 18.712.464 443.815
13 315 Accessorv Electric Eouioment 9.287.700 143
14 316 Miscellaneous Power Plant Eouioment 197.O44
15 317 Asset Retirement Costs for Steam Produclion (237 544\
16 TOTAL Steam Production Plant (Total of lines 8 throuoh 15,|1 39 986 759 1 478214
17 B. Nuclear Production Plant
18 320 Land and Land Riohts
19 321 Structures and lmorovements
20 322 Reactor Plant Eouioment
21 323 Turboqenerator Units
22 324 Accessorv Electric Equioment
23 325 Miscellaneous Power Plant Eoulpment
24 326 Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Total of lines 18 throuqh 24)
26 C. Hvdraulic Production Plant
27 330 Land and Land Riohts 20.600.228 1.755.624
28 331 Structures and lmorovements 21.209.103 2.522.4A4
29 332 Reservoirs. Dams. and Waterwavs 52.874.590 10.o92.246
30 333 Water Wheels. Turbines. and Generators 57.682.760 '15.736.189
31 334 14.636.180 'l .383.614
32 335 Miscellaneous Power Plant Eouioment 3.274.225 173.350
33 336 Roads, Railroads, and Bridqes 921.580 408.763
34 337 Asset Retirement Costs for Hvdraulic Production
35 TOTAL Hydraulic Production Plant (Total of lines 27 throuqh 34)17'1 ,198,666 32.O72.274
36 D. Other Production Plant
37 340 Land and Land Riohts 311 106
38 341 Structures and lmorovements 5 771 .478 90 967
39 342 Fuel Holders. Products. and Accessories 7 347.544 (49 128\
40 343 Prime Movers 8.217.685
41 344 Generators 71.569.943 8.873.400
42 345 Accessorv Electric Eouioment 7.142.335 1.S78
43 346 Miscellaneous Power Plant Eouioment 610.187 (44.518)
44 347 Asset Retirement Costs for Other Production
45 Plant lines 37 th 100.970.722 8.872.699
46 TOTAL Production Plant (Total of lines 16. 25, 35, and 45)412.156.147 42.423.187
(1)Asmall portionoftheCompany'selectricdistributionplantislocatedinMontana. Forjurisdictional reportingpurposes,thoseamountsare
included as ldaho plant.
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61405)E tD 204-205
Name of Respondent
Avista Corporation
This Report is:
I nn originat
A Resubmission
Date of Report
mm/dd/yyyy
3t31t2017
Year / Period of Report
End of 20'16 lQ4
ELECTRIC PLANT lN SERVICE - IDAHO (Account 1O1,1O2,103 and 106)
lnstructions
thesetentativeclassificationsincolumns(c) and(d),includingthereversalsoftheprioryear'stentativeaccountdistributionsoftheseamounts. 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.
T.Showincolumn(f)reclassificationsortransferswithinutilityplantaccounts. lncludealsoincolumn(f) theadditionsorreductionsofprimaryaccount
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. ForeachaccountcomprisingthereportedbalanceandchangesinAccountl02,statethepropertypurchasedorsold,nameofvendororpurchase,and
dateoftransaction. lfproposedjournal entrieshavebeenfiledasrequiredbytheUniformSystemofAccounts,givealsothedateofsuchfiling.
Retirements
(d)
Adjustments
(e)
Transfers
(f)
Balance
End ofYear
(s)
Line
No.
1
2
(44.049)15.095.667 J
12.824 (36.031)4.731.097 4
12.824 (80.080)19.826.764 E
6
7
'133 1.2',1j.544 I 226 107 I
22.303 't96.742 45.837.460 I
304,553 68.182 61 .260.S75 10
(7\2.320 11
19 472 279.124 19.415.931 12
330 '126.309 9.413.822 't3
10.81 5 66.008 6.1 35.238 14
46.124 283.708 15
403.730 2.230.610 143.291 .853 16
17
18
19
20
21
22
23
24
25
26
(1 .21 3.390)21.142.466 27
394.468 2.773.832 26.'t 10.951 28
738.699 r06.760)61.521.377 29
7.549.744 8,530,402 74,399,607 30
'1 .1 36.256 4,980,51 3 '19,864,051 31
228.304 940,630 4 159 901 3?
