2020Annual Report Electric.pdf

THIS FILING IS
Item 1:E An lnitial(Original)
Submission
OR E Resubmission No. _
Form 1 Approved
OMB No.1902-0021
(Expires 1113012022)
Form 1-F Approved
OMB No.1902-0029
(Expires 1113012022)
Form 3-Q Approved
OMB No.1902-O2Os
(Expires 1113012022)
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FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Cl: Quarterly Financia! Report
These reports are mandatory underthe Federal PowerAct, Sections 3, 4(a), 304 and 309, and
18 CFR 141 .'l and 141 .40O. 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 20201Q4
FERC FORM No.1/3-Q (REV.02-04)
AVU-E
IDENTIFICATION
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
Ryan Krasselt
1411 East Mission Avenue, Spokane, WA 99207
2020/Q4
1411 East Mission Avenue, Spokane, WA 99207
01 Exact Legal Name of Respondent
(1) An Original (2) A ResubmissionX
02 Year/Period of Report
End ofAvista Corporation
03 Previous Name and Date of Change (if name changed during year)
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
05 Name of Contact Person 06 Title of Contact Person
07 Address of Contact Person (Street, City, State, Zip Code)
08 Telephone of Contact Person,Including
Area Code
09 This Report Is 10 Date of Report
(Mo, Da, Yr)
01 Name
02 Title
03 Signature 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 Department of the United States any
false, fictitious or fraudulent statements as to any matter within its jurisdiction.
/ /
Ryan Krasselt VP, Controller, Prin. Acctg
[phone] 04/15/2021
Ryan Krasselt
VP, Controller, Prin. Acctg 04/15/2021
ANNUAL CORPORATE OFFICER CERTIFICATION
The undersigned officer certifies that:
I have examined this report and to the best of my knowledge, information, and belief all statements of fact contained in this report are correct statements
of the business affairs of the respondent and the financial statements, and other financial information contained in this report, conform in all material
respects to the Uniform System of Accounts.
FERC FORM No.1/3-Q (REV. 02-04)Page 1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LIST OF SCHEDULES (Electric Utility)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
101General Information 1
N/A102Control Over Respondent 2
103Corporations Controlled by Respondent 3
104Officers 4
105Directors 5
106(a)(b)Information on Formula Rates 6
108-109Important Changes During the Year 7
110-113Comparative Balance Sheet 8
114-117Statement of Income for the Year 9
118-119Statement of Retained Earnings for the Year 10
120-121Statement of Cash Flows 11
122-123Notes to Financial Statements 12
122(a)(b)Statement of Accum Comp Income, Comp Income, and Hedging Activities 13
200-201Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 14
N/A202-203Nuclear Fuel Materials 15
204-207Electric Plant in Service 16
N/A213Electric Plant Leased to Others 17
214Electric Plant Held for Future Use 18
216Construction Work in Progress-Electric 19
219Accumulated Provision for Depreciation of Electric Utility Plant 20
224-225Investment of Subsidiary Companies 21
227Materials and Supplies 22
N/A228(ab)-229(ab)Allowances 23
N/A230Extraordinary Property Losses 24
N/A230Unrecovered Plant and Regulatory Study Costs 25
231Transmission Service and Generation Interconnection Study Costs 26
232Other Regulatory Assets 27
233Miscellaneous Deferred Debits 28
234Accumulated Deferred Income Taxes 29
250-251Capital Stock 30
253Other Paid-in Capital 31
254Capital Stock Expense 32
256-257Long-Term Debt 33
261Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 34
262-263Taxes Accrued, Prepaid and Charged During the Year 35
266-267Accumulated Deferred Investment Tax Credits 36
FERC FORM NO. 1 (ED. 12-96)Page 2
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
269Other Deferred Credits 37
N/A272-273Accumulated Deferred Income Taxes-Accelerated Amortization Property 38
274-275Accumulated Deferred Income Taxes-Other Property 39
276-277Accumulated Deferred Income Taxes-Other 40
278Other Regulatory Liabilities 41
300-301Electric Operating Revenues 42
N/A302Regional Transmission Service Revenues (Account 457.1) 43
304Sales of Electricity by Rate Schedules 44
310-311Sales for Resale 45
320-323Electric Operation and Maintenance Expenses 46
326-327Purchased Power 47
328-330Transmission of Electricity for Others 48
N/A331Transmission of Electricity by ISO/RTOs 49
332Transmission of Electricity by Others 50
335Miscellaneous General Expenses-Electric 51
336-337Depreciation and Amortization of Electric Plant 52
350-351Regulatory Commission Expenses 53
352-353Research, Development and Demonstration Activities 54
354-355Distribution of Salaries and Wages 55
356Common Utility Plant and Expenses 56
397Amounts included in ISO/RTO Settlement Statements 57
398Purchase and Sale of Ancillary Services 58
400Monthly Transmission System Peak Load 59
N/A400aMonthly ISO/RTO Transmission System Peak Load 60
401Electric Energy Account 61
401Monthly Peaks and Output 62
402-403Steam Electric Generating Plant Statistics 63
406-407Hydroelectric Generating Plant Statistics 64
N/A408-409Pumped Storage Generating Plant Statistics 65
410-411Generating Plant Statistics Pages 66
FERC FORM NO. 1 (ED. 12-96)Page 3
LIST OF SCHEDULES (Electric Utility) (continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Title of Schedule Reference
Page No.
Remarks
(c)(b)(a)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
422-423Transmission Line Statistics Pages 67
424-425Transmission Lines Added During the Year 68
426-427Substations 69
429Transactions with Associated (Affiliated) Companies 70
450Footnote Data 71
Stockholders' Reports Check appropriate box:
X Two copies will be submitted
No annual report to stockholders is prepared
FERC FORM NO. 1 (ED. 12-96) Page 4
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
GENERAL INFORMATION
Avista Corporation X
04/15/2021 2020/Q4
State of Washington, Incorporated March 15, 1889
R. Krasselt, Vice President, Controller, and Principal Accounting Officer
1411 E. Mission Avenue
Spokane, WA 99207
1. Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
2. Provide the name of the State under the laws of which respondent is incorporated, and date of incorporation.
If incorporated under a special law, give reference to such law. If not incorporated, state that fact and give the type
of organization and the date organized.
3. If at any time during the year the property of respondent was held by a receiver or trustee, give (a) name of
receiver or trustee, (b) date such receiver or trustee took possession, (c) the authority by which the receivership or
trusteeship was created, and (d) date when possession by receiver or trustee ceased.
4. State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
5. Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1) Yes...Enter the date when such independent accountant was initially engaged:
(2) NoX
Not Applicable
Electric service in the states of Washington, Idaho, and Montana
Natural gas service in the states of Washington, Idaho, and Oregon
FERC FORM No.1 (ED. 12-87) PAGE 101
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CORPORATIONS CONTROLLED BY RESPONDENT
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company Controlled Kind of Business Percent Voting
Stock Owned(c)(b)(a)
Footnote
Ref.(d)
1. Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. If control ceased prior to end of year, give particulars (details) in a footnote.
2. If control was by other means than a direct holding of voting rights, state in a footnote the manner in which control was held, naming
any intermediaries involved.
3. If control was held jointly with one or more other interests, state the fact in a footnote and name the other interests.
Definitions
1. See the Uniform System of Accounts for a definition of control.
2. Direct control is that which is exercised without interposition of an intermediary.
3. Indirect control is that which is exercised by the interposition of an intermediary which exercises direct control.
4. Joint control is that in which neither interest can effectively control or direct action without the consent of the other, as where the
voting control is equally divided between two holders, or each party holds a veto power over the other. Joint control may exist by mutual
agreement or understanding between two or more parties who together have control within the meaning of the definition of control in the
Uniform System of Accounts, regardless of the relative voting rights of each party.
Parent to the Co's Subsidiary 100 1 Avista Capital, Inc.1
Investment in Real Estate 100 2 Avista Development, Inc.2
Investment in Internet Tech.100 3 Avista Edge, Inc.3
Parent of Bay Area Mfg and 100 4 Pentzer Corporation 4
Penture Venture Holdings 5
Holding Company-Inactive 100 6 Pentzer Venture Holdings II, Inc.5
Holding Company 100 7 Bay Area Manufacturing, Inc.6
Affiliated business trust 100 8 Avista Capital II 7
issued pref trust Securities 9
Owns an interest in a venture 100 10 Avista Northwest Resources, LLC 8
fund investment 11
Office & Retail Leasing 100 12 Steam Plant Square, LLC 9
Office & Retail Leasing 100 13 Courtyard Office Center, LLC 10
Restaurant Operations 100 14 Steam Plant Brew Pub, LLC 11
Liquified Natural Gas Operati 100 15 Salix, Inc.12
Parent Co of Alaska Opertions 100 16 Alaska Energy and Resources Company (AERC)13
Utility Operations in Juneau 100 17 Alaska Electric Light and Power Company 14
Inactive mining Co holding 100 18 AJT Mining Properties, Inc.15
Certain Properties 19
Right to Purchase Snetti 100 20 Snettisham Electric Company 16
21
22
23
24
25
26
27
FERC FORM NO. 1 (ED. 12-96) Page 103
Schedule Page: 103 Line No.: 1 Column: d
Parent to the company's subsidiaries.
Schedule Page: 103 Line No.: 2 Column: d
Maintains investment portfolio including real estate.
Schedule Page: 103 Line No.: 3 Column: d
Subsidiary of Avista Capital
Schedule Page: 103 Line No.: 4 Column: d
Subsidiary of Avista Capital
Schedule Page: 103 Line No.: 6 Column: d
Subsidiary of Pentzer Coporation
Schedule Page: 103 Line No.: 7 Column: d
Subsidiary of Pentzer Corporation
Schedule Page: 103 Line No.: 8 Column: d
Subsidiary of Avista Corporation
Schedule Page: 103 Line No.: 10 Column: d
Subsidiary of Avista Capital
Schedule Page: 103 Line No.: 12 Column: d
Subsidiary of Avista Development
Schedule Page: 103 Line No.: 13 Column: d
Subsidiary of Avista Development
Schedule Page: 103 Line No.: 14 Column: d
Subsidiary of Steam Plant Square, LLC
Schedule Page: 103 Line No.: 15 Column: d
Subsidiary of Avista Capital
Schedule Page: 103 Line No.: 16 Column: d
Subsidiary of Avista Corporation
Schedule Page: 103 Line No.: 17 Column: d
Subsidiary of AERC
Schedule Page: 103 Line No.: 18 Column: d
Subsidiary of AERC
Schedule Page: 103 Line No.: 20 Column: d
Subsidiary of AERC
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OFFICERS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Title Name of Officer Salaryfor Year(c)(b)(a)
1. Report below the name, title and salary for each executive officer whose salary is $50,000 or more. An "executive officer" of a
respondent includes its president, secretary, treasurer, and vice president in charge of a principal business unit, division or function
(such as sales, administration or finance), and any other person who performs similar policy making functions.
2. If a change was made during the year in the incumbent of any position, show name and total remuneration of the previous
incumbent, and the date the change in incumbency was made.
President and Chief Executive Officer 737,693D. P. Vermillion 1
2
Executive Vice President, Chief Financial Officer 452,615M. T. Thies 3
and Treasurer 4
5
Senior Vice President, External Affairs 333,462K. J. Christie 6
and Chief Customer Officer 7
8
Sr Vice President 237,539M. M. Durkin 9
(retired effective 8/1/2020) 10
11
Senior Vice President and Chief Human Resources Officer 71,154K. S. Feltes 12
(retired effective 3/1/2020) 13
14
Senior Vice President, Energy Delivery 329,385H. L. Rosentrater 15
and Shared Services 16
17
Senior Vice President, Energy Resources 332,692J. R. Thackston 18
and Environmental Compliance Officer 19
20
Vice President, Safety and Human Resources 270,769B. A. Cox 21
22
Vice President, General Council, Corporate Secretary 198,369G. C. Hessler 23
and Chief Ethics/ Compliance Officer 24
(effective 1/1/2020) 25
26
Vice President Community & Economic Vitality 198,899L. D. Hill 27
(effective 1/1/2020) 28
29
Vice President, Chief Information Officer, and 290,077J. M. Kensok 30
Chief Security Officer 31
32
Vice President, Controller, and 251,308R. L. Krasselt 33
Principal Accounting Officer 34
35
Vice President and Chief Counsel for Regulatory 303,478D. J. Meyer 36
and Governmental Affairs 37
38
Vice President and Chief Strategy Officer 272,231E. D. Schlect 39
40
Executive Chairman of the Board of Directors 166,154S. L. Morris 41
(retired effectitve 3/1/2020) 42
43
44
FERC FORM NO. 1 (ED. 12-96) Page 104
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DIRECTORS
Avista Corporation X 04/15/2021 2020/Q4
Line Name (and Title) of Director Principal Business Address(b)(a)No.
1. Report below the information called for concerning each director of the respondent who held office at any time during the year. Include in column (a), abbreviated
titles of the directors who are officers of the respondent.
2. Designate members of the Executive Committee by a triple asterisk and the Chairman of the Executive Committee by a double asterisk.
1411 E. Mission Ave, Spokane, WA 99202Scott L. Morris** 1
(Chairman of the Board) 2
3
1411 E. Mission Ave, Spokane, WA 99202Dennis P. Vermillion *** 4
President and CEO 5
6
P.O. Box 3727, Spokane, WA 99220Kristianne Blake*** 7
8
16 Ivy Court, Langhorne, PA 19047Donald C. Burke 9
10
115 NW 78th St., Seattle, WA 98117Scott H. Maw 11
12
611 S. Congress Ave., Suite 125, Austin, TX 78704Rebecca A. Klein 13
14
P.O. Box 9000, Spokane, WA 99209Jeffry L. Philipps 15
16
2234 Deerfield Ln., Helena, MT 59601Marc F. Racicot 17
18
P.O. Box 2884, Spokane, WA 99220Heidi B. Stanley*** 19
20
111 Main Street, Lewiston, ID 83501R. John Taylor*** 21
22
26 Sanford Ln., Lafayette, CA 94549Janet D. Widmann 23
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FERC FORM NO. 1 (ED. 12-95)Page 105
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INFORMATION ON FORMULA RATES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.FERC Rate Schedule or Tariff Number FERC Proceeding
Does the respondent have formula rates?Yes
NoX
1. Please list the Commission accepted formula rates including FERC Rate Schedule or Tariff Number and FERC proceeding (i.e. Docket No)
accepting the rate(s) or changes in the accepted rate.
FERC Rate Schedule/Tariff Number FERC Proceeding
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FERC FORM NO. 1 (NEW. 12-08)Page 106
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.\ Filed DateAccession No.
Date
Docket No. Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
INFORMATION ON FORMULA RATES
Does the respondent file with the Commission annual (or more frequent)Yes
NoX
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
FERC Rate Schedule/Tariff Number FERC Proceeding
filings containing the inputs to the formula rate(s)?
Document
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FERC FORM NO. 1 (NEW. 12-08)Page 106a
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.Page No(s). Schedule Column Line No
INFORMATION ON FORMULA RATES
1. If a respondent does not submit such filings then indicate in a footnote to the applicable Form 1 schedule where formula rate inputs differ from
Formula Rate Variances
amounts reported in the Form 1.
2. The footnote should provide a narrative description explaining how the "rate" (or billing) was derived if different from the reported amount in the
Form 1.
3. The footnote should explain amounts excluded from the ratebase or where labor or other allocation factors, operating expenses, or other items
impacting formula rate inputs differ from amounts reported in Form 1 schedule amounts.4. Where the Commission has provided guidance on formula rate inputs, the specific proceeding should be noted in the footnote.
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FERC FORM NO. 1 (NEW. 12-08)Page 106b
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
IMPORTANT CHANGES DURING THE QUARTER/YEAR
Avista Corporation X 04/15/2021 2020/Q4
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
Give particulars (details) concerning the matters indicated below. Make the statements explicit and precise, and number them in
accordance with the inquiries. Each inquiry should be answered. Enter "none," "not applicable," or "NA" where applicable. If
information which answers an inquiry is given elsewhere in the report, make a reference to the schedule in which it appears.
1. Changes in and important additions to franchise rights: Describe the actual consideration given therefore and state from whom the
franchise rights were acquired. If acquired without the payment of consideration, state that fact.
2. Acquisition of ownership in other companies by reorganization, merger, or consolidation with other companies: Give names of
companies involved, particulars concerning the transactions, name of the Commission authorizing the transaction, and reference to
Commission authorization.
3. Purchase or sale of an operating unit or system: Give a brief description of the property, and of the transactions relating thereto, and
reference to Commission authorization, if any was required. Give date journal entries called for by the Uniform System of Accounts were
submitted to the Commission.
4. Important leaseholds (other than leaseholds for natural gas lands) that have been acquired or given, assigned or surrendered: Give
effective dates, lengths of terms, names of parties, rents, and other condition. State name of Commission authorizing lease and give
reference to such authorization.
5. Important extension or reduction of transmission or distribution system: State territory added or relinquished and date operations
began or ceased and give reference to Commission authorization, if any was required. State also the approximate number of customers
added or lost and approximate annual revenues of each class of service. Each natural gas company must also state major new
continuing sources of gas made available to it from purchases, development, purchase contract or otherwise, giving location and
approximate total gas volumes available, period of contracts, and other parties to any such arrangements, etc.
6. Obligations incurred as a result of issuance of securities or assumption of liabilities or guarantees including issuance of short-term
debt and commercial paper having a maturity of one year or less. Give reference to FERC or State Commission authorization, as
appropriate, and the amount of obligation or guarantee.