(277 A99\1 052 444 33
34
10.o47.471 15.O27.328 208.250.797 35
36
(905)310.201 37
1.374 (52.1't7\5,809,354 38
28.363 7,326,823 39
(23 g10l a 193 775 40
4.937.561 /622 868)74 482 914 41
177.458 96.234 7.063.08S 42
27.546 593.215 43
44
5 116.393 (547.657\104.179.371 45
15.567.594 16.710.281 455.722.021 46
|DAHO STATE ELECTRTC ANNUAL REPORT (lC 61{05}E.lD.204-205
Name of Respondent
Avista Corporation x
This Report is:
An Original
A Resubmission
Date of Report
mm/ddr!yyy
3t31t2l',t7
Year / Period of Report
End of 2016 I Q4
ELECTRIC PLANT IN SERVICE - IDAHO 1 103 and
Line Balance
Beginning of Year
(b)
No.Account Additions
(c)
47 3. TRANSMISSION PLANT
48 350 Land and Land Riohls 7.541.38'l ''t . 't 36.1 78
4g 352 Structures and lmorovements 7.058.970 1.044.205
50 353 Station Eouioment 83.532.806 4.568.373
51 354 Towers and Fixtures 5.902.207 365
52 355 Poles and Fixtures 1 8,908.774
53 356 Overhead Conductors and Devices 1 3,060.866
54 357 UnderoroundConduit 1.026,663
55 358 Underoround Conductors and Devices 805,038 687
56 359 Roads and Trails 675,987 34 492
57 359.1 Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Total of lines 48 throuoh 57)219 999 531 18.753.940
59 4 DISTRIBUTION PLANT
60 360 Lanrl and Land Riohts 3.608.407 370.1 30
61 361 Slructures and lmorovemenls 6.49s.52'1 8.970
62 352 Station Eouioment 44.3',14.432 1.O27.444
63 363 Storaoe Batterv Eouioment
64 364 Poles. Towers. and Fixtures 123.542.375 5.805.863
65 365 Overhead Conductors and Devices 79.974.353 5.956.260
66 366 Underoround Conduit 35.928.995 1.426.854
67 367 Underoround Conductors and Devices 61 .446,1 96 3,818,437
68 368 Line Transformers 74,406,'t 99 2,018,404
69 369 Services 52.278.812 2 449 767
70 370 Meters 22,435.384 308 827
71 371 lnstallations on Customer Premises
72 372 I eased Pronertv on Crrslomer Premises
73 373 Street Liohtino and Sional Svstems 16.606.239 2.269.372
74 374 Asset Retirement Cosls for Distribution Plant
75 TOTAL Distribution Plant (Total of lines 60 throuoh 74)521 .036.913 25.460.328
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 380 Land and Land Riohts
78 381 Structures and lmorovements
79 382 Computer Hardware
80 383 Comouler Software
81 384 CommunicitionEouiDmenl
a2 385 Miscellaneous Reoional Transmission and [\rarket ODeration Plant
83 386 Asset Retirement Costs for Reoional Transmission and Ooeration Plant
84 TOTAL Transmission and Market Ooeration Planl (Total lines 77 throuoh 83)
85 6. GENERAL PLANT
86 389 Land and Land Riohts 369.558
87 390 Structures and lmorovements 3,382.520 520,200
88 391 Office 1,868.331 60,222
89 392 TransoortationEouioment 9.678,386 2.433,490
90 393 Stores EouiDment 134,602
91 394 Tools Shon and Garaoe Forrinment 1 081 581 4A 416
92 395 [aboralorv Fouioment 140 024 33 815
93 396 Power ODeraled Eouinment 12 345.249 116.754
94 397 Communication Eouinmenl 19.167.694 1 .210.3S3
95 398 MiscellaneousEouioment 27.419 19.846
96 SUBTOTAL (Total of lines 86 throuoh 95)48.235.368 4.443.136
97 399 Other Tanoible ProDertv
98 399.1 Asset Retirement Costs for General Plant
s9 TOTAL General Plant (Total of lines 96. 97 and 98)48.235.368 4.443.136
100 TOTAL (Accounts 101 and 106)1.221 .090.488 91.337.730
101 102 Electric Plant Purchased
102 102 (Less) Electric Plant Sold
103 103 Exoerimental PlantUnclassified
104 TOTAL Electric Plant in Service (Total of lines 100 throuqh 103)1.22'1 .090,488 91 337 730
IDAHO STATE ELECTRTC ANNUAL REPORT (tC 61.{05)E.to.206,-207
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
3t3',v2017
Year/ Period of Report
End of 2016 I Q4
ELECTRIC PLANT IN SERVICE - IDAHO 101 103 and 1
Balance
End ofYear
(s)
Line
Retirements Adjustments Transfers No.
(e)(f)
47
(45.979)8.631.580 48
77.480 254.188 8.279.883 49
2.680.'t 09 2.109.446 87.530.5'16 50
(16.940 5.885.632 5't
432.828 (4.033.448)72.638.847 52
71.448 (1 .156.545)47.093.003 53
e.9871 1.023.67(54
(2.7941 802,931 55
8,6'1 1 719 090 56
57
3,261.865 (2.886.448)232 605 lsB 58
59
3.978.537 60
96 292 6.408.199 51
779.377 23.900 44.586.399 a2
63
211.177 8.040 129.145.101 64
27.508 3.97'1 8s.907.076 65
30.505 "t .518 10326 37.337.288 66
109.314 1 Q4.631\65.1 30,68 67
49,355 2.194 76.377,442 68
16.226 1,540 54 713 893 69
22 744 211 70
7'l
72
235.351 91 1 18.641.171 73
43.404 43.404 74
1.s98.s09 71.274 544.970.006 75
76
77
78
79
80
81
a?
83
84
85
(53)36S.505 86
10 014 (8.767)3.883.939 87
98.348 (13.340)1.816.865 88
371 .S33 (24.389)23.799 11.739.353 89
(863)133.739 90
31.078 87 1.186.611 91
24.696 s2.784 241.931 92
249 s11 (18.455)(153 440)12 080 596 93
1 69 630 294.997 169 535)20.433.919 94
2 299 (181)44.745 95
957.509 409.424 (1 99.1 76)51.931.243 96
97
98
957.509 409,424 (1 99.1 76)51 99
21.398.301 '14.224.451 (199.176)1 .305.055.192 100
101
102
103
21 398 301 14.224.451 (1SS't76)1 .305.055 192 10,4
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61405)E.!D.206-207
Name of Respondent
Avista Corporation
This Report is:
x An OriginalEA Resubmission
Date of Report
mm/dd/yyw
3t31t2017
Year / Period of Report
End of 2016 I 04
ELECTRIC OPERATING REVENUES . IOAHO
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 (fl anO 1911 on the basis of meters, in addition to the number of flat rate accounts; except that where separate
meterreadingsareaddedforbillingpurposes,onecustomershouldbecountedforeachgroupofmetersadded. Theaveragenumberofcustomers
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 at the bottom of the page, or in a separate schedule.