7. Changes in articles of incorporation or amendments to charter: Explain the nature and purpose of such changes or amendments.
8. State the estimated annual effect and nature of any important wage scale changes during the year.
9. State briefly the status of any materially important legal proceedings pending at the end of the year, and the results of any such
proceedings culminated during the year.
10. Describe briefly any materially important transactions of the respondent not disclosed elsewhere in this report in which an officer,
director, security holder reported on Page 104 or 105 of the Annual Report Form No. 1, voting trustee, associated company or known
associate of any of these persons was a party or in which any such person had a material interest.
11. (Reserved.)
12. If the important changes during the year relating to the respondent company appearing in the annual report to stockholders are
applicable in every respect and furnish the data required by Instructions 1 to 11 above, such notes may be included on this page.
13. Describe fully any changes in officers, directors, major security holders and voting powers of the respondent that may have occurred
during the reporting period.
14. In the event that the respondent participates in a cash management program(s) and its proprietary capital ratio is less than 30
percent please describe the significant events or transactions causing the proprietary capital ratio to be less than 30 percent, and the
extent to which the respondent has amounts loaned or money advanced to its parent, subsidiary, or affiliated companies through a cash
management program(s). Additionally, please describe plans, if any to regain at least a 30 percent proprietary ratio.
FERC FORM NO. 1 (ED. 12-96)Page 108
1. None
2. None
3. None
4. None
5. None
6. Reference is made to Notes 11, 12, 13 and 14 of the Notes to Financial Statements.
7. None
8. Average annual wage increases were 3.0% for non-exempt employees effective March 2, 2020. Average
annual wage increases were 3.1% for exempt employees effective March 2, 2020. Officers received average
increases of 5.5% effective February 22, 2020. Certain bargaining unit employees received increases of 3.0%
effective March 26, 2020.
9. Reference is made to Note 17 of the Notes to Financial Statements.
10. None
11. Reserved
12. See page 123 of this report.
13. Effective March 1, 2020, Karen S. Feltes, Senior Vice President and Chief Human Resources Officer,
retired.
Effective January 1, 2020, Marian Durkin moved from Chief Compliance Officer to Chief Legal Officer. She
retained her role as the Corporate Secretary. Effective August 1, 2020, Marian Durkin retired.
Effective January 1, 2020, Greg Hesler has been promoted from Senior Counsel II to Vice President, General
Counsel and Chief Compliance Officer. Effective May 11, 2020, Greg Hesler has been promoted from Chief
Compliance Officer to Chief Ethics/Compliance Officer.
Effective January 1, 2020, Latisha Hill has been promoted from Director of Business and Community
Development to Vice President of Community and Economic Vitality.
On March 10, 2021, the Company announced Sena Kwawu has been nominated to join the Avista Corp. board
of directors. Mr. Kwawu will stand for election by the shareholders and, if elected, will join the baord effective
May 11, 2021.
On March 10, 2021, the Company announced the upcoming retirement of board of directors member, Marc
Racicot, who has reached the mandatory retirement age of 72 under the Company's bylaws.
14. Proprietary capital is not less than 30 percent.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
Avista Corporation 04/15/2021 2020/Q4
UTILITY PLANT 1
6,713,727,078 6,385,433,383200-201Utility Plant (101-106, 114) 2
172,073,892 157,909,990200-201Construction Work in Progress (107) 3
6,885,800,970 6,543,343,373TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
2,294,362,603 2,121,893,905200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
4,591,438,367 4,421,449,468Net Utility Plant (Enter Total of line 4 less 5) 6
0 0202-203Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 7
0 0Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 8
0 0Nuclear Fuel Assemblies in Reactor (120.3) 9
0 0Spent Nuclear Fuel (120.4) 10
0 0Nuclear Fuel Under Capital Leases (120.6) 11
0 0202-203(Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 12
0 0Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 13
4,591,438,367 4,421,449,468Net Utility Plant (Enter Total of lines 6 and 13) 14
0 0Utility Plant Adjustments (116) 15
6,992,076 6,992,076Gas Stored Underground - Noncurrent (117) 16
OTHER PROPERTY AND INVESTMENTS 17
5,311,287 4,340,610Nonutility Property (121) 18
212,107 176,234(Less) Accum. Prov. for Depr. and Amort. (122) 19
11,547,000 11,547,000Investments in Associated Companies (123) 20
207,410,331 207,105,954224-225Investment in Subsidiary Companies (123.1) 21
(For Cost of Account 123.1, See Footnote Page 224, line 42) 22
0 0228-229Noncurrent Portion of Allowances 23
77,890 77,973Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
24,673,077 22,034,002Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
596,015 922,948Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
249,403,493 245,852,253TOTAL Other Property and Investments (Lines 18-21 and 23-31) 32
CURRENT AND ACCRUED ASSETS 33
0 0Cash and Working Funds (Non-major Only) (130) 34
7,363,358 3,067,240Cash (131) 35
4,335,989 4,434,090Special Deposits (132-134) 36
1,116,351 730,965Working Fund (135) 37
152,774 155,890Temporary Cash Investments (136) 38
0 0Notes Receivable (141) 39
161,513,344 153,814,552Customer Accounts Receivable (142) 40
56,664,630 15,726,829Other Accounts Receivable (143) 41
11,336,140 2,373,469(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
0 0Notes Receivable from Associated Companies (145) 43
719,507 222,671Accounts Receivable from Assoc. Companies (146) 44
4,088,628 4,148,891227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
51,854,056 46,558,819227Plant Materials and Operating Supplies (154) 48
0 0227Merchandise (155) 49
0 0227Other Materials and Supplies (156) 50
0 0202-203/227Nuclear Materials Held for Sale (157) 51
0 0228-229Allowances (158.1 and 158.2) 52
FERC FORM NO. 1 (REV. 12-03)Page 110
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
X
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBITS)
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
Avista Corporation 04/15/2021 2020/Q4
(Continued)
0 0(Less) Noncurrent Portion of Allowances 53
0 0227Stores Expense Undistributed (163) 54
9,535,324 14,305,397Gas Stored Underground - Current (164.1) 55
0 0Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56
26,280,659 24,682,259Prepayments (165) 57
0 0Advances for Gas (166-167) 58
24,973 129,823Interest and Dividends Receivable (171) 59
2,934,797 3,609,147Rents Receivable (172) 60
0 0Accrued Utility Revenues (173) 61
236,392 193,803Miscellaneous Current and Accrued Assets (174) 62
1,523,219 1,780,327Derivative Instrument Assets (175) 63
596,015 922,948(Less) Long-Term Portion of Derivative Instrument Assets (175) 64
0 0Derivative Instrument Assets - Hedges (176) 65
0 0(Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 66
316,411,846 270,264,286Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
15,341,337 13,795,819Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
0 0230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
717,281,643 643,207,368232Other Regulatory Assets (182.3) 72
0 0Prelim. Survey and Investigation Charges (Electric) (183) 73
0 0Preliminary Natural Gas Survey and Investigation Charges 183.1) 74
0 0Other Preliminary Survey and Investigation Charges (183.2) 75
152,201 131,978Clearing Accounts (184) 76
0 0Temporary Facilities (185) 77
29,826,563 18,484,386233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
7,512,371 8,883,821Unamortized Loss on Reaquired Debt (189) 81
216,728,536 177,056,526234Accumulated Deferred Income Taxes (190) 82
1,433,580 -3,189,401Unrecovered Purchased Gas Costs (191) 83
988,276,231 858,370,497Total Deferred Debits (lines 69 through 83) 84
6,152,522,013 5,802,928,580TOTAL ASSETS (lines 14-16, 32, 67, and 84) 85
FERC FORM NO. 1 (REV. 12-03)Page 111
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
Avista Corporation 04/15/2021 2020/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
PROPRIETARY CAPITAL 1
1,176,498,9771,249,688,206Common Stock Issued (201) 2 250-251
00Preferred Stock Issued (204) 3 250-251
00Capital Stock Subscribed (202, 205) 4
00Stock Liability for Conversion (203, 206) 5
00Premium on Capital Stock (207) 6
-10,696,711-10,696,711Other Paid-In Capital (208-211) 7 253
00Installments Received on Capital Stock (212) 8 252
00(Less) Discount on Capital Stock (213) 9 254
-44,938,398-47,076,877(Less) Capital Stock Expense (214) 10 254b
747,158,701771,613,505Retained Earnings (215, 215.1, 216) 11 118-119
-13,386,701-13,577,380Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119
00(Less) Reaquired Capital Stock (217) 13 250-251
00 Noncorporate Proprietorship (Non-major only) (218) 14
-10,258,024-14,378,164Accumulated Other Comprehensive Income (219) 15 122(a)(b)
1,934,254,6402,029,726,333Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
1,904,200,0002,017,200,000Bonds (221) 18 256-257
83,700,00083,700,000(Less) Reaquired Bonds (222) 19 256-257
51,547,00051,547,000Advances from Associated Companies (223) 20 256-257
00Other Long-Term Debt (224) 21 256-257
142,133133,250Unamortized Premium on Long-Term Debt (225) 22
930,270843,651(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
1,871,258,8631,984,336,599Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
65,565,10567,716,314Obligations Under Capital Leases - Noncurrent (227) 26
00Accumulated Provision for Property Insurance (228.1) 27
245,000395,000Accumulated Provision for Injuries and Damages (228.2) 28
212,005,607211,880,117Accumulated Provision for Pensions and Benefits (228.3) 29
00Accumulated Miscellaneous Operating Provisions (228.4) 30
11,767,1583,820,594Accumulated Provision for Rate Refunds (229) 31
19,684,47637,427,278Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
20,338,05317,194,050Asset Retirement Obligations (230) 34
329,605,399338,433,353Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
182,300,000202,000,000Notes Payable (231) 37
107,406,813104,217,591Accounts Payable (232) 38
14,722,3488,742,915Notes Payable to Associated Companies (233) 39
00Accounts Payable to Associated Companies (234) 40
4,745,5733,028,142Customer Deposits (235) 41
38,022,91845,266,874Taxes Accrued (236) 42 262-263
15,282,04115,884,942Interest Accrued (237) 43
00Dividends Declared (238) 44
00Matured Long-Term Debt (239) 45
FERC FORM NO. 1 (rev. 12-03)Page 112
Year/Period of ReportName of Respondent This Report is:
(1) An Original
(2) A Resubmission
x
Date of Report
(mo, da, yr)
end of
Line
No.Title of Account
(a)
Ref.
Page No.
(b)
Current Year
End of Quarter/Year
Balance
(c)
Prior Year
End Balance
12/31
(d)
Avista Corporation 04/15/2021 2020/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
168,034111,813Tax Collections Payable (241) 47
50,808,47960,781,094Miscellaneous Current and Accrued Liabilities (242) 48
4,127,5614,249,213Obligations Under Capital Leases-Current (243) 49
30,612,67051,435,582Derivative Instrument Liabilities (244) 50
19,684,47637,427,277(Less) Long-Term Portion of Derivative Instrument Liabilities 51
00Derivative Instrument Liabilities - Hedges (245) 52
00(Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 53
428,511,961458,290,889Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
2,083,4902,444,383Customer Advances for Construction (252) 56
30,443,96129,866,627Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
29,659,55831,450,029Other Deferred Credits (253) 59 269
481,207,133473,121,377Other Regulatory Liabilities (254) 60 278
1,448,3591,318,822Unamortized Gain on Reaquired Debt (257) 61
00Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
514,870,007603,415,433Accum. Deferred Income Taxes-Other Property (282) 63
179,585,209200,118,168Accum. Deferred Income Taxes-Other (283) 64
1,239,297,7171,341,734,839Total Deferred Credits (lines 56 through 64) 65
5,802,928,5806,152,522,013TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 66
FERC FORM NO. 1 (rev. 12-03)Page 113
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME
Avista Corporation X 04/15/2021 2020/Q4
Line
(c)(b)(a)
Title of Account
No.
Total
Current Year to
Date Balance for
Quarter/Year
(d)
(Ref.)
Page No.
Quarterly
1. Report in column (c) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2. Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
3. Report in column (g) the quarter to date amounts for electric utility function; in column (i) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the current year quarter.
4. Report in column (h) the quarter to date amounts for electric utility function; in column (j) the quarter to date amounts for gas utility, and in column (l) the
quarter to date amounts for other utility function for the prior year quarter.
5. If additional columns are needed, place them in a footnote.
Annual or Quarterly if applicable
5. Do not report fourth quarter data in columns (e) and (f)
6. Report amounts for accounts 412 and 413, Revenues and Expenses from Utility Plant Leased to Others, in another utility columnin a similar manner to
a utility department. Spread the amount(s) over lines 2 thru 26 as appropriate. Include these amounts in columns (c) and (d) totals.
7. Report amounts in account 414, Other Utility Operating Income, in the same manner as accounts 412 and 413 above.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
Total
Prior Year to
Date Balance for
Quarter/Year
UTILITY OPERATING INCOME 1
1,379,875,645 1,428,099,066300-301Operating Revenues (400) 2
Operating Expenses 3
762,581,592 818,533,678320-323Operation Expenses (401) 4
74,568,922 70,160,821320-323Maintenance Expenses (402) 5
181,300,837 163,503,287336-337Depreciation Expense (403) 6
336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
44,668,607 40,625,925336-337Amort. & Depl. of Utility Plant (404-405) 8
99,047 99,047336-337Amort. of Utility Plant Acq. Adj. (406) 9
Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407) 10
Amort. of Conversion Expenses (407) 11
12,453,020 7,343,186Regulatory Debits (407.3) 12
57,223,861 24,373,462(Less) Regulatory Credits (407.4) 13
114,634,576 104,229,614262-263Taxes Other Than Income Taxes (408.1) 14
-41,194,492 1,016,853262-263Income Taxes - Federal (409.1) 15
654,441 -512,990262-263- Other (409.1) 16
134,834,319 16,095,155234, 272-277Provision for Deferred Income Taxes (410.1) 17
82,145,804 3,735,815234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
-577,334 718,518266Investment Tax Credit Adj. - Net (411.4) 19
(Less) Gains from Disp. of Utility Plant (411.6) 20
Losses from Disp. of Utility Plant (411.7) 21
(Less) Gains from Disposition of Allowances (411.8) 22
Losses from Disposition of Allowances (411.9) 23
Accretion Expense (411.10) 24
1,144,653,870 1,193,703,817TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
235,221,775 234,395,249Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,line 27 26
FERC FORM NO. 1/3-Q (REV. 02-04) Page 114
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line Previous Year to Date
(in dollars)
(k)(j)(g)
ELECTRIC UTILITY
No.Current Year to Date
(in dollars)
OTHER UTILITY
(l)
GAS UTILITY
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
Previous Year to Date
(in dollars)
Current Year to Date
(in dollars)
(h) (i)
9. Use page 122 for important notes regarding the statement of income for any account thereof.
10. Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected the
gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights of the
utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
11 Give concise explanations concerning significant amounts of any refunds made or received during the year resulting from settlement of any rate
proceeding affecting revenues received or costs incurred for power or gas purches, and a summary of the adjustments made to balance sheet, income,
and expense accounts.
12. If any notes appearing in the report to stokholders are applicable to the Statement of Income, such notes may be included at page 122.
13. Enter on page 122 a concise explanation of only those changes in accounting methods made during the year which had an effect on net income,
including the basis of allocations and apportionments from those used in the preceding year. Also, give the appropriate dollar effect of such changes.
14. Explain in a footnote if the previous year's/quarter's figures are different from that reported in prior reports.
15. If the columns are insufficient for reporting additional utility departments, supply the appropriate account titles report the information in a footnote to
this schedule.
1
942,731,364 444,615,322 437,144,281 983,483,744 2
3
479,296,895 303,138,157 283,284,697 515,395,521 4
58,433,891 15,618,412 16,135,031 54,542,409 5
142,059,284 36,824,230 39,241,553 126,679,057 6
7
32,861,811 10,079,068 11,806,796 30,546,857 8
99,047 99,047 9
10
11
8,161,579 1,453,061 4,291,441 5,890,125 12
47,876,238 3,442,644 9,347,623 20,930,818 13
86,303,016 24,983,566 28,331,560 79,246,048 14
-21,919,271 -6,428,201-19,275,221 7,445,054 15
-214,113 -8,110 868,554-504,880 16
83,467,206 11,059,318 51,367,113 5,035,837 17
61,963,304 1,346,919 20,182,500 2,388,896 18
-562,691 172,256-14,643 546,262 19
20
21
22
23
24
758,147,112 392,102,194 386,506,758 801,601,623 25
184,584,252 52,513,128 50,637,523 181,882,121 26
FERC FORM NO. 1 (ED. 12-96) Page 115
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF INCOME FOR THE YEAR (continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
Previous Year
(c)(b)(a)
Title of Account
No.
Current Year
TOTAL
(d)
(Ref.)
Page No.
Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
235,221,775 234,395,249Net Utility Operating Income (Carried forward from page 114) 27
Other Income and Deductions 28
Other Income 29
Nonutilty Operating Income 30
Revenues From Merchandising, Jobbing and Contract Work (415) 31
(Less) Costs and Exp. of Merchandising, Job. & Contract Work (416) 32
108,256Revenues From Nonutility Operations (417) 33
5,439,625 14,612,589(Less) Expenses of Nonutility Operations (417.1) 34
-31,838 -31,291Nonoperating Rental Income (418) 35
5,304,376 13,582,269119Equity in Earnings of Subsidiary Companies (418.1) 36
3,448,647 4,401,265Interest and Dividend Income (419) 37
338,811 -104,311Allowance for Other Funds Used During Construction (419.1) 38
Miscellaneous Nonoperating Income (421) 39
289,281 109,159Gain on Disposition of Property (421.1) 40
4,017,908 3,344,502TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
Loss on Disposition of Property (421.2) 43
-815,484 -33,721Miscellaneous Amortization (425) 44
2,999,603 11,332,979 Donations (426.1) 45
3,072,596 2,640,044 Life Insurance (426.2) 46
-17,039 21,180 Penalties (426.3) 47
1,773,265 1,718,553 Exp. for Certain Civic, Political & Related Activities (426.4) 48
3,494,855 27,317,212 Other Deductions (426.5) 49
10,507,796 42,996,247TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
923,792 311,708262-263Taxes Other Than Income Taxes (408.2) 52
-60,470 -8,257,303262-263Income Taxes-Federal (409.2) 53
800 -350,985262-263Income Taxes-Other (409.2) 54
218,831 -1,887,439234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
3,167,528 196,940234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.2) 56
Investment Tax Credit Adj.-Net (411.5) 57
(Less) Investment Tax Credits (420) 58
-2,084,575 -10,380,959TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
-4,405,313 -29,270,786Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
88,943,779 86,591,405Interest on Long-Term Debt (427) 62
937,453 321,206Amort. of Debt Disc. and Expense (428) 63
2,222,423 2,266,506Amortization of Loss on Reaquired Debt (428.1) 64
8,883 8,883(Less) Amort. of Premium on Debt-Credit (429) 65
(Less) Amortization of Gain on Reaquired Debt-Credit (429.1) 66
186,289 489,554Interest on Debt to Assoc. Companies (430) 67
6,170,081 8,205,985Other Interest Expense (431) 68
2,152,002 4,169,530(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
96,299,140 93,696,243Net Interest Charges (Total of lines 62 thru 69) 70
134,517,322 111,428,220Income Before Extraordinary Items (Total of lines 27, 60 and 70) 71
Extraordinary Items 72
102,999,990Extraordinary Income (434) 73
(Less) Extraordinary Deductions (435) 74
102,999,990Net Extraordinary Items (Total of line 73 less line 74) 75
22,478,603262-263Income Taxes-Federal and Other (409.3) 76
80,521,387Extraordinary Items After Taxes (line 75 less line 76) 77
134,517,322 191,949,607Net Income (Total of line 71 and 77) 78
FERC FORM NO. 1/3-Q (REV. 02-04) Page 117
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
Avista Corporation X 04/15/2021 2020/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 -
439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
623,531,170 705,980,176 1 Balance-Beginning of Period
2 Changes
3 Adjustments to Retained Earnings (Account 439)
4
5
6
7
8
9 TOTAL Credits to Retained Earnings (Acct. 439)
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
178,367,338 129,212,946 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 3,725,554)-4,274,423 18
19
20
21
( 3,725,554)-4,274,423 22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
( 102,772,642)-110,253,196 31
32
33
34
35
( 102,772,642)-110,253,196 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
10,579,864 5,495,054 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
705,980,176 726,160,557 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
41,178,525 45,452,948 39
40
FERC FORM NO. 1/3-Q (REV. 02-04)Page 118
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF RETAINED EARNINGS
Avista Corporation X 04/15/2021 2020/Q4
Line
Current
Quarter/Year
Year to Date
Balance
(c)(b)(a)
Item
Contra Primary
No.
Account Affected
1. Do not report Lines 49-53 on the quarterly version.
2. Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3. Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436 -
439 inclusive). Show the contra primary account affected in column (b)
4. State the purpose and amount of each reservation or appropriation of retained earnings.
5. List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6. Show dividends for each class and series of capital stock.
7. Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8. Explain in a footnote the basis for determining the amount reserved or appropriated. If such reservation or appropriation is to be
recurrent, state the number and annual amounts to be reserved or appropriated as well as the totals eventually to be accumulated.
9. If any notes appearing in the report to stockholders are applicable to this statement, include them on pages 122-123.
Previous
Quarter/Year
Year to Date
Balance
(d)
41
42
43
44
41,178,525 45,452,948 45 TOTAL Appropriated Retained Earnings (Account 215)
APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
41,178,525 45,452,948 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
747,158,701 771,613,505 48 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1)
UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
( 16,389,107)-13,386,701 49 Balance-Beginning of Year (Debit or Credit)
13,582,269 5,304,376 50 Equity in Earnings for Year (Credit) (Account 418.1)
10,000,000 5,000,000 51 (Less) Dividends Received (Debit)
( 579,863)-495,055 52 Corporate Costs Allocated to Subsidiaries
( 13,386,701)-13,577,380 53 Balance-End of Year (Total lines 49 thru 52)
FERC FORM NO. 1/3-Q (REV. 02-04)Page 119
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF CASH FLOWS
Avista Corporation X 04/15/2021 2020/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
191,949,607 134,517,322 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
202,496,251 225,969,444 4 Depreciation and Depletion
-45,916,643-9,923,228 5 Amortization of Deferred Power and Natural Gas Costs
2,578,830 3,150,992 6 Amortization of Debt Expense
1,632,961 7 Amortization of Investment in Exchange Power
10,274,962 49,739,817 8 Deferred Income Taxes (Net)
718,518-577,334 9 Investment Tax Credit Adjustment (Net)
-9,860,829-51,466,229 10 Net (Increase) Decrease in Receivables
-6,255,653-464,901 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
1,823,471 6,150,782 13 Net Increase (Decrease) in Payables and Accrued Expenses
-6,065,721-9,597,307 14 Net (Increase) Decrease in Other Regulatory Assets
-5,135,361-4,626,804 15 Net Increase (Decrease) in Other Regulatory Liabilities
6,434,430 6,711,875 16 (Less) Allowance for Other Funds Used During Construction
13,582,269 5,304,376 17 (Less) Undistributed Earnings from Subsidiary Companies
74,394,412 7,562,554 18 Other (provide details in footnote):
400,000 4,149,939 19 Allowance for Doubtful Accounts
10,396,693 8,520,219 20 Changes in Other Non-Current Assets and Liabilities
-13,325,137-33,499,271 21 Cash Paid for Settlement of Interest Rate Swaps
390,089,662 317,589,743 22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21)
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
-439,249,001-399,504,892 26 Gross Additions to Utility Plant (less nuclear fuel)
27 Gross Additions to Nuclear Fuel
28 Gross Additions to Common Utility Plant
29 Gross Additions to Nonutility Plant
30 (Less) Allowance for Other Funds Used During Construction
31 Other (provide details in footnote):
32
33
-439,249,001-399,504,892 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
882,641 570,225 37 Proceeds from Disposal of Noncurrent Assets (d)
38
-3,693,898-6,476,269 39 Investments in and Advances to Assoc. and Subsidiary Companies
40 Contributions and Advances from Assoc. and Subsidiary Companies
41 Disposition of Investments in (and Advances to)
42 Associated and Subsidiary Companies
43
44 Purchase of Investment Securities (a)
45 Proceeds from Sales of Investment Securities (a)
FERC FORM NO. 1 (ED. 12-96)Page 120
(1) Codes to be used:(a) Net Proceeds or Payments;(b)Bonds, debentures and other long-term debt; (c) Include commercial paper; and (d) Identify separately such items as
investments, fixed assets, intangibles, etc.
(2) Information about noncash investing and financing activities must be provided in the Notes to the Financial statements. Also provide a reconciliation between "Cash and
Cash Equivalents at End of Period" with related amounts on the Balance Sheet.
(3) Operating Activities - Other: Include gains and losses pertaining to operating activities only. Gains and losses pertaining to investing and financing activities should be
reported in those activities. Show in the Notes to the Financials the amounts of interest paid (net of amount capitalized) and income taxes paid.
(4) Investing Activities: Include at Other (line 31) net cash outflow to acquire other companies. Provide a reconciliation of assets acquired with liabilities assumed in the Notes
to the Financial Statements. Do not include on this statement the dollar amount of leases capitalized per the USofA General Instruction 20; instead provide a reconciliation of
the dollar amount of leases capitalized with the plant cost.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENT OF CASH FLOWS
Avista Corporation X 04/15/2021 2020/Q4
Line Description (See Instruction No. 1 for Explanation of Codes)Current Year to Date
Quarter/Year
(b)(a)No.
Previous Year to Date
Quarter/Year
(c)
46 Loans Made or Purchased
47 Collections on Loans
48
49 Net (Increase) Decrease in Receivables
50 Net (Increase ) Decrease in Inventory
51 Net (Increase) Decrease in Allowances Held for Speculation
52 Net Increase (Decrease) in Payables and Accrued Expenses
53 Other (provide details in footnote):
-1,750,738-1,362,792 54 Other
10,000,000 5,000,000 55 Dividends Received from Subsidiaries
56 Net Cash Provided by (Used in) Investing Activities
-433,810,996-401,773,728 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
180,000,000 165,000,000 61 Long-Term Debt (b)
62 Preferred Stock
64,572,145 72,200,592 63 Common Stock
64 Other (provide details in footnote):
65
19,700,000 66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
244,572,145 256,900,592 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-90,000,000-52,000,000 73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
-891,513-2,408,161 76 Other (provide details in footnote):
-1,115,527-3,376,862 77 Debt Issuance Costs
-7,700,000 78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Preferred Stock
-102,772,642-110,253,196 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
42,092,463 88,862,373 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
-1,628,871 4,678,388 86 (Total of lines 22,57 and 83)
87
5,582,966 3,954,095 88 Cash and Cash Equivalents at Beginning of Period
89
3,954,095 8,632,483 90 Cash and Cash Equivalents at End of period
FERC FORM NO. 1 (ED. 12-96)Page 121
Schedule Page: 120 Line No.: 18 Column: b
Power and natural gas deferrals 1,092,888
Change in special deposits 1,579,362
Change in other current assets (861,790)
Non-cash stock compensation 5,846,058
Gain on sale of property and equipment (289,281)
Other 195,317
Schedule Page: 120 Line No.: 18 Column: c
Power and natural gas deferrals 4,692,134
Change in special deposits 63,973,598
Change in other current assets (5,417,123)
Non-cash stock compensation 11,352,863
Gain on sale of property and equipment (109,159)
Other (97,901)
Schedule Page: 120 Line No.: 76 Column: b
Payment of minimum tax withholdings for
share-based payment awards (2,408,161)
Schedule Page: 120 Line No.: 76 Column: c
Payment of minimum tax withholdings for
share-based payment awards (891,513)
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report Year/Period of Report
End of
NOTES TO FINANCIAL STATEMENTS
Avista Corporation X 04/15/2021 2020/Q4
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
1. Use the space below for important notes regarding the Balance Sheet, Statement of Income for the year, Statement of Retained
Earnings for the year, and Statement of Cash Flows, or any account thereof. Classify the notes according to each basic statement,
providing a subheading for each statement except where a note is applicable to more than one statement.
2. Furnish particulars (details) as to any significant contingent assets or liabilities existing at end of year, including a brief explanation of
any action initiated by the Internal Revenue Service involving possible assessment of additional income taxes of material amount, or of a
claim for refund of income taxes of a material amount initiated by the utility. Give also a brief explanation of any dividends in arrears on
cumulative preferred stock.
3. For Account 116, Utility Plant Adjustments, explain the origin of such amount, debits and credits during the year, and plan of
disposition contemplated, giving references to Cormmission orders or other authorizations respecting classification of amounts as plant
adjustments and requirements as to disposition thereof.
4. Where Accounts 189, Unamortized Loss on Reacquired Debt, and 257, Unamortized Gain on Reacquired Debt, are not used, give an
explanation, providing the rate treatment given these items. See General Instruction 17 of the Uniform System of Accounts.
5. Give a concise explanation of any retained earnings restrictions and state the amount of retained earnings affected by such
restrictions.
6. If the notes to financial statements relating to the respondent company appearing in the annual report to the stockholders are
applicable and furnish the data required by instructions above and on pages 114-121, such notes may be included herein.
7. For the 3Q disclosures, respondent must provide in the notes sufficient disclosures so as to make the interim information not
misleading. Disclosures which would substantially duplicate the disclosures contained in the most recent FERC Annual Report may be
omitted.
8. For the 3Q disclosures, the disclosures shall be provided where events subsequent to the end of the most recent year have occurred
which have a material effect on the respondent. Respondent must include in the notes significant changes since the most recently
completed year in such items as: accounting principles and practices; estimates inherent in the preparation of the financial statements;
status of long-term contracts; capitalization including significant new borrowings or modifications of existing financing agreements; and
changes resulting from business combinations or dispositions. However were material contingencies exist, the disclosure of such matters
shall be provided even though a significant change since year end may not have occurred.
9. Finally, if the notes to the financial statements relating to the respondent appearing in the annual report to the stockholders are
applicable and furnish the data required by the above instructions, such notes may be included herein.
FERC FORM NO. 1 (ED. 12-96)Page 122
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature 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 eastern Washington and northern Idaho. Avista
Corp. also provides natural gas distribution service in parts of northeastern and southwestern Oregon. Avista Corp. has electric
generating facilities in Washington, Idaho, Oregon and Montana. Avista Corp. also supplies electricity to a small number of
customers in Montana, most of whom are employees who operate the Company's Noxon Rapids generating facility.
Alaska Electric and Resources Company (AERC) is a wholly-owned subsidiary of Avista Corp. The primary subsidiary of AERC is
Alaska Electric Light and Power (AEL&P), which comprises Avista Corp.'s regulated utility operations in Alaska.
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).
Basis of Reporting
The financial statements include the assets, liabilities, revenues and expenses of the Company and have been prepared in accordance
with the accounting requirements of the Federal Energy Regulatory Commission (FERC) as set forth in its applicable Uniform System
of Accounts and published accounting releases, which is a comprehensive basis of accounting other than accounting principles
generally accepted in the United States of America (U.S. GAAP). As required by the FERC, the Company accounts for its investment
in majority-owned subsidiaries on the equity method rather than consolidating the assets, liabilities, revenues, and expenses of these
subsidiaries, as required by U.S. GAAP. The accompanying financial statements include the Company’s proportionate share of utility
plant and related operations resulting from its interests in jointly owned plants. In addition, under the requirements of the FERC, there
are differences from U.S. GAAP in the presentation of (1) current portion of long-term debt (2) assets and liabilities for cost of
removal of assets, (3) assets held for sale, (4) regulatory assets and liabilities, (5) deferred income taxes associated with accounts
other than utility property, plant and equipment, (6) comprehensive income, (7) unamortized debt issuance costs, (8) operating
revenues and resource costs associated with settled energy contracts that are “booked out” (not physically delivered), (9) non-service
portion of pension and other postretirement benefit costs and (10) leases.
Use of Estimates
The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that
affect the amounts reported for assets and liabilities and the disclosure of contingent assets and liabilities at the date of the financial
statements and the reported amounts of revenues and expenses during the reporting period. Significant estimates include:
determining the market value of energy commodity derivative assets and liabilities,
pension and other postretirement benefit plan obligations,
contingent liabilities,
goodwill impairment testing for goodwill held at subsidiaries,
recoverability of regulatory assets, and
unbilled revenues.
Changes in these estimates and assumptions are considered reasonably possible and may have a material effect on the financial
statements and thus actual results could differ from the amounts reported and disclosed herein.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.1
System of Accounts
The accounting records of the Company’s utility operations are maintained in accordance with the uniform system of accounts
prescribed by the FERC and adopted by the state regulatory commissions in Washington, Idaho, Montana and Oregon.
Regulation
The Company is subject to state regulation in Washington, Idaho, Montana, and Oregon. The Company is also subject to federal
regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its
operations.
Depreciation
For utility operations, depreciation expense is estimated by a method of depreciation accounting utilizing composite rates for utility
plant. Such rates are designed to provide for retirements of properties at the expiration of their service lives. For utility operations, the
ratio of depreciation provisions to average depreciable property was as follows for the years ended December 31:
2020 2019
Avista Corp.
Ratio of depreciation to average depreciable property 3.43% 3.28%
The average service lives for the following broad categories of utility plant in service are (in years):
Avista Corp.
Electric thermal/other production 27
Hydroelectric production 81
Electric transmission 49
Electric distribution 39
Natural gas distribution property 44
Other shorter-lived general plant 8
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the cost of both the debt and equity funds used to finance utility plant additions during the construction period. As
prescribed by regulatory authorities, AFUDC is capitalized as a part of the cost of utility plant. 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 Statements of Income in the line item “other expense (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 WUTC and IPUC have authorized Avista Corp. to calculate AFUDC using its allowed rate of return. To the extent amounts
calculated using this rate exceed the AFUDC amounts calculated using the FERC formula, Avista Corp. capitalizes the excess as a
regulatory asset. The regulatory asset associated with plant in service is amortized over the average useful life of Avista Corp.'s utility
plant which is approximately 30 years. The regulatory asset associated with construction work in progress is not amortized until the
plant is placed in service.
The effective AFUDC rate was the following for the years ended December 31:
2020 2019
Avista Corp.
Effective state AFUDC rate 7.25% 7.39%
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.2
Income Taxes
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. 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 income tax returns. The deferred income tax expense for the period is equal to the net
change in the deferred income tax asset and liability accounts from the beginning to the end of the period. The effect on deferred
income taxes from a change in tax rates is recognized in income in the period that includes the enactment date unless a regulatory
order specifies deferral 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's largest deferred income tax item is the difference between the book and tax basis of utility plant. This item results
from the temporary difference on depreciation expense. In early tax years, this item is recorded as a deferred income tax liability that
will eventually reverse and become subject to income tax in later tax years.
The Company did not incur any penalties on income tax positions in 2020 or 2019. The Company would recognize interest accrued
related to income tax positions as interest expense and any penalties incurred as other operating expense.