Line
No Account
(a)
ELECTRIC OPERATING REVENUE
Current Year
(b)
Prior Year
(c)
I Sales of Electricitv
2 44O Residential Seles 109 104 0S4 108 819 717
3 442 Commercial and lndustrial Sales (3)
4 Small (or Commercial)87.674i15 s0.052 492
5 Laroe (or lndustriall 44.158.145 48.544.161
6 444 Public Street and Hiohwav Liohtino 2.507.387 2.386.81S
7 445 Other Sales to Public AuthoritiesI446 Sales to Railroads and Railwavs
I 448 lnterdeoartmental Sales 247.973 262.414
10 TOTAL Sales to Ultimate Customers (1)243.695.714 250.075.603
11 447 Sales for Resale 40.718.232 45.82'1 .008
12 TOTAL Sales of Electricitv 284.4'.t3.946 295.896.611
13 449.1 (Less) Provision for Rate Refunds 71 1,306 (2.198.387)
't4 TOTAL Revenues Net of Provision for Refunds 285,125,252 293,698.224
15 Other Ooeratino Revenues
16 450 ForfeitedDiscounts
17 451 Miscellaneous Service Revenues 170.474 98.003
18 453 Sales of Water and Water Power 122.229 't40.001
19 454 Rent from Electric Prooertv 973.671 1.024.892
20 455 lnterdeoartmental Rents
21 456 Other Electric Revenues (4)37.070.455 31 ,604,020
22 456.1 Revenues from Transmission of Electricitv for Others 4.323.734 4,930,952
23 457.1 Reqional Control Service Revenues
24 457.2 Miscellaneous Revenues
25
26 TOTAL Other Ooeralino Revenues 42.660.s67 37.797.868
27 TOTAL Electric Ooeratino Revenues 327.785.8',t9 33't.4S6.092
IDAHO STATE ELECTRTC ANNUAL REPORT (rC 61.405)E rD.300-301
Name of Respondent
Avista Corporation
This Report is:
lx I nn originat
A Resubmission
Date of Report
mm/dd/yyyy
3t31t2017
Year / Period of Report
End of 2016 I Q4
ELECTRIC OPERATING REVENUES - IDAHO
lnstructions
4. Discloseamountsof $250,000orgreaterinafootnoteatthebottomof thepageorinaseparatescheduleforaccounts45l,456, and457.2.
5. Commercial and lndustrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or lndustrial)
regularlyusedbytherespondentifsuchbasisofclassificationisnotgenerallygreaterthanl000Kwofdemand. (SeeAccount442oflheUniform
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. lnclude unmetered sales. Provide details of such Sales in a footnote in the available space atthe bottom of this page or in a separate schedule.
MEGAWATT HOURS SOLD AVG. NO. OF CUSTOMERS PER MONTH Line
No.Current Year
(d)
Previous Year
(e)
Current Year
(D
Previous Year
(s)
1
1.143.246 1 .'146.891 110.667 110.297 2
3
1.OO4.O27 1.012.144 17.278 17.267 4
772.244 822,348 443 449 5
8.724 8.586 149 151 h
7
8
2.767 2.905 53 49 I
Q\2,931.008 2.992.874 128,590 128.213 10
1.031.775 1 130 S70 11
3 962 783 4123.A44 1 28 590 128.213 12
13
3 962 783 4123.844 I 28 590 124 213 14
(1) lncludes $1,232,395 of unbilled revenues
(2) lncludes 13,329 MWH relating to unbilled revenues
(3) Segregation of Commercial and lndustrial made on basis of utilization of energy and not on size of account.
(4)lncludes $(50.78'1) associated with a special contract for wheeling over the distribution system on file with the IPUC, recorded
in sub-account 456700.
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61405)E.1D.300-301
Name of Respondent
Avista Corporation x
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
3t31t2017
Year/ Period of Report
End of 2016 / Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
lnstructions
'1 . For each prescribed account below, report operation and mainlenance expenses as allocated by lhe Results of Operations model to the state of
ldaho.
2. lftheamountforpreviousyearisnotderivedfrompreviouslyreportedfigures,explaininafootnote.
Line
No.Accounl
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
,|1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Ooeration
4 500 Ooeration Suoervision and Enoineerino 109.211 94.755
5 501 Fuel 10.466,908 10.584,045
6 502 Steam Expenses 1.529.281 1.786,948
7 503 Steam from Other Sources
8 504 /Less) Sleam Transferred-Cr
s 505 Electric Exoenses 411 608 422 375
10 506 l\riscellaneous Steam Power Exoenses 1123141 1 .019.781
11 507 Rents 14j82 11 .571
12 509 Allowances
13 TOTAL Ooeration fTotal of lines 4 throuoh 12)13.654.371 1 3.919.475
14 Maintenance
'15 5'10 Maintenance SuDervision and Enoineerino 199.730 210.742
'16 5"1 'l Maintenance of Structures 241.646 260.644
17 5'12 Maintenance of Boiler Plant 2.469.806 '1 .636.249
18 513 Maintenance of Electric Plant 833.293 206.568
19 514 Maintenance of Miscellaneous Steam Plant 585.269 328.227
20 TOTAL Maintenance (Total of Lines 15 throuqh 19)4.329.744 2.642.430
21 TOTAL Steam Power Generation Expenses (Total lines 13 & 20)17 984 115 16 561 905
22 B. Nuclear Power Generation
23 Ooeration
24 517 Ooeration Suoervision and Enoineerino
25 518 Fuel
26 5'19 Coolants and Water
27 520 Steam Expenses
2A 521 Steam from Other Sources
29 522 (Less) Sieam Transferrerl-Cr
30 523 Electric Expenses
31 524 Miscellaneous Nuclear Power ExDenses
32 525 Rents
33 TOTAL Ooeration (Total of lines 24 throuoh 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 Electric Plant
39 532 Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Total of lines 35 throuqh 39)
41 TOTAL Nuclear Power Generalion Exoenses (Total lines 33 & 40)
42 C. Hvdraulic Power Generalion
43 ODeration
44 535 Ooeration Suoervision and Enoineerino 988.529 724.398
45 536 Water for Power 370.467 447.'.|19
46 537 Hvdraulic Exoenses 2.482.584 2.516.343
47 538 Electric Exoenses 2.448.171 2.254.625
48 539 laneous tc 311 .663 30'1 .256
49 540 Rents 2.266.596 2.490.828
50 TOTAL Ooeration (Total of lines 44 throuoh 49)0 8.734.569
51 Maintenance
52 541 Mainlenance Supervision and Enoineerino 309.902 555.728
53 542 Maintenance of Structures 't76.419 112.307
54 543 Maintenance of Reservoirs, Dams. and Watenravs 813 040 472.853
55 544 Maintenance of Electric Plant 1 0,44 674 915 368
56 545 lvlaintenance of lt/liscellaneous Hvdraulic Plant 248 068 239 345
57 TOTAL Maintenance (Total of lines 53 throuoh 57)2 596 103 2 255 AOl
58 TOTAL Hvdraulic Power Generation Exoenses fTotal of lines 50 & 58)11.464.1'.t3 1 1 .030.1 70
59
IDAHO STATE ELECTRTC ANNUAL REPORT (C 61-405)E.tD.320
Name of Respondent
Avista Corporation
This Report is:
x An Original
A Resubmission
Date of Report
mm/ddrlyyy
3t31t2017
Year / Period of Report
End of 2016 I Q4
ELECTR]C 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. lftheamountforpreviousyearisnotderivedfrompreviouslyreportedflgures,explaininafootnote.
Line
No Account
(a)
Amount for
Cunent Year
(b)
Amount for
Previous Year
(c)
60 D. Other Power Generation
61 Operation
62 546 and 417 635 405 557
63 547 Fuel 26 456 092 31 543 857
64 548 GenerationExDenses 542.982 6S3.007
65 549 Miscellaneous Other Power Generation Expenses 204.211 158.583
66 550 Rents /"t 1.539)(11.450'l
67 TOTAL Ooeration (T6tal of lines 62 throuoh 66)27.609.381 32.789.554
68 Maintenance
69 551 Maintenance Suoervision and Enoineeilno 2't 6.368 214.877
70 552 Maintenance of Structures 43.587 37.938
71 553 Maintenanee of Generatino and Electric Plant 1.095.933 796.460
72 554 Maintenance of Miscellaneous Other Power Generation Plant 92.580 155.838
73 TOTAL Maintenance (Total of lines 69 throuqh 72)'1 .448.468 1.205.113
74 TOTAL Other Power Generation ExDenses 29,057,849 33,994,667