Stock-Based Compensation
The Company currently issues three types of stock-based compensation awards - restricted shares, market-based awards and
performance-based awards. Historically, these stock compensation awards have not been material to the Company's overall financial
results. Compensation cost relating to share-based payment transactions is recognized in the Company’s financial statements based on
the fair value of the equity or liability instruments issued and recorded over the requisite service period.
The Company recorded stock-based compensation expense (included in other operating expenses) and income tax benefits in the
Statements of Income of the following amounts for the years ended December 31 (dollars in thousands):
2020 2019
Stock-based compensation expense $5,846 $11,353
Income tax benefits 1,228 2,384
Excess tax benefits (expenses) on settled share-based employee
payments (165)(612)
Restricted share awards vest in equal thirds each year over 3 years 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, for restricted shares granted in 2017, the Company must meet
a return 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 Earnings Per Share (CEPS) awards are
performance awards. Both types of awards vest after a period of 3 years and are payable in cash or Avista Corp. common stock at the
end of the three-year period. The method of settlement is at the discretion of the Company and historically the Company has settled
these awards through issuance of Avista Corp. common stock and intends to continue this practice. Both types of awards entitle the
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.3
recipients to dividend equivalent rights, are subject to forfeiture under certain circumstances, and are subject to meeting specific
market or performance conditions. Based on the level of attainment of the market or performance conditions, the amount of cash paid
or common stock issued will range from 0 to 200 percent of the initial awards granted. Dividend equivalent rights are accumulated
and paid out only on shares that eventually vest and have met the market and performance conditions.
For both the TSR awards and the CEPS awards, the Company accounts for them as equity awards and compensation cost for these
awards is recognized over the requisite service period, provided that the requisite service period is rendered. For TSR awards, if the
market condition is not met at the end of the three-year service period, there will be no change in the cumulative amount of
compensation cost recognized, since the awards are still considered vested even though the market metric was not met. For CEPS
awards, at the end of the three-year service period, if the internal performance metric of cumulative earnings per share is not met, all
compensation cost for these awards is reversed as these awards are not considered vested.
The fair value of each TSR award is estimated on the date of grant using a statistical model that incorporates the probability of
meeting the market targets based on historical returns relative to a peer group. The estimated fair value of the equity component of
CEPS awards was estimated on the date of grant as the share price of Avista Corp. common stock on the date of grant, less the net
present value of the estimated dividends over the three-year period.
The following table summarizes the number of grants, vested and unvested shares, earned shares (based on market metrics), and other
pertinent information related to the Company's stock compensation awards for the years ended December 31:
2020 2019
Restricted Shares
Shares granted during the year 45,540 50,061
Shares vested during the year 56,203 48,228
Unvested shares at end of year 71,706 93,351
Unrecognized compensation expense at end of year
(in thousands) $2,003 $2,054
TSR Awards
TSR shares granted during the year 47,848 99,214
TSR shares vested during the year (1)71,299 106,858
Unvested TSR shares at end of year 122,133 178,035
Unrecognized compensation expense (in thousands) $2,296 $3,377
CEPS Awards
CEPS shares granted during the year 47,848 49,609
CEPS shares vested during the year 35,622 53,454
CEPS shares earned based on market metrics 63,763 106,908
Unvested CEPS shares at end of year 83,464 88,990
Unrecognized compensation expense (in thousands) $1,090 $2,401
(1) The market metrics were not met during 2020 and 2019 and no TRS shares were earned during these periods.
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, 2020 and 2019, the Company had recognized cumulative compensation expense and a liability of $0.8 million and $0.9
million, respectively, related to the dividend component on the outstanding and unvested share grants.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.4
Cash and Cash Equivalents
For the purposes of the Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months
or less when purchased to be cash equivalents.
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The
Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual
accounts.
Utility Plant in Service
The cost of additions to utility plant in service, including AFUDC and replacements of units of property and improvements, is
capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is charged to accumulated
depreciation.
Asset Retirement Obligations (ARO)
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
recorded, the associated costs of the ARO are capitalized as part of the carrying amount of the related long-lived asset. The liability is
accreted to its present value each period and the related capitalized costs are depreciated over the useful life of the related asset. In
addition, if there are changes in the estimated timing or estimated costs of the AROs, adjustments are recorded during the period new
information becomes available as an increase or decrease to the liability, with the offset recorded to the related long-lived asset. Upon
retirement of the asset, the Company either settles the ARO for its recorded amount or recognizes a regulatory asset or liability for the
difference, which will be surcharged/refunded to customers through the ratemaking process. 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 AROs).
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Balance Sheets measured at estimated fair value.
The Washington Utilities and Transportation Commission (WUTC) and the Idaho Public Utilities Commission (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 Purchased Gas
Adjustments (PGA), the Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (PCA) mechanism in
Idaho, and periodic general rates cases. The resulting regulatory assets associated with energy commodity derivative instruments have
been concluded to be probable of recovery through future rates.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated
fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual
basis until they are settled or realized unless there is a decline in the fair value of the contract that is determined to be
other-than-temporary.
For interest rate swap 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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
regulatory asset or liability is amortized as a component of interest expense over the term of the associated debt. The Company
records 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.
The Company has multiple master netting agreements with a variety of entities that allow for cross-commodity netting of derivative
agreements with the same counterparty (i.e. power derivatives can be netted with natural gas derivatives). 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 that would be received when selling an asset or paid to transfer a liability (an exit price) in an orderly
transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred
compensation assets, as well as derivatives related to interest rate swap derivatives and foreign currency exchange derivatives, are
reported at estimated fair value on the Balance Sheets. See Note 15 for the Company’s fair value disclosures.
Regulatory Deferred Charges and 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,
the regulated rates are designed to recover the cost of providing the regulated services, and
in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can
be charged to and collected from customers at levels that will recover costs.
Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not
currently reflected 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. See Note 3 for discussion on decoupling revenue
deferrals.
If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory
accounting practices for all or a portion of its regulated operations, the Company could be:
required to write off its regulatory assets, and
precluded from the future deferral of costs or decoupled revenues not recovered through rates at the time such
amounts are incurred, even if the Company expected to recover these amounts from customers in the future.
Unamortized Debt Expense
Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt.
Unamortized Debt Repurchase Costs
For the Company’s Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, 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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.6
recovered or returned to customers through retail rates as a component of interest expense.
Appropriated Retained Earnings
In accordance with the hydroelectric licensing requirements of section 10(d) of the Federal Power Act (FPA), the Company maintains
an appropriated retained earnings account for any earnings in excess of the specified rate of return on the Company's investment in the
licenses for its various hydroelectric projects. Per section 10(d) of the FPA, the Company must maintain these excess earnings in an
appropriated retained earnings account until the termination of the licensing agreements or apply them to reduce the net investment in
the licenses of the hydroelectric projects at the discretion of the FERC. The Company calculates the earnings in excess of the
specified rate of return on an annual basis, usually during the second quarter.
The appropriated retained earnings amounts included in retained earnings were as follows as of December 31 (dollars in thousands):
2020 2019
Appropriated retained earnings $45,453 $41,179
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 loss contingencies that do not meet these conditions for accrual, if there is a reasonable possibility that a
material loss may be incurred. As of December 31, 2020, the Company has not recorded any significant amounts related to unresolved
contingencies. See Note 17 for further discussion of the Company's commitments and contingencies.
COVID-19
In 2020, the WUTC, IPUC, and OPUC approved accounting orders that allow the Company to defer certain net COVID-19 related
costs and benefits. As such, as of December 31, 2020, the Company has deferred a net benefit to customers of $2.8 million for all
jurisdictions.
The respective regulatory authorities will determine the appropriateness and prudency of any deferred expenses when the Company
seeks recovery. See “Regulatory Deferred Charges and Credits”.
Equity in Earnings (Losses) of Subsidiaries
The Company records all the earnings (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 31 (dollars in thousands):
2020 2019
Avista Capital $(2,491)$6,404
AERC 7,795 7,178
Total equity in earnings of subsidiary companies $5,304 $13,582
Subsequent Events
Management has evaluated the impact of events occurring after December 31, 2020 up to February 23, 2021, the date that Avista
Corp.’s U.S. GAAP financial statements were issued and has updated such evaluation for disclosure purposes through the date of this
filing. These financial statements include all necessary adjustments and disclosures resulting from these evaluations.
NOTE 2. NEW ACCOUNTING STANDARDS
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
Accounting Standards Update (ASU) No. 2016-02, "Leases (Topic 842)"
ASU No. 2018-01, "Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842"
ASU No. 2018-11, "Leases (Topic 842): Targeted Improvements"
On January 1, 2019, the Company adopted ASU No. 2016-02, which outlines a model for entities to use in accounting for leases and
supersedes previous lease accounting guidance, as well as several practical expedients in ASU Nos. 2018-01 and 2018-11.
The Company adopted ASU No. 2016-02 utilizing a modified retrospective adoption method with the "package of three" and
hindsight practical expedients offered by the standard. The "package of three" provides for an entity to not reassess at adoption
whether any expired or existing contracts are deemed, for accounting purposes, to be or contain leases, the classification of any
expired or existing leases, and any initial direct costs for any existing leases. As a result, the Company did not reassess existing or
expired contracts under the new lease guidance, and it did not reassess the classification of any existing leases. The Company used the
benefit of hindsight in determining both term and impairments associated with any existing leases. Use of this practical expedient has
resulted in lease terms that best represent management's expectations with respect to use of the underlying asset but did not result in
recognition of any impairment.
The Company elected to adopt ASU No. 2018-01, which allows an entity to exclude from application of Topic 842 all easements
executed prior to January 1, 2019. In addition, the Company elected to adopt the "comparatives under 840" practical expedient offered
in ASU No. 2018-11, which allows an entity to apply the new lease standard at the adoption date, recognizing any necessary
cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption and presenting comparative periods
in the financial statements under Accounting Standards Codification (ASC) 840 (previous lease accounting guidance). Adoption of
the standard did not result in a cumulative effect adjustment within the Company's financial statements.
As allowed by ASU No. 2016-02, the Company elected not to apply the requirements of the standard to short-term leases, those leases
with an initial term of 12 months or less. These leases are not recorded on the balance sheet and are not material to the financial
statements.
Adoption of the standard impacted the Company's Balance Sheets through recognition of right-of-use (ROU) assets and lease
liabilities for the Company's operating leases. Accounting for finance leases (formerly capital leases) remained substantially
unchanged. See Note 4 for further information on the Company's leases.
ASU 2018-13 "Fair Value Measurement (Topic 820)"
In August 2018, the FASB issued ASU No. 2018-13, which amends the fair value measurement disclosure requirements of ASC 820.
The requirements of this ASU include additional disclosure regarding the range and weighted average used to develop significant
unobservable inputs for Level 3 fair value estimates and the elimination of certain other previously required disclosures, such as the
narrative description of the valuation process for Level 3 fair value measurements. This ASU became effective on January 1, 2020
and the requirements of this ASU did not have a material impact on the Company's fair value disclosures. See Note 15 for the
Company's fair value disclosures.
ASU No. 2018-14 "Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20)"
In August 2018, the FASB issued ASU No. 2018-14, which amends ASC 715 to add, remove and/or clarify certain disclosure
requirements related to defined benefit pension and other postretirement plans. The additional disclosure requirements are primarily
narrative discussion of significant changes in the benefit obligations and plan assets. The removed disclosures are primarily
information about accumulated other comprehensive income expected to be recognized over the next year and the effects of changes
associated with assumed health care costs. This ASU became effective for periods ending after December 15, 2020 and the
requirements of this ASU did not have a material impact on the Company’s disclosures upon adoption.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
NOTE 3. REVENUE
ASC 606 defines the core principle of the revenue recognition 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.
Utility Revenues
Revenue from Contracts with Customers
General
The majority of Avista Corp.’s revenue is from rate-regulated sales of electricity and natural gas to retail customers, which has two
performance obligations, (1) having service available for a specified period (typically a month at a time) and (2) the delivery of
energy to customers. The total energy price generally has a fixed component (basic charge) related to having service available and a
usage-based component, related to the delivery and consumption of energy. The commodity is sold and/or delivered to and consumed
by the customer simultaneously, and the provisions of the relevant utility commission authorization determine the charges the
Company may bill the customer. Given that all revenue recognition criteria are met upon the delivery of energy to customers, revenue
is recognized immediately.
In addition, the sale of electricity and natural gas is governed by the various state utility commissions, which set rates, charges, terms
and conditions of service, and prices. Collectively, these rates, charges, terms and conditions are included in a “tariff,” which governs
all aspects of the provision of regulated services. Tariffs are only permitted to be changed through a rate-setting process involving an
independent, third-party regulator empowered by statute to establish rates that bind customers. Thus, all regulated sales by the
Company are conducted subject to the regulator-approved tariff.
Tariff sales involve the current provision of commodity service (electricity and/or natural gas) to customers for a price that generally
has a basic charge and a usage-based component. Tariff rates also include certain pass-through costs to customers such as natural gas
costs, retail revenue credits and other miscellaneous regulatory items that do not impact net income, but can cause total revenue to
fluctuate significantly up or down compared to previous periods. The commodity is sold and/or delivered to and consumed by the
customer simultaneously, and the provisions of the relevant tariff determine the charges the Company may bill the customer, payment
due date, and other pertinent rights and obligations of both parties. Generally, tariff sales do not involve a written contract. Given that
all revenue recognition criteria are met upon the delivery of energy to customers, revenue is recognized immediately at that time.
Unbilled Revenue from Contracts with Customers
The determination of the volume of energy sales to individual customers is based on the reading of their meters, which occurs on a
systematic basis throughout the month (once per month for each individual customer). 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. The Company's estimate of unbilled revenue is based on:
the number of customers,
current rates,
meter reading dates,
actual native load for electricity,
actual throughput for natural gas, and
electric line losses and natural gas system losses.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9
Any difference between actual and estimated revenue is automatically corrected in the following month when the actual meter reading
and customer billing occurs.
Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
2020 2019
Unbilled accounts receivable $68,545 $60,560
Non-Derivative Wholesale Contracts
The Company has certain wholesale contracts which are not accounted for as derivatives that are within the scope of ASC 606 and
considered revenue from contracts with customers. Revenue is recognized as energy is delivered to the customer or the service is
available for specified period of time, consistent with the discussion of tariff sales above.
Alternative Revenue Programs (Decoupling)
ASC 606 specifies that alternative revenue programs are contracts between an entity and a regulator of utilities, not a contract between
an entity and a customer. GAAP requires that an entity present revenue arising from alternative revenue programs separately from
revenues arising from contracts with customers on the face of the Statements of Income. The Company's decoupling mechanisms
(also known as a FCA in Idaho) qualify as alternative revenue programs. Decoupling revenue deferrals are recognized in the
Statements of Income during the period they occur (i.e. during the period of revenue shortfall or excess due to fluctuations in
customer usage), subject to certain limitations, and a regulatory asset or liability is established which will be surcharged or rebated to
customers in future periods. GAAP requires that for any alternative revenue program, like decoupling, the revenue must be expected
to be collected from customers within 24 months of the deferral to qualify for recognition in the current period Statements 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. The amounts expected to be
collected from customers within 24 months represents an estimate which must be made by the Company on an ongoing basis due to it
being based on the volumes of electric and natural gas sold to customers on a go-forward basis.
The Company records alternative program revenues under the gross method, which is to amortize the decoupling regulatory
asset/liability to the alternative revenue program line item on the Statements of Income as it is collected from or refunded to
customers. The cash passing between the Company and the customers is presented in revenue from contracts with customers since it
is a portion of the overall tariff paid by customers. This method results in a gross-up to both revenue from contracts with customers
and revenue from alternative revenue programs, but has a net zero impact on total revenue. Depending on whether the previous
deferral balance being amortized was a regulatory asset or regulatory liability, and depending on the size and direction of the current
year deferral of surcharges and/or rebates to customers, it could result in negative alternative revenue program revenue during the
year.
Derivative Revenue
Most wholesale electric and natural gas transactions (including both physical and financial transactions), and the sale of fuel are
considered derivatives, which are scoped out of ASC 606. As such, these revenues are disclosed separately from revenue from
contracts with customers. Revenue is recognized for these items upon the settlement/expiration of the derivative contract. Derivative
revenue includes those transactions which are entered into and settled within the same month.
Other Utility Revenue
Other utility revenue includes rent, revenues from the lineman training school, sales of materials, late fees and other charges that do
not represent contracts with customers. Other utility revenue also includes the provision for earnings sharing and the deferral and
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10
amortization of refunds to customers associated with the Tax Cuts and Jobs Act, enacted in December 2017. This revenue is scoped
out of ASC 606, as this revenue does not represent items where a customer is a party that has contracted with the Company to obtain
goods or services that are an output of the Company’s ordinary activities in exchange for consideration. As such, these revenues are
presented separately from revenue from contracts with customers.
Other Considerations for Utility Revenues
Contracts with Multiple Performance Obligations
In addition to the tariff sales described above, which are stand-alone energy sales, the Company has bundled arrangements which
contain multiple performance obligations including some combination of energy, capacity, energy reserves and RECs. Under these
arrangements, the total contract price is allocated to the various performance obligations and revenue is recognized as the obligations
are satisfied. Depending on the source of the revenue, it could either be included in revenue from contracts with customers or
derivative revenue.
Gross Versus Net Presentation
Utility-related taxes collected from customers (primarily state excise taxes and city utility taxes) are taxes that are imposed on Avista
Corp. as opposed to being imposed on its customers; therefore, Avista Corp. is the taxpayer and records these transactions on a gross
basis in revenue from contracts with customers and operating expense (taxes other than income taxes).