75 Other Power
76 555 Purchased Power 50 454 5C9 59.352 868
77 556 Svstem Control and Load Disoatchinq 257.139 360.600
7A 557 Other Expenses 27.662.552 33.573.420
79 TOTAI Other Power Sunnlv Fxnenses fTotal of lines 76 throuoh 78)78.374.290 93.286.888
80 TOTAL Power Prorftr.lion Fxoenses fTotal of lines 2'1.41. 59.74. &79\136.880.367 154.873.630
81 2. TRANSMISSION EXPENSES
82 ODeralion
83 560 Ooeration Suoervision and Enoineerino 870.482 728.513
84 561 Load Disoatchino 971.109 877.898
85 561 .'l Load DisDatch-Reliabilitv
86 561 .2 Load and
87 561.3 Load
88 561.4 Schedulino. Svstem Control and Dispatch Services
8C and
s0 561 -6 Transmission Service Studies
91 561.7 Generation lnterconnection Studies
92 561.8 Reliabilitv Plennind end Standards Develooment Services
s3 562 Station Exnenses 149.707 1 83.1 56
94 563 Overhead Lines Eroenses 175.849 157.616
95 564 Underoround Lines ExDenses
96 565 Transmission of Electricitv bv Others 5.912.041 5.976.906
97 566 Miscellaneous Transmission Exoenses 743.324
98 567 Rents 65,354 52.792
99 TOTAL Ooeration (Total of lines 83 throuoh 98)8,977,980 8.720.205
100 Maintenance
'101 568 Maintenance SuDervision and Enqineerinq 347.479 277.43'l
102 569 lilaintenancn of Stnlclures 228.530 256.903
103 559.'l Mainlenance of ComDuler Hardware
104 569.2 Maintenance of Comouter Software
'105 569.3 Maintenance of Communication Eouioment
'106 569.4 Maintenance of Miscellaneous Reoional Transmission Plant
107 570 Maintenance of Station Eouioment 456 837 461 223
108 571 Maintenance of Overhead Lines 61't 730 399 678
109 572 Maintenance of Underoround Lines 568 5 397
110 573 Maintenance of Miscellaneous Transmission Plant 28.589 31 .094
't 11 TOTAL Maintenance (Total of lines 101 through 110)1.673.733 '1 .431.926
112 TOTAL Transmission ExDenses (Total of lines 99 and 111)10.651 .713 1 0.1 52.13't
IDAHO STATE ELECTRTC ANNUAL REPORT (rC 6140s)E.rD.321
Name of Respondent
Avista Corporation x
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
3t31t2017
Year / Period of Report
End of 2016 / 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
Cunent Year
(b)
Amount for
Previous Year
(c)
1't3 3. REGIONAL MARKET EXPENSES
114 Operation
115 575.1 ODeration SuDervision
'l 16 575.2 Dav-Ahead and Real-Time Market Facilitation
117 575.3 Transmission Riohts Market Facilitation
118 575.4 Market Facilitation
119 575.5 Market Facilitation
't20 575.6 Market Monitorino and Comoliance
121 Services
122 575.8 Rents
'123 Total Ooeration (Total lines 115 throuoh 122)
124 Maintenance
125 576.1 Maintenance of Structures and lmDrovements
126 576.2 Maintenance of Computer Hardware
127 576.3 Maintenance of Computer Software
128 576.4 Maintenance of Communication Eauipment
129 576-5 Maintenance of Miscellaneous Markel Ooeretion Plant
'130 Total Maintenance (Total lines '125 throuoh 129)
13'1 TOTAL Reoional Market ExDenses (Total lines'123 & 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 and 1.290.878 't.263.379
135 581 Load Disoatchinq
136 582 Station Expenses 324.1 95 347.O82
137 583 Overhead Line Expenses 807.1 61 696.866
138 584 Underoround Line Exoenses 444 264 474.O08
139 585 Street Liohtino and Sional Svstem Exoenses 7 508 5,009
140 586 Meter Exoenses 400.806 347 302
141 587 Customer lnstallations Exoenses 317.997 270 370
142 588 MiscellaneousExDenses 2.840.7A4 2 694 799
143 589 Rents 117.34s 86.550
144 TOTAL Operation (Total of lines 1 34 throuoh 143)6.590.942 6.225.365
145 Maintenance
146 590 Maintenance Supervision and Enoineerinq 455.978 588.684
147 591 Maintenance of Structures 174.859 156.407