Utility-related taxes that were included in revenue from contracts with customers were as follows for the years ended December 31
(dollars in thousands):
2020 2019
Utility-related taxes $59,319 $59,528
Significant Judgments and Unsatisfied Performance Obligations
The vast majority of the Company's revenues are derived from the rate-regulated sale of electricity and natural gas that have two
performance obligations that are satisfied throughout the period and as energy is delivered to customers. In addition, the customers do
not pay for energy in advance of receiving it. As such, the Company does not have any significant unsatisfied performance
obligations or deferred revenues as of period-end associated with these revenues. Also, the only significant judgments involving
revenue recognition are estimates surrounding unbilled revenue and receivables from contracts with customers (discussed in detail
above) and estimates surrounding the amount of decoupling revenues which will be collected from customers within 24 months.
The Company has certain capacity arrangements, where the Company has a contractual obligation to provide either electric or natural
gas capacity to its customers for a fixed fee. Most of these arrangements are paid for in arrears by the customers and do not result in
deferred revenue and only result in receivables from the customers. The Company does have one capacity agreement where the
customer makes payments throughout the year, and depending on the timing of the customer payments, it can result in an immaterial
amount of deferred revenue or a receivable from the customer. As of December 31, 2020, the Company estimates it had unsatisfied
capacity performance obligations of $23.8 million, which will be recognized as revenue in future periods as the capacity is provided
to the customers. These performance obligations are not reflected in the financial statements, as the Company has not received
payment for these services.
Disaggregation of Total Operating Revenue
The following table disaggregates total operating revenue by source for the years ended December 31 (dollars in thousands):
2020 2019
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11
Avista Corp.
Revenue from contracts with customers $1,168,207 $1,160,853
Derivative revenues 203,099 246,355
Alternative revenue programs (3,814) 9,614
Deferrals and amortizations for rate refunds to customers 4,795 1,093
Other utility revenues 7,589 10,184
Total Avista Corp. 1,379,876 1,428,099
Utility Revenue from Contracts with Customers by Type and Service
The following table disaggregates revenue from contracts with customers associated with the Company's electric operations for the
years ended December 31 (dollars in thousands):
2020 2019
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential
$
377,78
5 $
369,10
2
Commercial and governmental 303,97
2
317,58
9
Industrial 113,56
3
114,53
0
Public street and highway lighting 7,304 7,448
Total retail revenue 802,62
4
808,66
9
Transmission 18,236 18,180
Other revenue from contracts
with customers 19,252 26,969
Total revenue from contracts
with customers $
840,11
2 $
853,81
8
The following table disaggregates revenue from contracts with customers associated with the Company's natural gas operations for
the years ended December 31 (dollars in thousands):
2020 2019
Avista Corp. Avista Corp.
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential $213,612 $196,430
Commercial 94,937 92,168
Industrial and interruptible 7,128 5,263
Total retail revenue 315,677 293,861
Transportation 7,917 8,674
Other revenue from contracts with customers 4,501 4,500
Total revenue from contracts with customers $328,095 $307,035
NOTE 4. LEASES
ASC 842, which outlines a model for entities to use in accounting for leases and supersedes previous lease accounting guidance,
became effective on January 1, 2019. The core principle of the model is that an entity should recognize the ROU assets and liabilities
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
that arise from leases on the balance sheet and depreciate or amortize the asset and liability over the term of the lease, as well as
provide disclosure to enable users of the financial statements to assess the amount, timing, and uncertainty of cash flows arising from
leases. For regulatory reporting, the FERC provided prescribed accounts for the ROU assets and lease liabilities, with the ROU assets
being included in utility plant (FERC account 101) and the lease liabilities being included in capital lease obligations (FERC account
227). These accounts are different than the accounts allowed for in GAAP reporting, which results in a FERC/GAAP difference.
Significant Judgments and Assumptions
The Company determines if an arrangement is a lease, as well as its classification, at its inception.
ROU assets represent the Company's right to use an underlying asset for the lease term, and lease liabilities represent the Company's
obligation to make lease payments arising from the lease. Operating lease ROU assets and lease liabilities are recognized at the
commencement date of the agreement based on the present value of lease payments over the lease term. As most of the Company's
leases do not provide an implicit rate, the Company uses its incremental borrowing rate based on the information available at the
commencement date to determine the present value of lease payments. The implicit rate is used when it is readily determinable. The
operating lease ROU assets also include any lease payments made and exclude lease incentives, if any, that accrue to the benefit of the
lessee.
Lease terms may include options to extend or terminate the lease when it is reasonably certain that the Company will exercise that
option. Lease expense for lease payments is recognized on a straight-line basis over the lease term. Any difference between lease
expense and cash paid for leased assets is recognized as a regulatory asset or regulatory liability.
Description of Leases
Operating Leases
The Company's most significant operating lease is with the State of Montana associated with submerged land around the Company's
hydroelectric facilities in the Clark Fork River basin, which expires in 2046. The terms of this lease are subject to renegotiation,
depending on the outcome of ongoing litigation between Montana and NorthWestern Energy. In addition, the State of Montana and
Avista Corp. are engaged in litigation regarding lease terms, including how much money, if any, the State of Montana will return to
Avista Corp. The Company is currently paying all lease payments to the State of Montana into an escrow account until the litigation is
resolved. As such, amounts recorded for this lease are uncertain and amounts may change in the future depending on the outcome of
the ongoing litigation. Any reduction in future lease payments or the return of previously paid amounts to Avista Corp. will be
included in the future ratemaking process.
In addition to the lease with the State of Montana, the Company also has other operating leases for land associated with its utility
operations, as well as communication sites which support network and radio communications within its service territory. The
Company's leases have remaining terms of 1 to 73 years. Most of the Company's leases include options to extend the lease term for
periods of 5 to 50 years. Options are exercised at the Company's discretion.
Certain of the Company's lease agreements include rental payments which are periodically adjusted over the term of the agreement
based on the consumer price index. The Company's lease agreements do not include any material residual value guarantees or material
restrictive covenants.
Avista Corp. does not record leases with a term of 12 months or less in the Balance Sheets. Total short-term lease costs for the year
ended December 31, 2020 are immaterial.
The components of lease expense were as follows for the year ended December 31 (dollars in thousands):
2020 2019
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
Operating lease cost:
Fixed lease cost $4,746 $4,425
Variable lease cost 1,099 988
Total operating lease cost $5,845 $5,413
Supplemental cash flow information related to leases was as follows for the year ended December 31 (dollars in thousands):
2020 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash outflows:
Operating lease payments $4,612 $4,375
Supplemental balance sheet information related to leases was as follows for December 31 (dollars in thousands):
December 31, December 31,
2020 2019
Operating Leases
Operating lease ROU assets (Utility Plant) $71,891 $69,746
Obligations under capital lease - current $4,249 $4,128
Obligations under capital lease - noncurrent 67,716 65,565
Total operating lease liabilities $71,965 $69,693
Weighted Average Remaining Lease Term
Operating leases 25.20 years 26.60 years
Weighted Average Discount Rate
Operating leases 4.28% 3.82%
Maturities of lease liabilities (including principal and interest) were as follows as of December 31, 2020 (dollars in thousands):
Operating Leases
2021 $4,779
2022 4,799
2023 4,827
2024 4,852
2025 4,865
Thereafter 96,734
Total lease payments $120,856
Less: imputed interest (48,891)
Total $71,965
Maturities of lease liabilities (including principal and interest) were as follows as of December 31, 2019 (dollars in thousands):
Operating Leases
2020 $4,372
2021 4,375
2022 4,383
2023 4,399
2024 4,411
Thereafter 91,654
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
Total lease payments $113,594
Less: imputed interest (43,901)
Total $69,693
NOTE 5. DERIVATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel
prices. Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily
by supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments.
Avista Corp. utilizes derivative instruments, such as forwards, futures, swap derivatives and options in order to manage the various
risks relating to these commodity price exposures. Avista Corp. has an energy resources risk policy and control procedures to manage
these risks.
As part of Avista Corp.'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 Avista
Corp.'s load obligations and the use of these resources to capture available economic value through wholesale market transactions.
These include sales and purchases of electric capacity and energy, fuel for electric generation, and derivative contracts related to
capacity, energy and fuel. Such transactions are part of the process of matching resources with load obligations and hedging a portion
of the related financial risks. These transactions range from terms of intra-hour up to multiple years.
As part of its resource procurement and management of its natural gas business, Avista Corp. makes continuing projections of its
natural gas loads and assesses available natural gas resources including natural gas storage availability. Natural gas resource planning
typically includes peak requirements, low and average monthly requirements and delivery constraints from natural gas supply
locations to Avista Corp.'s distribution system. However, daily variations in natural gas demand can be significantly different than
monthly demand projections. On the basis of these projections, Avista Corp. plans and executes a series of transactions to hedge a
portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions
may extend as much as three 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.
Avista Corp. plans for sufficient natural gas delivery capacity to serve its retail customers for a theoretical peak day event. Avista
Corp. generally has more pipeline and storage capacity than what is needed during periods other than a peak day. Avista Corp.
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 Avista Corp. should buy or sell natural gas during other times in the year, Avista Corp. engages in
optimization transactions to capture value in the marketplace. Natural gas optimization activities include, but are not limited to,
wholesale market sales of surplus natural gas supplies, purchases and sales of natural gas to optimize use of pipeline and storage
capacity, and participation in the transportation capacity release market.
The following table presents the underlying energy commodity derivative volumes as of December 31, 2020 that are expected to be
delivered in each respective year (in thousands of MWhs and mmBTUs):
Purchases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives
Year
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15
2021 1 224 10,353 65,188 17 451 5,448 39,273
2022 — — 450 25,525 — — 1,360 12,030
2023 — — — 4,950 — — 1,360 900
2024 — — — — — — 1,370 —
2025 — — — — — — 1,115 —
As of December 31, 2020, there are no expected deliveries of energy commodity derivatives after 2025.
The following table presents the underlying energy commodity derivative volumes as of December 31, 2019 that were expected to be
delivered in each respective year (in thousands of MWhs and mmBTUs):
Purchases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives
Year
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
Physical (1)
MWh
Financial (1)
MWh
Physical (1)
mmBTUs
Financial (1)
mmBTUs
2020 2 442 9,813 78,803 133 1,724 2,984 37,848
2021 — — 153 25,523 — 246 1,040 13,108
2022 — — 225 4,725 — — — 675
As of December 31, 2019, there were no expected deliveries of energy commodity derivatives after 2022.
(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 the benefit or
cost but with no physical delivery of the commodity, such as futures, swap derivatives, 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 delivered and will be included in the various deferral and recovery mechanisms (ERM, PCA, and PGAs), or in the
general rate case process, and are expected to be collected through retail rates from customers.
Foreign Currency Exchange Derivatives
A significant portion of Avista Corp.'s natural gas supply (including fuel for power generation) is obtained from Canadian sources.
Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.’s short-term
natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled
within 60 days with U.S. dollars. Avista Corp. hedges a portion of the foreign currency risk by purchasing Canadian currency
exchange 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 Avista Corp.’s financial condition, results of operations or cash flows and these
differences in cost related to currency fluctuations are included with natural gas supply costs for ratemaking.
The following table summarizes the foreign currency exchange derivatives that Avista Corp. has outstanding as of December 31
(dollars in thousands):
2020 2019
Number of contracts 22 20
Notional amount (in United States dollars) $3,860 $5,932
Notional amount (in Canadian dollars)4,949 7,828
Interest Rate Swap Derivatives
Avista Corp. is affected by fluctuating interest rates related to a portion of its existing debt, and future borrowing requirements. Avista
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16
Corp. hedges a portion of its interest rate risk with financial derivative instruments. These financial derivative instruments 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 Avista Corp. 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, 2020 4 45,000 2021
11 120,000 2022
1 10,000 2023
December 31, 2019 7 70,000 2020
3 35,000 2021
10 110,000 2022
See Note 13 for discussion of the bond purchase agreement and the related settlement of interest rate swaps in connection with the
pricing of the bonds in June 2020.
The fair value of outstanding interest rate swap derivatives can vary significantly from period to period depending on the total
notional amount of swap derivatives outstanding and fluctuations in market interest rates compared to the interest rates fixed by the
swaps. Avista Corp. is required to make cash payments to settle the interest rate swap derivatives when the fixed rates are higher than
prevailing market rates at the date of settlement. Conversely, Avista Corp. receives cash to settle its interest rate swap derivatives
when prevailing market rates at the time of settlement exceed the fixed swap rates.
Summary of Outstanding Derivative Instruments
The amounts recorded on the Balance Sheets as of December 31, 2020 and December 31, 2019 reflect the offsetting of derivative
assets and liabilities where a legal right of offset exists.
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheets as of
December 31, 2020 (in thousands):
Fair Value
Derivative and Balance Sheet Location
Gross
Asset
Gross
Liability
Collateral
Netting
Net Asset
(Liability)
on Balance
Sheet
Foreign currency exchange derivatives
Derivative instrument assets current $30 $— $— $30
Interest rate swap derivatives
Derivative instrument liabilities current — (19,575) 8,050 (11,525)
Long-term portion of derivative liabilities 952 (32,190) — (31,238)
Energy commodity derivatives
Derivative instrument assets current 9,203 (8,306) — 897
Long-term portion of derivative assets 1,755 (1,159) — 596
Derivative instrument liabilities current 11,037 (14,007) 487 (2,483)
Long-term portion of derivative liabilities 1,725 (8,043) 129 (6,189)
Total derivative instruments recorded on the
balance sheet $24,702 $(83,280) $8,666 $(49,912)
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheets as of
December 31, 2019 (in thousands):
Fair Value
Derivative and Balance Sheet Location
Gross
Asset
Gross
Liability
Collateral
Netting
Net Asset
(Liability)
on Balance
Sheet
Foreign currency exchange derivatives
Derivative instrument assets current $97 $— $— $97
Interest rate swap derivatives
Derivative instrument assets current 589 — — 589
Derivative instrument liabilities current 238 (9,379) 1,316 (7,825)
Long-term portion of derivative liabilities 725 (24,677) 5,454 (18,498)
Energy commodity derivatives
Derivative instrument assets 416 (245) — 171
Long-term portion of derivative assets 6,369 (5,446) — 923
Derivative instrument liabilities current 34,760 (41,241) 3,378 (3,103)
Long-term portion of derivative liabilities 28 (1,215) — (1,187)
Total derivative instruments recorded on the
balance sheet $43,222 $(82,203) $10,148 $(28,833)
Exposure to Demands for Collateral
Avista Corp.'s derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or
reductions or terminations of a portion of the contract through cash settlement. In the event of a downgrade in Avista Corp.'s credit
ratings or changes in market prices, additional collateral may be required. In periods of price volatility, the level of exposure can
change significantly. As a result, sudden and significant demands may be made against Avista Corp.'s credit facilities and cash. Avista
Corp. actively monitors the exposure to possible collateral calls and takes steps to mitigate capital requirements.
The following table presents Avista Corp.'s collateral outstanding related to its derivative instruments as of December 31 (in
thousands):
2020 2019
Energy commodity derivatives
Cash collateral posted $4,953 $7,812
Letters of credit outstanding 23,500 17,400
Balance sheet offsetting (cash collateral against net derivative positions)616 3,378
Interest rate swap derivatives
Cash collateral posted (offset by net derivative positions)8,050 6,770
There were no letters of credit outstanding related to interest rate swap derivatives as of December 31, 2020 and December 31, 2019.
Certain of Avista Corp.’s derivative instruments contain provisions that require the Company to maintain an "investment grade" credit
rating from the major credit rating agencies. If Avista Corp.’s credit ratings were to fall below “investment grade,” it would be in
violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand
immediate and ongoing collateralization on derivative instruments in net liability positions.
The following table presents the aggregate fair value of all derivative instruments with credit-risk-related contingent features that are
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.18
in a liability position and the amount of additional collateral Avista Corp. could be required to post as of December 31 (in thousands):
2020 2019
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features $50,813 $34,056
Additional collateral to post 42,763 26,912
NOTE 6. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in Units 3 & 4 of the Colstrip generating station, a coal-fired plant located in
southeastern Montana, and provides financing for its ownership interest in the project. Pursuant to the ownership and operating
agreements among the co-owners, the Company’s share of related fuel costs as well as operating expenses for plant in service are
included in the corresponding accounts in the Statements of Income. The Company’s share of utility plant in service for Colstrip and
accumulated depreciation (inclusive of the ARO assets and accumulated amortization) were as follows as of December 31 (dollars in
thousands):
2020 2019
Utility plant in service $391,922 $387,860
Accumulated depreciation (284,282) (268,637)
See Note 7 for further discussion of AROs.
While the obligations and liabilities with respect to Colstrip are to be shared among the co-owners on a pro-rata basis, many of the
environmental liabilities are joint and several under the law, so that if any co-owner failed to pay its share of such liability, the other
co-owners (or any one of them) could be required to pay the defaulting co-owner‘s share (or the entire liability).
NOTE 7. ASSET RETIREMENT OBLIGATIONS
The Company has recorded liabilities for future AROs to:
restore coal ash containment ponds and coal holding areas at Colstrip,
cap a landfill at the Kettle Falls Plant, and
remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease.
Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:
removal and disposal of certain transmission and distribution assets, and
abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.
In 2015, the EPA issued a final rule regarding CCRs. Colstrip, of which Avista Corp. is a 15 percent owner of Units 3 & 4, produces
this byproduct. The CCR rule has been the subject of ongoing litigation. In August 2018, the D.C. Circuit struck down provisions of
the rule. The rule includes technical requirements for CCR landfills and surface impoundments. The Colstrip owners developed a
multi-year compliance plan to address the CCR requirements and existing state obligations.
The actual asset retirement costs related to the CCR rule requirements may vary substantially from the estimates used to record the
ARO due to the uncertainty and evolving nature of the compliance strategies that will be used and the availability of 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. The Company updates its estimates as new information becomes available. The Company expects to seek
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19
recovery of any increased costs related to complying with the CCR rule through customer rates.
In addition to the above, under a 2018 Administrative Order on Consent and ongoing negotiations with the Montana Department of
Ecological Quality, the owners of Colstrip are required to provide financial assurance, primarily in the form of surety bonds, to secure
each owner's pro-rata share of various anticipated closure and remediation of the ash ponds and coal holding areas. The amount of
financial assurance required of each owner may, like the ARO, vary substantially due to the uncertainty and evolving nature of
anticipated closure and remediation activities, and as those activities are completed over time.
The following table documents the changes in the Company’s asset retirement obligation during the years ended December 31
(dollars in thousands):
2020 2019
Asset retirement obligation at beginning of year $20,338 $18,266
Liabilities incurred (2,315) 2,699
Liabilities settled (1,645) (1,503)
Accretion expense 816 876
Asset retirement obligation at end of year $17,194 $20,338
NOTE 8. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The pension and other postretirement benefit plans described below only relate to Avista Corp. AEL&P (not discussed below)
participates in a defined contribution multiemployer plan for its union workers and a defined contribution money purchase pension
plan for its nonunion workers. None of the subsidiary retirement plans, individually or in the aggregate, are significant to Avista Corp.
Avista Corp.
The Company has a defined benefit pension plan covering the majority of all regular full-time employees at Avista Corp. that were
hired prior to January 1, 2014. Individual benefits under this plan are based upon the employee’s years of service, date of hire and
average compensation as specified in the plan. Non-union employees hired on or after January 1, 2014 participate in a defined
contribution 401(k) plan in lieu of a defined benefit pension plan. Union employees hired on or after January 1, 2014 are still covered
under the defined benefit pension plan. The Company’s funding policy is to contribute at least the minimum amounts that are required
to be funded under the Employee Retirement Income Security Act, but not more than the maximum amounts that are currently
deductible for income tax purposes. The Company contributed $22.0 million in cash to the pension plan in 2020 and 2019. The
Company expects to contribute $42.0 million in cash to the pension plan in 2021.
The Company also has a SERP that provides additional pension benefits to certain executive officers and certain key employees of the
Company. The SERP is intended to provide benefits to individuals whose benefits under the defined benefit pension plan are reduced
due to the application of Section 415 of the Internal Revenue Code of 1986 and the deferral of salary under deferred compensation
plans. The liability and expense for this plan are included as pension benefits in the tables included in this Note.
The Company expects that benefit payments under the pension plan and the SERP will total (dollars in thousands):
2021 2022 2023 2024 2025
Total 2026-
2030
Expected benefit payments
$42,390 $42,673 $42,478 $43,149 $43,752 $
223,78
8
The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments
held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20
maturities similar to that of the expected term of pension benefits.
The Company provides certain health care and life insurance benefits for eligible retired employees that were hired prior to January 1,
2014. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services.
The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January 1,
2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution
toward their medical premium.
The Company has a Health Reimbursement Arrangement (HRA) to provide employees with tax-advantaged funds to pay for
allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the
employee’s years of service and the ending salary. The liability and expense of the HRA are included as other postretirement benefits.
The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement.
Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base
salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension
benefit). The liability and expense for this plan are included as other postretirement benefits.
The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):
2021 2022 2023 2024 2025
Total
2026-
2030
Expected benefit payments $6,610 $6,800 $6,891 $7,021 $7,164 $37,156
The Company expects to contribute $6.8 million to other postretirement benefit plans in 2021, representing expected benefit payments
to be paid during the year excluding the Medicare Part D subsidy. The Company uses a December 31 measurement date for its
pension and other postretirement benefit plans.
The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2020 and 2019 and the
components of net periodic benefit costs for the years ended December 31, 2020 and 2019 (dollars in thousands):
Pension Benefits
Other Post-
retirement Benefits
2020 2019 2020 2019
Change in benefit obligation:
Benefit obligation as of beginning of year $742,382 $671,629 $159,296 $134,053
Service cost 22,392 19,755 3,902 3,006
Interest cost 27,853 28,417 6,042 5,598
Actuarial (gain)/loss 74,688 57,829 (2,589) 23,344
Benefits paid (40,400) (35,248) (5,418) (6,705)
Benefit obligation as of end of year $826,915 $742,382 $161,233 $159,296
Change in plan assets:
Fair value of plan assets as of beginning of year $642,063 $544,051 $44,853 $36,852
Actual return on plan assets 96,591 109,942 7,320 8,001
Employer contributions 22,000 22,000 — —
Benefits paid (38,630) (33,930) — —
Fair value of plan assets as of end of year $722,024 $642,063 $52,173 $44,853
Funded status $(104,891) $(100,319) $(109,060) $(114,443)
Amounts recognized in the Balance Sheets:
Current liabilities $(1,943) $(1,602) $(669) $(640)
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
Non-current liabilities (102,948) (98,717) (108,391) (113,803)
Net amount recognized $(104,891) $(100,319) $(109,060) $(114,443)
Accumulated pension benefit obligation $710,023 $644,004
Accumulated postretirement benefit obligation:
For retirees $75,876 $72,816
For fully eligible employees $32,097 $34,545
For other participants $53,260 $51,935
Included in accumulated other comprehensive loss (income) (net of tax):
Unrecognized prior service cost $1,902 $2,105 $(3,570) $(4,400)
Unrecognized net actuarial loss 119,318 114,368 53,737 63,101
Total 121,220 116,473 50,167 58,701
Less regulatory asset (108,301) (107,395) (48,708) (57,520)
Accumulated other comprehensive loss for unfunded
benefit
obligation for pensions and other postretirement benefit
plans $12,919 $9,078 $1,459 $1,181
Pension Benefits
Other Post-
retirement Benefits
2020 2019 2020 2019
Weighted-average assumptions as of December 31:
Discount rate for benefit obligation 3.25% 3.85% 3.27% 3.89%
Discount rate for annual expense 3.85% 4.31% 3.89% 4.32%
Expected long-term return on plan assets 5.50% 5.90% 5.30% 5.70%
Rate of compensation increase 4.74% 4.66%
Medical cost trend pre-age 65 – initial 6.25% 5.75%
Medical cost trend pre-age 65 – ultimate 5.00% 5.00%
Ultimate medical cost trend year pre-age 65 2026 2023
Medical cost trend post-age 65 – initial 6.25% 6.50%
Medical cost trend post-age 65 – ultimate 5.00% 5.00%
Ultimate medical cost trend year post-age 65 2026 2026
Pension Benefits
Other Post-retirement
Benefits
2020 2019 2020 2019
Components of net periodic benefit cost:
Service cost (a) $22,392 $19,755 $3,902 $3,006
Interest cost 27,853 28,417 6,042 5,598
Expected return on plan assets (34,886) (31,763) (2,377) (2,101)
Amortization of prior service cost 257 257 (958) (981)
Net loss recognition 6,717 10,216 4,871 4,013
Net periodic benefit cost $22,333 $26,882 $11,480 $9,535
(a)(a) Total service costs in the table above are recorded to the same accounts as labor expense. Labor and benefits expense is
recorded to various projects based on whether the work is a capital project or an operating expense. Approximately 40
percent of all labor and benefits is capitalized to utility property and 60 percent is expensed to utility other operating
expenses.
Plan Assets
The Finance Committee of the Company’s Board of Directors approves investment policies, objectives and strategies that seek an
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22
appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and
funding policies.
The Company has contracted with investment consultants who are responsible for monitoring the individual investment managers.
The investment managers’ performance and related individual fund performance is periodically reviewed by an internal benefits
committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies.
Pension plan assets are invested in mutual funds, trusts and partnerships that hold marketable debt and equity securities, real estate,
and absolute return. In seeking to obtain a return that aligns with the funded status of the pension plan, the investment consultant
recommends allocation percentages by asset classes. These recommendations are reviewed by the internal benefits committee, which
then recommends their adoption by the Finance Committee. The Finance Committee has established target investment allocation
percentages by asset classes and also investment ranges for each asset class. The target investment allocation percentages are typically
the midpoint of the established range. The target investment allocation percentages by asset classes are indicated in the table below:
2020 2019
Equity securities 35% 35%
Debt securities 49% 49%
Real estate 7% 7%
Absolute return 9% 9%
The target investment allocation percentages were revised in the first quarter of 2021 and the pension plan assets are being reinvested
to move toward the new target investment allocation percentages of 55 percent equity securities, 40 percent debt securities, 5 percent
real estate and 0 percent absolute return. The target asset allocation percentages were modified to better align the asset allocations
with the funded status of the pension 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).
Pension plan and other postretirement plan assets whose fair values are measured using net asset value (NAV) are excluded from the
fair value hierarchy and are included as reconciling items in the tables below.
The Company's investments in common/collective trusts have redemption limitations that permit quarterly redemptions following
notice requirements of 45 to 60 days. 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 following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of the
pension plan’s assets measured and reported as of December 31, 2020 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Cash equivalents $— $3,309 $— $3,309
Fixed income securities:
U.S. government issues — 10,990 — 10,990
Corporate issues — 279,857 — 279,857
International issues — 39,634 — 39,634
Municipal issues — 22,431 — 22,431
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
Mutual funds:
U.S. equity securities 146,375 — — 146,375
International equity securities 96,311 — — 96,311
Absolute return (1)11,640 — — 11,640
Plan assets measured at NAV (not subject to hierarchy
disclosure)
Common/collective trusts:
Real estate — — — 29,532
Partnership/closely held investments:
Absolute return (1)— — — 47,188
International equity securities — — — 26,760
Real estate — — — 7,997
Total $254,326 $356,221 $— $722,024
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of the
pension plan’s assets measured and reported as of December 31, 2019 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Cash equivalents $— $2,852 $— $2,852
Fixed income securities:
U.S. government issues — 37,297 — 37,297
Corporate issues — 207,222 — 207,222
International issues — 35,836 — 35,836
Municipal issues — 23,539 — 23,539
Mutual funds:
U.S. equity securities 173,568 — — 173,568
International equity securities 46,416 — — 46,416
Absolute return (1)16,720 — — 16,720
Plan assets measured at NAV (not subject to hierarchy
disclosure)
Common/collective trusts:
Real estate — — — 31,473
Partnership/closely held investments:
Absolute return (1)— — — 59,260
Real estate — — — 7,880
Total $236,704 $306,746 $— $642,063
(1) This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven,
relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income,
and (d) market neutral strategies.
The fair value of other postretirement plan assets invested in debt and equity securities was based primarily on market prices. The fair
value of investment securities traded on a national securities exchange is determined based on the last reported sales price; securities
traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market prices are not
readily available 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 2020 and 2019.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
The fair value of other postretirement plan assets was determined as of December 31, 2020 and 2019.
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of
other postretirement plan assets measured and reported as of December 31, 2020 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Balanced index mutual fund (1) $52,173 $— $— $52,173
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of
other postretirement plan assets measured and reported as of December 31, 2019 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Balanced index mutual fund (1) $44,853 $— $— $44,853
(1)The balanced index fund for 2020 and 2019 is a single mutual fund that includes a percentage of U.S. equity and fixed
income securities and International equity and fixed income securities.
401(k) Plans and Executive Deferral Plan
Avista Corp. has a salary deferral 401(k) plan 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):
2020 2019
Employer 401(k) matching contributions $11,742 $10,412
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. Deferred compensation funds are held by the Company in a Rabbi Trust.
There were deferred compensation assets and corresponding deferred compensation liabilities on the Balance Sheets of the following
amounts as of December 31 (dollars in thousands):
2020 2019
Deferred compensation assets and liabilities $9,174 $8,948
NOTE 9. ACCOUNTING FOR INCOME TAXES
The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company
evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that
deferred income tax assets will be realized.
As of December 31, 2020, the Company had $18.3 million of state tax credit carryforwards. Of the total amount, the Company
believes that it is more likely than not that it will only be able to utilize $8.6 million of the state tax credits. As such, the Company has
recorded a valuation allowance of $9.7 million against the state tax credit carryforwards and reflected the net amount of $8.6 million
as an asset as of December 31, 2020. State tax credits expire from 2021 to 2034.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
Status of Internal Revenue Service (IRS) and State Examinations
The Company and its eligible subsidiaries file federal income tax returns. All tax years after 2016 are open for an IRS tax
examination.
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 Idaho State Tax Commission is currently reviewing tax years 2014 through 2017. All tax years after 2016 are open for
examination in Montana and Oregon, and all tax years after 2017 are open for examination in Idaho.
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.
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 31 (dollars in thousands):
2020 2019
Utility power resources $324,297 $376,769
The following table details Avista Corp.’s future contractual commitments for power resources (including transmission contracts) and
natural gas resources (including transportation contracts) (dollars in thousands):
2021 2022 2023 2024 2025 Thereafter Total
Power resources
$
181,87
2 $
177,78
6 $
173,53
6 $
157,22
1 $
157,88
7 $849,444 $
1,697,74
6
Natural gas resources 67,717 52,158 42,499 35,598 32,473 241,145 471,590
Total
$
249,58
9 $
229,94
4 $
216,03
5 $
192,81
9 $
190,36
0 $
1,090,58
9 $
2,169,33
6
These energy purchase contracts were entered into as part of Avista Corp.’s obligation to serve its retail electric and natural gas
customers’ energy requirements, including contracts entered into for resource optimization. As a result, these costs are recovered
either through base retail rates or adjustments to retail rates as part of the power and natural gas cost deferral and recovery
mechanisms.
The above future contractual commitments for power resources include fixed contractual amounts related to the Company's contracts
with certain Public Utility Districts (PUD) to purchase portions of the output of certain generating facilities. Although Avista Corp.
has no investment in the PUD generating facilities, the fixed contracts obligate Avista Corp. to pay certain minimum amounts 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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
with the revenue bonds outstanding at December 31, 2020 (principal and interest) was $63.7 million.
In addition, Avista Corp. has operating agreements, settlements and other contractual obligations related to its generating facilities and
transmission and distribution services. The expenses associated with these agreements are reflected as other operating expenses in the
Statements of Income. The following table details future contractual commitments under these agreements (dollars in thousands):
2021 2022 2023 2024 2025 Thereafter Total
Contractual obligations
$
33,88
5 $
31,33
9 $
32,08
3 $
35,68
2 $
33,70
6 $
208,52
6 $
375,22
1
NOTE 11. NOTES PAYABLE
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million. During 2020, the
Company amended and extended, for one additional year, the revolving line of credit agreement for a revised expiration date of April
2022, with the option to extend for an additional one year period. The committed line of credit is secured by non-transferable first
mortgage bonds of the Company issued to the agent bank that would only become due and payable in the event, and then only to the
extent, that the Company defaults on its obligations under the committed line of credit.
The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant
which does not permit the ratio of “ consolidated total debt” to “consolidated total capitalization” of Avista Corp. to be greater than 65
percent at any time. As of December 31, 2020, 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):
2020 2019
Balance outstanding at end of period $102,000 $182,300
Letters of credit outstanding at end of period $27,618 $21,473
Average interest rate at end of period 1.22%2.64%
As of December 31, 2020 and 2019, the borrowings outstanding under Avista Corp.'s committed line of credit were classified as
short-term borrowings on the Balance Sheets.
NOTE 12. CREDIT AGREEMENT
In April 2020, the Company entered into a Credit Agreement with various financial institutions, in the amount of $100 million with an
expiration date of April 2021. Indebtedness under this agreement is unsecured.
The Credit Agreement contains customary covenants and default provisions, including a covenant not to permit the ratio of
"consolidated total debt" to "consolidated total capitalization" of Avista Corp. to be greater than 65 percent at any time.
The Company borrowed the entire $100 million available under this agreement.
NOTE 13. BONDS
The following details long-term debt outstanding as of December 31 (dollars in thousands):
Maturity
Year Description
Interest
Rate 2020 2019
Avista Corp. Secured Long-Term Debt
2020 First Mortgage Bonds 3.89%— 52,000
2022 First Mortgage Bonds 5.13%250,000 250,000
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
2023
Secured Medium-Term Notes
7.18%-7.54
%13,500 13,500
2028 Secured Medium-Term Notes 6.37%25,000 25,000
2032 Secured Pollution Control Bonds (1)(1)66,700 66,700
2034 Secured Pollution Control Bonds (1)(1)17,000 17,000
2035 First Mortgage Bonds 6.25%150,000 150,000
2037 First Mortgage Bonds 5.70%150,000 150,000
2040 First Mortgage Bonds 5.55%35,000 35,000
2041 First Mortgage Bonds 4.45%85,000 85,000
2044 First Mortgage Bonds 4.11%60,000 60,000
2045 First Mortgage Bonds 4.37%100,000 100,000
2047 First Mortgage Bonds 4.23%80,000 80,000
2047 First Mortgage Bonds 3.91%90,000 90,000
2048 First Mortgage Bonds 4.35%375,000 375,000
2049 First Mortgage Bonds 3.43%180,000 180,000
2050 First Mortgage Bonds (2)3.07%165,000 —
2051 First Mortgage Bonds 3.54%175,000 175,000
Total Avista Corp. secured long-term bonds 2,017,200 1,904,200
Secured Pollution Control Bonds held by Avista
Corporation (1)(83,700) (83,700)
Total long-term bonds $1,933,500 $1,820,500
(1) In December 2010, $66.7 million and $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding
Bonds (Avista Corporation Colstrip Project) due in 2032 and 2034, respectively, which had been held by Avista Corp. since
2008 and 2009, respectively, were refunded by new variable rate 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.