148 592 Maintenance of Station Eouioment 252.967 265.131
149 593 Maintenance ofOverhead Lines 2 647 425 3.647.993
150 594 Maintenance of Underoround Lines 215 906 264.047
151 595 Maintenance of Line Transformers 62 638 184,851
152 596 Maintenance of Street Liohtino and Sional Svstems 55.429 234 368
153 597 Maintenance of Meters 4.222 5 380
154 598 Maintenance of Miscellaneous Distribution Plant 267.958 268 650
155 TOTAL Maintenance (Total lines'146 throuoh 154)4.181.782 5.615.51 1
156 TOTAL Distribution Expenses (Total of lines 144 and 1 55)10.772.724 11.840.876
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 90'1 Supervision 116.284 122.109
't60 902 Meter Readinq Expenses 7 363.062
't61 903 Customer Records and Collection Exnenses 2 3.038.348
162 904 UncollectableAccounts 1.088,'148 1.042.462
163 905 Miscellaneous Customer Accounts Exoenses 84 130 90.370
16,4 TOTAL Customer Accounts Exoenses (Total of line 159 throuoh 163)4,968,358 4.656.351
|DAHO STATE ELECTRTC ANNUAL REPORT (tC 61.{0s)E.!D.322
Name of Respondent
Avista Corporation x
This Report is
An Original
A Resubmission
Date of Report
mm/dd/yyyy
3t31t2017
Year / Period of Report
End of 2016 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)
165 6. CUSTOMER SFRVICE AND INFORMATIONAL EXPENSES
166 Ooeration
167 907 Suoervision
't68 908 CustomerAssislance Exoenses 6.424.374 6,676.012
169 909 lnformational and lnstructional Exoenses 318.1 91 297.230
170 910 Miscellaneous Customer Service and lnformational ExDenses 81 11 36,716
171 TOTAL Customer Service and lnformational Exoenses ffotal lines 167 throuoh '170)6,823,678 7,009,958
172 7. SALES EXPENSES
173 rDeration
174 91 1
175 9'12 Demonstratino and Sellino Exoenses
't76 913 Advertisino Exoenses
177 916 Miscellaneous Sales Expenses
't78 TOTAL Sales Fxoenses (Totel of lines 174 throuoh 177)
'179 8 ADITINISTRATIVF AND GFNERAL EXPENSES
180 ODeration
't 8'l 920 Administrative and General Salaries 10,653.259 10.243.395
182 921 Office Suonlies and ExDenses 1.347.134 't.320.114
183 922 (Less) Administralive ExDenses Transfened-Credit (39.817)(37.866)
't84 923 Outside Services Emoloved 2,407.406 3,104,929
185 924 ProDertv lnsurance 404,665 419 945
186 925 lniuries and Damaoes I 067 408 1.103.O21
187 926 Emolovee Pensions and Benefits 423.730 509.749
188 927 FranchiseReouirements 4.606 3.927
189 928 RequlatorvCommission Expenses 1.870.264 1.928.587
190 929 (Less) Duplicate Charqes-Cr.
191 930 1 General Advertisino Fxoenses
192 930 2 lrliscellaneorrs General Fxnenses 1.228.934 1.164.071
193 931 Rents 341 .1 36 326.35'1
194 TOTAL Ooeration /Tolal of lines 181 throuoh 193)19.708.725 20.086.223
19s Maintenance
196 935 Maintenance of General Plant 3.709.853 3.522,543
197 TOTAL Administrative and General Expenses (Total of lines 194 and 196)23.4',t8.578 23.608.766
'198 TOTAL Elec Op and Maint Expns (Total lines 80, 112, 131 , 1 56, 164, 171 , 178, 197\193,515,418 212.141.712
toAHo STATE ELECTRTC ANNUAL REPORT (tC 61405)E.1D.323
Name of Respondent
Avista Corporation
This Report is:
lFl en orisinat
A Resubmission
Date of Report
mm/dd/yyyy
3t31t2017
Year / Period of Report
End of 2016 / 04
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 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 construclion. 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 (0 and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on struclures the cost of which is
reportedforthelinedesignated; conversely,showincolumn(g) thepolemilesoflineonstructuresthecostofwhichisreportedforanotherline. 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
60 cvcle. 3 ohase
Type of