(2) In September 2020, the Company issued and sold $165.0 million of 3.07 percent first mortgage bonds due in 2050 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 maturing long-term debt of $52.0 million and repay a portion of the outstanding balance
under Avista Corp.'s $400.0 million committed line of credit. In connection with the pricing of the first mortgage bonds in
June 2020, the Company cash settled seven interest rate swap derivatives (notional aggregate amount of $70.0 million) and
paid a net amount of $33.5 million. See Note 5 for a discussion of interest rate swap derivatives.
The following table details future long-term debt maturities including advances from associated companies (see Note 14) (dollars in
thousands):
2021 2022 2023 2024 2025 Thereafter Total
Debt maturities
$— $
250,00
0 $
13,50
0 $— $— $
1,721,54
7 $
1,985,04
7
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 each issue additional
first mortgage bonds under its mortgage in an aggregate principal amount equal to the sum of:
66-2/3 percent of the cost or fair value (whichever is lower) of property additions which have not previously been
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
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 of cash.
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 earnings” (as defined in the Mortgage) for any period of 12 consecutive calendar months out of the
preceding 18 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, 2020,
property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.7
billion in an aggregate principal amount of additional first mortgage bonds at Avista Corp.
NOTE 14. ADVANCES FROM ASSOCIATED COMPANIES
In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of
$51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of
Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly.
The distribution rates paid were as follows during the years ended December 31:
2020 2019
Low distribution rate 1.10% 2.79%
High distribution rate 2.79% 3.61%
Distribution rate at the end of the year 1.10% 2.79%
Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to
the Company. These Preferred Trust Securities may be redeemed at the option of Avista Capital II at any time and mature on June 1,
2037. In December 2000, the Company purchased $10.0 million of these Preferred Trust Securities.
The Company owns 100 percent of Avista Capital II and has solely and unconditionally guaranteed the payment of distributions on,
and redemption price and liquidation amount for, the Preferred Trust Securities to the extent that Avista Capital II has funds available
for such payments from the respective debt securities. Upon maturity or prior redemption of such debt securities, the Preferred Trust
Securities will be mandatorily redeemed.
NOTE 15. FAIR VALUE
The carrying values of cash and cash equivalents, special deposits, accounts and notes receivable, accounts payable and notes payable
are reasonable estimates of their fair values. Bonds and advances from associated companies are reported at carrying value on the
Balance Sheets.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted
prices in active markets for identical assets or liabilities (Level 1 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.
Level 2 – Pricing inputs are other than quoted prices in active markets included in Level 1, but which are either directly or
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29
indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other
valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted
forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying
instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace
throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which
transactions are executed in the marketplace.
Level 3 – Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs may be
used with internally developed methodologies that result in management’s best estimate of fair value.
Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value
measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment,
and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels. The
determination of the fair values incorporates various factors that not only include the credit standing of the counterparties involved
and the impact of credit enhancements (such as cash deposits and letters of credit), but also the impact of Avista Corp.’s
nonperformance risk on its liabilities.
The following table sets forth the carrying value and estimated fair value of the Company’s financial instruments not reported at
estimated fair value on the Balance Sheets as of December 31 (dollars in thousands):
2020 2019
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
Bonds (Level 2) $963,500 $1,189,824 $963,500 $1,124,649
Bonds (Level 3)970,000 1,125,618 857,000 946,674
Advances from associated companies (Level 3)51,547 43,815 51,547 41,238
These estimates of fair value of bonds and advances from associated 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 85.0 to 144.9, where a par value of 100.00 represents the carrying
value recorded on the Balance Sheets. Level 2 bonds represent 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
bonds with similar risk and terms if there is no trading activity near a period end. Level 3 bonds consist of private placement bonds
and advances from affiliated companies, which typically have no secondary trading activity. Fair values in Level 3 are estimated
based on market prices from third party brokers using secondary market quotes for bonds 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, 2020 at fair value on a recurring basis (dollars in thousands):
Level 1 Level 2 Level 3
Counterparty
and Cash
Collateral
Netting (1)Total
December 31, 2020
Assets:
Energy commodity derivatives $— $23,645 $— $(22,152) $1,493
Level 3 energy commodity derivatives:
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.30
Natural gas exchange agreements — — 75 (75) —
Foreign currency exchange derivatives — 30 — — 30
Interest rate swap derivatives — 952 — (952) —
Deferred compensation assets:
Mutual Funds:
Fixed income securities 2,471 — — — 2,471
Equity securities 6,228 — — — 6,228
Total $8,699 $24,627 $75 $(23,179) $10,222
Liabilities:
Energy commodity derivatives $— $23,030 $— $(22,768) $262
Level 3 energy commodity derivatives:
Natural gas exchange agreement — — 8,485 (75) 8,410
Interest rate swap derivatives — 51,765 — (9,002) 42,763
Total $— $74,795 $8,485 $(31,845) $51,435
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, 2019 at fair value on a recurring basis (dollars in thousands):
Level 1 Level 2 Level 3
Counterparty
and Cash
Collateral
Netting (1)Total
December 31, 2019
Assets:
Energy commodity derivatives $— $41,546 $— $(40,452) $1,094
Level 3 energy commodity derivatives:
Natural gas exchange agreement — — 27 (27) —
Foreign currency exchange derivatives — 97 — — 97
Interest rate swap derivatives — 1,552 — (963) 589
Deferred compensation assets:
Mutual Funds:
Fixed income securities 2,232 — — — 2,232
Equity securities 6,271 — — — 6,271
Total $8,503 $43,195 $27 $(41,442) $10,283
Liabilities:
Energy commodity derivatives $— $45,144 $— $(43,830) $1,314
Level 3 energy commodity derivatives:
Natural gas exchange agreement — — 3,003 (27) 2,976
Interest rate swap derivatives — 34,056 — (7,733) 26,323
Total $— $79,200 $3,003 $(51,590) $30,613
(1) The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally
enforceable master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against
any payables and receivables for cash collateral held or placed with these same counterparties.
The difference between the amount of derivative assets and liabilities disclosed in respective levels in the table above and the amount
of derivative assets and liabilities disclosed on the Balance Sheets is due to netting arrangements with certain counterparties. See Note
4 for additional discussion of derivative netting.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.31
To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to
estimate the fair value of energy commodity derivative instruments included in Level 2. In particular, electric derivative valuations are
performed using market quotes, adjusted for periods in between quotable periods. Natural gas derivative valuations are estimated
using New York Mercantile Exchange pricing for similar instruments, adjusted for basin differences, using market quotes. Where
observable inputs are available for substantially the full term of the contract, the derivative asset or liability is included in Level 2.
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 currency derivatives, the Company uses forward market curves for Canadian dollars against the US
dollar and multiplies the difference between the locked-in price and the market price by the notional amount of the derivative.
Forward foreign currency market curves are provided by third party brokers. The Company's credit spread is factored into the
locked-in price of the foreign exchange contracts.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan.
These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table
above excludes cash and cash equivalents of $0.5 million as of December 31, 2020 and $0.4 million as of December 31, 2019.
Level 3 Fair Value
For the natural gas commodity exchange agreement, the Company uses the same Level 2 brokered quotes described above; however,
the Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions.
Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because
the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions
can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based
on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated
with market prices and market volatility.
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, 2020 (dollars in thousands):
Fair Value (Net) at
December 31,
2020
Valuation
Technique Unobservable Input Range
Natural gas exchange (8,410) Internally
derived
weighted
average
cost of gas
Forward purchase
prices
$1.71 - $2.54/mmBTU
$2.01 Weighted Average
Forward sales prices $1.76 - $4.16/mmBTU
$3.22 Weighted Average
Purchase volumes 130,000 - 310,000
mmBTUs
Sales volumes 75,000 - 310,000
mmBTUs
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.32
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 of fair value each reporting period.
The following table presents activity for energy commodity derivative assets (liabilities) measured at fair value using significant
unobservable inputs (Level 3) for the years ended December 31 (dollars in thousands):
Natural Gas
Exchange
Agreement
Power
Exchange
Agreement Total
Year ended December 31, 2020:
Balance as of January 1, 2020 $(2,976) $— $(2,976)
Total losses (realized/unrealized):
Included in regulatory assets (1)(4,311) — (4,311)
Settlements (1,123) — (1,123)
Ending balance as of December 31, 2020 (2) $(8,410) $— $(8,410)
Year ended December 31, 2019:
Balance as of January 1, 2019 $(2,774) $(2,488) $(5,262)
Total losses (realized/unrealized):
Included in regulatory assets (1)8,175 435 8,610
Settlements (8,377) 2,053 (6,324)
Ending balance as of December 31, 2019 (2) $(2,976) $— $(2,976)
(1)All gains and losses are included in other regulatory assets and liabilities. There were no gains and losses included in either
net income or other comprehensive income during any of the periods presented in the table above.
(2)There were no purchases, issuances or transfers from other categories of any derivatives instruments during the periods
presented in the table above.
NOTE 16. COMMON STOCK
The payment of dividends on common stock could be limited by:
certain covenants applicable to preferred stock (when outstanding) contained in the Company’s Restated Articles of
Incorporation, as amended (currently there are no preferred shares outstanding),
certain covenants applicable to the Company's outstanding long-term debt and committed line of credit agreements,
the hydroelectric licensing requirements of section 10(d) of the FPA (see Note 1), and
certain requirements under the OPUC approval of the AERC acquisition in 2014. The OPUC's AERC acquisition
order requires Avista Corp. to maintain a capital structure of no less than 35 percent common equity (inclusive of
short-term debt). This limitation may be revised upon request by the Company with approval from the OPUC.
The requirements of the OPUC approval of the AERC acquisition are the most restrictive. Under the OPUC restriction, the amount
available for dividends at December 31, 2020 was $311.8 million.
The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of
December 31, 2020 and 2019.
Equity Issuances
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.33
The Company issued equity in 2020 for total net proceeds of $72.2 million. Most of these issuances came through the Company's
sales agency agreements under which the sales agents may offer and sell new shares of common stock from time to time. The
Company has board and regulatory authority to issue a maximum of 3.2 million shares under these agreements, of which 1.3 million
remain unissued as of December 31, 2020. In 2020, 1.9 million shares were issued under these agreements resulting in total net
proceeds of $70.6 million.
NOTE 17. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters,
including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve
litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and
pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other
contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Corp.’s operations, the
Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.
Collective Bargaining Agreements
The Company’s collective bargaining agreement with the IBEW represents approximately 40 percent of all of Avista Corp.’s
employees. Avista’s largest represented group, representing approximately 90 percent of Avista Corp.'s bargaining unit employees in
Washington and Idaho, are currently covered under a three-year agreement which expires in March 2021.
The Company is in the process of negotiating a new agreement with the IBEW. However, there is a risk that if the collective
bargaining agreement expired and a new agreement was not reached, employees subject to that agreement could strike. Given the
number of employees that are covered by the collective bargaining agreement, a strike could result in disruptions to our operations.
However, the Company believes that the possibility of this occurring is remote.
2015 Washington General Rate Cases
In January 2016, the Company received an order (Order 05) that concluded its electric and natural gas general rate cases that were
originally filed with the WUTC in February 2015. New electric and natural gas rates were effective on January 11, 2016.
PC Petition for Judicial Review
In March 2016, PC filed in Thurston County Superior Court a Petition for Judicial Review of the WUTC's Order 05 and Order 06
described above. In April 2016, this matter was certified for review directly by the Court of Appeals, an intermediate appellate court
in the State of Washington.
In August 2018, the Court of Appeals issued a "Published Opinion" (Opinion) which concluded that the WUTC's use of an attrition
allowance to calculate Avista Corp.'s rate base violated Washington law. In the Opinion, the Court stated that because the projected
additions to rate base in the future were not "used and useful" for service at the time the request for the rate increase was made, they
may not lawfully be included in the Company's rate base to justify a rate increase. Accordingly, the Court concluded that the WUTC
erred in including an attrition allowance in the calculation of Avista Corp.’s electric and natural gas rate base. The Court noted,
however, that the law does not prohibit an attrition allowance in the calculation, for ratemaking purposes, of recoverable operating
and maintenance expense. Since the WUTC order provided one lump sum attrition allowance without distinguishing what portion was
for rate base and which was for operating and maintenance expenses or other considerations, the Court struck all portions of the
attrition allowance attributable to Avista Corp.'s rate base and reversed and remanded the case for the WUTC to recalculate Avista
Corp.’s rates without including an attrition allowance in the calculation of rate base.
In March 2020, the Company received an order from the WUTC that requires it to refund $8.5 million to electric and natural gas
customers. The Company will refund $4.9 million to electric customers and $3.6 million to natural gas customers, which is being
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.34
refunded over a twelve-month period that began on April 1, 2020. The Company previously recorded a customer refund liability of
$8.5 million in 2019.
Boyds Fire (State of Washington Department of Natural Resources v. Avista)
In August 2019, the Company was served with a complaint, captioned “State of Washington Department of Natural Resources v.
Avista Corporation,” seeking recovery up to $4.4 million for fire suppression and investigation costs and related expenses incurred in
connection with a wildfire that occurred in Ferry County, Washington in August 2018. Specifically, the complaint alleges that the fire,
which became known as the “Boyds Fire,” was caused by a dead ponderosa pine tree falling into an overhead distribution line, and
that Avista Corp. was negligent in failing to identify and remove the tree before it came into contact with the line. Avista Corp.
disputes that the tree in question was the cause of the fire and that it was negligent in failing to identify and remove it. Additional
lawsuits have subsequently been filed by private landowners seeking property damages, and holders of insurance subrogation claims
seeking recovery of insurance proceeds paid.
The lawsuits were filed in the Superior Court of Ferry County, Washington. The Company intends to vigorously defend itself in the
litigation. However, the Company cannot predict the outcome of these matters.
Labor Day Windstorm
In September 2020, a severe windstorm occurred in eastern Washington and northern Idaho. The extreme weather event resulted in
customer outages and the cause of multiple wildfires in the region. With respect to wildfires, the Company’s investigation determined
that the primary cause of the fires was extreme high winds. To date, the Company has not found any evidence that the fires were
caused by any deficiencies in its equipment, maintenance activities or vegetation management practices.
The Company has become aware of instances where, during the course of the storm, otherwise healthy trees and limbs, located in
areas outside its maintenance right-of-way, broke under the extraordinary wind conditions and caused damage to its energy delivery
system at or near what is believed to be the potential area of origin of a wildfire. Those instances include what has been referred to as:
the Babb Road fire (near Malden and Pine City, Washington); the Christensen Road fire (near Airway Heights, Washington); and the
Mile Marker 49 fire (near Orofino, Idaho). These wildfires covered, in total, approximately 22,000 acres. The Company currently
estimates approximately 230 residential, commercial and other structures were impacted. Parallel investigations by applicable state
agencies, including the Washington Department of Natural Resources, are ongoing, and the Company is cooperating with those
efforts.
In addition to the instances identified above, the Company is aware of a 5-acre fire that occurred in Colfax, Washington, which
damaged several residential structures. The Company’s investigation determined that the Company’s facilities were not involved in
the ignition of this fire in any way.
The Company’s investigation has found no evidence of negligence with respect to any of the fires, and the Company intends to
vigorously defend any claims for damages that may be asserted against it with respect to the wildfires arising out of the extreme wind
event.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company
believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of
operations or cash flows. It is possible that a change could occur in the Company’s estimates of the probability or amount of a liability
being incurred. Such a change, should it occur, could be significant.
The Company routinely assesses, based on studies, expert analysis 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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.35
who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company’s policy is to accrue
and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation,
cleanup and monitoring costs to be incurred. For matters that affect Avista Corp.’s operations, the Company seeks, to the extent
appropriate, recovery of incurred costs through the ratemaking process.
The Company has potential liabilities under the Endangered Species Act for species of fish, plants and wildlife that have either
already been added to the endangered species list, listed as “threatened” or petitioned for listing. Thus far, measures adopted and
implemented have had minimal impact on the Company. However, the Company will continue to seek recovery, through the
ratemaking process, of all operating and capitalized costs related to these issues.
Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights.
In addition, the Company holds additional non-hydro water rights. The State of Montana is examining the status of all water right
claims within state boundaries through a general adjudication. Claims within the Clark Fork River basin could adversely affect the
energy production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated
adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d’Alene
basin. The Company is and will continue to be a participant in these and any other relevant adjudication processes. The complexity of
such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to
estimate the impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all
operating and capitalized costs related to this issue.
NOTE 18. REGULATORY MATTERS
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge or liability on the Balance Sheets for future prudence review and
recovery or rebate through retail rates. The power supply costs deferred include certain differences between actual net power supply
costs incurred by Avista Corp. and the costs included in base retail rates. This difference in net power supply costs primarily results
from changes in:
short-term wholesale market prices and sales and purchase volumes,
the level, availability and optimization of hydroelectric generation,
the level and availability of thermal generation (including changes in fuel prices),
retail loads, and
sales of surplus transmission capacity.