Supporting
Structure
(e)
LENGTH (Pole Miles)
For undeQround lines. reDod circuit miles Number
of
Circuits
(h)
On Structure
of Line Designated
(D
On Structures
of Another Line
(s)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
1 Grouo Sum - 11skv 1 15.00 1 15.00 606.00
2
3 Beacon Cabinet Goroe Planl 230.00 230.00 Steel Pole 9.00 1
4 Beacon Cabinet Goroe Plant 230.00 230.00 Steel Pole 5.00 2
5 Beacnn Cabinet Goroe Plant 230.00 230.00 H TvDe 53.00 ,|
6 Divide Creek Lolo Sub 230.00 230.00 Steel Tower 1
7 Divide Creek Lolo Sub 230.00 230.00 H TvDe 43 00 ,|
I Noxon Plant Pine Creek Sub 230.00 230 00 H Tvoe 100 I
I Noxon Plant Pine Creek Sub 230.00 230 00 H Tvoe 14 00 1
10 Noxon Planl Pine Creek Sub 230.00 230.00 Steel Pole 15.00 1
11 Cabinet Goroe Plant Noxon 230.00 230.00 H Tvoe 2.00 1
12 Benewah Sw. Station Pine Creek Sub 230.00 230.00 Steel Tower 1
13 Benewah Sw. Station Pine Creek Sub 230.00 230.00 H Tvoe 43.00 1
14 Beacon Sub Lolo Sub 230.00 230.00 Steel Pole 12.00 1
15 Beacon Sub Lolo Sub 230.00 230.00 H TvDe 69 00 ,|
'16 North Lewiston Walle W2lle 230 00 230 00 H Tvne 8.00 ,|
17 North Lewiston Shawnee 230 00 230 00 H Tvne 1.00 1
18 Hatwai N I ewiston Sub 230 00 230 00 H Tvoe 7.OO 1
1g
20
21
22
23
24
25
26
27
2A
29
30
31
32
33
34
35
36
IDAHO STATE ELECTRIC ANNUAL REPORT 0C 61-{05)E.!D.422423
Name of Respondent
Avista Corporation
This Report is:EE An Original
A Resubmission
Date of Report
mm/dd/yyyy
3t31t2017
Year / Period of Report
End of 2016 / Q4
TRANSMISSION LINE STATISTICS - IDAHO
lnstructions
schedule, explain the basis of such occupancy and state whether these expenses with respect to such structures are included in the expenses reported
for the line designated.
7. Do not report the same transmission line structure twice. Reporl 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 struclure 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
nameoflessor,dateandtermsoflease,andamountofrentforyear. Foranytransmissionlineotherthanaleasedline,orportionthereof,forwhichthe
respondent is not the sole owner but which the respondent operates or shares in the operation of, fumish a succinct statement explaining the anangement
and giving details of such matters as percent ownership by respondent in the line, name of c-owner, basis of sharing expenses of the line, and and how
expenses borne by the respondent are accounts 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 O through (l) on the book cost at end of year associated with the physical lines reported.
Size of
Conduclor
and Material
(D
COST OF LINE
lnclu& in column (il land. land riohts, and cleaing ight-of-way
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Line
No.
Land
0)
Construclion
and Other Costs
(k)
Total Cost
o
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(o)
Total
Expenses
(p)
5.083.708 75.961 ,199 a1 044 907 101 978 61 1 788 713.766 1
2
1 5gO ACSS 3
1 590 ACSS 4
15SO ACSR 1.042.786 26.232.947 27.275.733 8.108 8.108 5
1272McMAL 6
1272M0MAL a6 224 5.359.151 5.445.379 2.485 2.485 7
't s90 Acss I
954 McMAL I
1272 ACSR 692.447 11.277 .590 1',t.970.437 1 103 828 10
954 McMAL 138.010 466.485 604.495 772 772 11
1622 ACSS 12
954 MCMAL 350.325 4 5 139 401 112 009 1 12 009 't3
1 590 ACSS 14
'1272M$\AAL 363.604 18,540,500 18 S04 '104 318 977 1.295 15
1272 M1MAI 25.818 1,672.758 1.698.575 1.343 423 1.766 't6
1272 ACSR 10.015 319,300 329.315 17
1 590 ACSR 113795 2.626.745 2.740.540 292 292 't8
19
20
21
22
24
25
26
27
28
29
30
3'l
32
33
31
35
35
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61405)E.!D.422423
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