In Washington, the ERM allows Avista Corp. to periodically increase or decrease electric rates with WUTC 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 and defer these
differences (over the $4.0 million deadband and sharing bands) for future surcharge or rebate to customers. For 2020, the Company
recognized a pre-tax benefit of $6.2 million under the ERM in Washington compared to a benefit of $4.4 million for 2019. Total net
deferred power costs under the ERM were a liability of $37.9 million as of December 31, 2020 and a liability of $40.0 million as of
December 31, 2019. These deferred power cost balances represent amounts due to customers. Pursuant to WUTC requirements,
should the cumulative deferral balance exceed $30 million in the rebate or surcharge direction, the Company must make a filing with
the WUTC to adjust customer rates to either return the balance to customers or recover the balance from customers. As the cumulative
rebate balance exceeded $30 million, the Company’s 2019 filing contained a proposed rate refund. The ERM proceeding was
considered with the Company’s 2019 general rate case proceeding and a refund was approved and is being returned to customers over
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.36
a two-year period that began on April 1, 2020. Avista Corp. makes an annual filing on, or before, April 1 of each year to provide the
opportunity for the WUTC staff and other interested parties to review the prudence of, and audit, the ERM deferred power cost
transactions for the prior calendar year.
Avista Corp. has a PCA mechanism in Idaho that allows it to modify electric rates on October 1 of each year with IPUC approval.
Under the PCA mechanism, Avista Corp. defers 90 percent of the difference between certain actual net power supply expenses and
the amount included in base retail rates for its Idaho customers. The October 1 rate adjustments recover or rebate power costs deferred
during the preceding July-June twelve-month period. Total net power supply costs deferred under the PCA mechanism were an asset
of $2.5 million as of December 31, 2020 and $0.3 million as of December 31, 2019. Deferred power cost assets represent amounts
due from customers and liabilities represent amounts due to customers.
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Corp. files a PGA in all three states it serves to adjust natural gas rates for: 1) estimated commodity and pipeline transportation
costs to serve natural gas customers for the coming year, and 2) the difference between actual and estimated commodity and
transportation costs for the prior year. Total net deferred natural gas costs were an asset of $1.4 million as of December 31, 2020 and
a liability of $3.2 million as of December 31, 2019. Asset balances represent amounts due from customers and liabilities represent
amounts due to customers.
Decoupling and Earnings Sharing Mechanisms
Decoupling (also known as an FCA in Idaho) is a mechanism designed to sever the link between a utility's revenues and consumers'
energy usage. In each of Avista Corp.'s jurisdictions, 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 and assumed "normal" kilowatt hour and therm sales, rather than being based
on actual kilowatt hour and therm sales. The difference between revenues based on the number of customers and "normal" sales and
revenues based on actual usage is deferred and either surcharged or rebated to customers beginning in the following year. Only
residential and certain commercial customer classes are included in decoupling mechanisms.
Washington Decoupling and Earnings Sharing
In Washington, the WUTC approved the Company's decoupling mechanisms for electric and natural gas for a five-year period
beginning January 1, 2015. In 2019, the WUTC approved an extension of the mechanisms for an additional five-year term through
March 31, 2025, with one modification in that new customers added after any test period would not be decoupled until included in a
future test period.
Electric and natural gas decoupling surcharge rate adjustments to customers are limited to a 3 percent increase 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 decoupling mechanisms each include an after-the-fact earnings test. At the end of each calendar year, separate electric and natural
gas earnings calculations are made for the calendar year just ended. These earnings tests reflect actual decoupled revenues,
normalized power supply costs and other normalizing adjustments. If the Company earns more than its authorized ROR in
Washington, 50 percent of excess earnings are rebated to customers through adjustments to decoupling surcharge or rebate balances.
See below for a summary of cumulative balances under the decoupling and earnings sharing mechanisms.
Idaho FCA and Earnings Sharing Mechanisms
In Idaho, the IPUC approved the implementation of FCAs for electric and natural gas (similar in operation and effect to the
Washington decoupling mechanisms) for an initial term of three years, beginning January 1, 2016. In 2019, the IPUC approved an
extension of the FCAs through March 31, 2025.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.37
Oregon Decoupling Mechanism
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. Changes related to deferral
interest rates were recommended by the parties in Avista Corp.'s 2019 general rate case and were implemented effective January 15,
2020. In Oregon, an earnings review is conducted on an annual basis. In the annual earnings review, if the Company earns more than
100 basis points above its allowed ROE, one-third of the earnings above the 100 basis points would be deferred 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.
Cumulative Decoupling and Earnings Sharing Mechanism Balances
As of December 31, 2020 and December 31, 2019, the Company had the following cumulative balances outstanding related to
decoupling and earnings sharing mechanisms in its various jurisdictions (dollars in thousands):
December 31,December 31,
2020 2019
Washington
Decoupling surcharge $21,340 $22,440
Idaho
Decoupling surcharge $1,202 $2,549
Provision for earnings sharing rebate (686) (686)
Oregon
Decoupling rebate $(1,262) $(739)
There were no earnings sharing rebates associated with Washington and Oregon as of December 31, 2020 and December 31, 2019.
NOTE 19. TERMINATION OF PROPOSED ACQUISITION BY HYDRO ONE
In July 2017, Avista Corp. entered into a Merger Agreement that provided for Avista Corp. to become an indirect, wholly-owned
subsidiary of Hydro One, subject to the satisfaction or waiver of specified closing conditions, including approval by regulatory
agencies. Hydro One, based in Toronto, is Ontario’s largest electricity transmission and distribution provider.
Termination of the Merger Agreement
Due to the denial of the proposed merger by certain of the Company's regulatory commissions, in January 2019, Avista Corp., Hydro
One and certain subsidiaries thereof, entered into a Termination Agreement indicating their mutual agreement to terminate the Merger
Agreement, effective immediately. Pursuant to the terms of the Termination Agreement, Hydro One paid Avista Corp. a $103 million
termination fee in January 2019. The termination fee was used for reimbursing the Company's transaction costs incurred from 2017 to
2019. The balance of the termination fee remaining after payment of 2019 transaction costs and applicable income taxes was used for
general corporate purposes and reduced the Company's need for external financing. The 2019 costs were $19.7 million pre-tax and
included financial advisers' fees, legal fees, consulting fees and employee time.
NOTE 20. SALE OF METALfx
In April 2019, Bay Area Manufacturing, Inc., a non-regulated subsidiary of Avista Corp., entered into a definitive agreement to sell
its interest in METALfx to an independent third party. The transaction was a stock sale for a total cash purchase price of $17.5
million, plus cash on-hand, subject to customary closing adjustments. The transaction closed in April 2019, and as of that date the
Company has no further involvement with METALfx.
The purchase price of $17.5 million, as adjusted, was divided among the security holders of METALfx, including the minority
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.38
shareholder, pro-rata based on ownership (Avista Corp. owned 89.2 percent of the equity of METALfx). As required under the
purchase agreement, $1.2 million (7 percent of the purchase price) will be held in escrow for 24 months from the closing of the
transaction to satisfy certain indemnification obligations.
When all escrow amounts are released, the sales transaction is expected to provide cash proceeds to Avista Corp., net of payments to
the minority holder, contractually obligated compensation payments and other transaction expenses, of $16.5 million and result in a
net gain after-tax of $3.3 million. The Company expects to receive the full amount of its portion of the escrow accounts; therefore, the
full amounts are included in the gain calculation.
NOTE 21. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow information consisted of the following items for the years ended December 31 (dollars in thousands):
2020 2019
Cash paid for interest $ 91,188 $ 92,681
Cash paid for income taxes 701 26,164
Cash received for income tax refunds (984) (589)
NOTE 22. SUBSEQUENT EVENTS
The Company has evaluated its subsequent events and noted no subsequent events have occurred.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.39
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
1. Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-tax basis, where appropriate.
2. Report in columns (f) and (g) the amounts of other categories of other cash flow hedges.
3. For each category of hedges that have been accounted for as "fair value hedges", report the accounts affected and the related amounts in a footnote.
4. Report data on a year-to-date basis.
Other
Adjustments
(e)
Foreign Currency
Hedges
(d)
Minimum Pension
Liability adjustment
(net amount)
(c)
Unrealized Gains and
Losses on Available-
for-Sale Securities
(b)
Item
(a)
( 7,866,070)
Balance of Account 219 at Beginning of
Preceding Year
1
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
( 2,391,954)
Preceding Quarter/Year to Date Changes in
Fair Value
3
( 2,391,954)Total (lines 2 and 3) 4
( 10,258,024)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 10,258,024)
Balance of Account 219 at Beginning of
Current Year
6
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
( 4,120,140)
Current Quarter/Year to Date Changes in
Fair Value
8
( 4,120,140)Total (lines 7 and 8) 9
( 14,378,164)
Balance of Account 219 at End of Current
Quarter/Year
10
FERC FORM NO. 1 (NEW 06-02)Page 122a
Other Cash Flow
Hedges
[Insert Footnote at Line 1
to specify]
(g)
Other Cash Flow
Hedges
Interest Rate Swaps
(f)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Total
Comprehensive
Income
(j)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Totals for each
category of items
recorded in
Account 219
(h)
( 7,866,070) 1
2
( 2,391,954) 3
196,979,195 194,587,241( 2,391,954) 4
( 10,258,024) 5
( 10,258,024) 6
7
( 4,120,140) 8
134,517,321 130,397,181( 4,120,140) 9
( 14,378,164) 10
FERC FORM NO. 1 (NEW 06-02)Page 122b
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Avista Corporation X
04/15/2021 2020/Q4
Line
No.(b)(a)
Classification Electric
(c)
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Total Company for the
Current Year/Quarter Ended
Report in Column (c) the amount for electric function, in column (d) the amount for gas function, in column (e), (f), and (g) report other (specify) and in
column (h) common function.
Utility Plant 1
In Service 2
4,525,328,898 6,627,834,919Plant in Service (Classified) 3
71,890,863Property Under Capital Leases 4
Plant Purchased or Sold 5
Completed Construction not Classified 6
Experimental Plant Unclassified 7
4,525,328,898 6,699,725,782Total (3 thru 7) 8
Leased to Others 9
12,822,127 13,727,648Held for Future Use 10
150,751,249 172,073,892Construction Work in Progress 11
273,648 273,648Acquisition Adjustments 12
4,689,175,922 6,885,800,970Total Utility Plant (8 thru 12) 13
1,635,742,935 2,294,362,603Accum Prov for Depr, Amort, & Depl 14
3,053,432,987 4,591,438,367Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
1,607,056,988 2,132,757,425Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
28,685,947 161,605,178Amort of Other Utility Plant 21
1,635,742,935 2,294,362,603Total In Service (18 thru 21) 22
Leased to Others 23
Depreciation 24
Amortization and Depletion 25
Total Leased to Others (24 & 25) 26
Held for Future Use 27
Depreciation 28
Amortization 29
Total Held for Future Use (28 & 29) 30
Abandonment of Leases (Natural Gas) 31
Amort of Plant Acquisition Adj 32
1,635,742,935 2,294,362,603Total Accum Prov (equals 14) (22,26,30,31,32) 33
FERC FORM NO. 1 (ED. 12-89) Page 200
(g)
Common
(h)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas Other (Specify)
(d) (e) (f)
Other (Specify)Other (Specify)
1
2
1,410,775,568 691,730,453 3
71,890,863 4
5
6
7
1,410,775,568 763,621,316 8
9
190,585 714,936 10
3,747,095 17,575,548 11
12
1,414,713,248 781,911,800 13
421,698,079 236,921,589 14
993,015,169 544,990,211 15
16
17
421,097,745 104,602,692 18
19
20
600,334 132,318,897 21
421,698,079 236,921,589 22
23
24
25
26
27
28
29
30
31
32
421,698,079 236,921,589 33
FERC FORM NO. 1 (ED. 12-89) Page 201
Schedule Page: 200 Line No.: 4 Column: h
ROU Asset - $71,890,863
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account
103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of
plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
1. INTANGIBLE PLANT 1
(301) Organization 2
(302) Franchises and Consents 44,373,854 2,317,727 3
(303) Miscellaneous Intangible Plant 25,423,701 7,421,846 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 69,797,555 9,739,573 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 3,578,472 284,864 8
(311) Structures and Improvements 139,674,955 1,221,499 9
(312) Boiler Plant Equipment 192,656,435 1,450,206 10
(313) Engines and Engine-Driven Generators 8,179 1,072,700 11
(314) Turbogenerator Units 57,238,023 1,219,106 12
(315) Accessory Electric Equipment 29,561,074 1,559,557 13
(316) Misc. Power Plant Equipment 16,624,409 1,044,743 14
(317) Asset Retirement Costs for Steam Production 17,026,651 -2,315,577 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 456,368,198 5,537,098 16
B. Nuclear Production Plant 17
(320) Land and Land Rights 18
(321) Structures and Improvements 19
(322) Reactor Plant Equipment 20
(323) Turbogenerator Units 21
(324) Accessory Electric Equipment 22
(325) Misc. Power Plant Equipment 23
(326) Asset Retirement Costs for Nuclear Production 24
TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24) 25
C. Hydraulic Production Plant 26
(330) Land and Land Rights 64,014,211 885,138 27
(331) Structures and Improvements 97,019,506 1,675,216 28
(332) Reservoirs, Dams, and Waterways 192,430,218 1,546,822 29
(333) Water Wheels, Turbines, and Generators 234,559,681 -111,730 30
(334) Accessory Electric Equipment 69,727,335 6,562,094 31
(335) Misc. Power PLant Equipment 15,179,096 -2,133,230 32
(336) Roads, Railroads, and Bridges 3,649,100 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 676,579,147 8,424,310 35
D. Other Production Plant 36
(340) Land and Land Rights 905,167 37
(341) Structures and Improvements 17,169,217 288,072 38
(342) Fuel Holders, Products, and Accessories 21,390,353 -318,631 39
(343) Prime Movers 23,507,372 40
(344) Generators 219,321,048 1,863,789 41
(345) Accessory Electric Equipment 22,350,892 195,712 42
(346) Misc. Power Plant Equipment 1,702,679 -61,293 43
(347) Asset Retirement Costs for Other Production 351,683 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 306,698,411 1,967,649 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 1,439,645,756 15,929,057 46
Page 204FERC FORM NO. 1 (REV. 12-05)
(f)
Transfers Balance atEnd of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent’s plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
1
2
46,691,581 3
31,934,915 53,919 964,551 4
78,626,496 53,919 964,551 5
6
7
3,863,336 8
140,719,044 177,410 9
193,639,431 467,210 10
1,080,879 11
58,189,080 268,049 12
30,840,159 280,472 13
17,640,074 29,078 14
14,711,074 15
460,683,077 1,222,219 16
17
18
19
20
21
22
23
24
25
26
64,899,349 27
98,195,701-62,582 436,439 28
193,977,040 29
234,353,977 93,974 30
75,374,302 915,127 31
13,042,016 3,850 32
3,649,100 33
34
683,491,485-62,582 1,449,390 35
36
905,167 37
17,439,411 17,878 38
21,069,206 2,516 39
23,507,372 40
221,122,751 62,086 41
22,541,451 5,153 42
1,641,386 43
351,683 44
308,578,427 87,633 45
1,452,752,989-62,582 2,759,242 46
Page 205FERC FORM NO. 1 (REV. 12-05)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 29,647,248 1,317,287 48
(352) Structures and Improvements 25,358,219 3,346,156 49
(353) Station Equipment 287,013,636 28,710,707 50
(354) Towers and Fixtures 17,160,699 92,604 51
(355) Poles and Fixtures 278,634,026 21,441,701 52
(356) Overhead Conductors and Devices 158,589,765 7,464,344 53
(357) Underground Conduit 3,253,240 577,382 54
(358) Underground Conductors and Devices 2,602,442 576,099 55
(359) Roads and Trails 2,107,559 46,426 56
(359.1) Asset Retirement Costs for Transmission Plant 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 804,366,834 63,572,706 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 11,814,980 7,576,606 60
(361) Structures and Improvements 33,532,067 1,302,968 61
(362) Station Equipment 146,876,585 9,910,815 62
(363) Storage Battery Equipment 2,428,752 63
(364) Poles, Towers, and Fixtures 436,264,125 26,250,177 64
(365) Overhead Conductors and Devices 280,528,350 18,365,903 65
(366) Underground Conduit 123,584,467 10,412,009 66
(367) Underground Conductors and Devices 219,816,148 12,701,847 67
(368) Line Transformers 280,684,915 13,237,158 68
(369) Services 180,415,605 9,836,373 69
(370) Meters 72,884,062 21,619,348 70
(371) Installations on Customer Premises 2,114,606 1,011,018 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 65,814,671 4,693,076 73
(374) Asset Retirement Costs for Distribution Plant 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 1,856,759,333 136,917,298 75
5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT 76
(380) Land and Land Rights 77
(381) Structures and Improvements 78
(382) Computer Hardware 79
(383) Computer Software 80
(384) Communication Equipment 81
(385) Miscellaneous Regional Transmission and Market Operation Plant 82
(386) Asset Retirement Costs for Regional Transmission and Market Oper 83
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83) 84
6. GENERAL PLANT 85
(389) Land and Land Rights 507,277 86
(390) Structures and Improvements 8,475,394 2,179,421 87
(391) Office Furniture and Equipment 1,438,878 1,691,400 88
(392) Transportation Equipment 49,928,658 3,711,321 89
(393) Stores Equipment 391,830 90
(394) Tools, Shop and Garage Equipment 6,162,650 1,033,327 91
(395) Laboratory Equipment 1,801,512 205,954 92
(396) Power Operated Equipment 31,797,569 136,180 93
(397) Communication Equipment 48,785,141 4,783,859 94
(398) Miscellaneous Equipment 193,350 85,133 95
SUBTOTAL (Enter Total of lines 86 thru 95) 149,482,259 13,826,595 96
(399) Other Tangible Property 97
(399.1) Asset Retirement Costs for General Plant 98
TOTAL General Plant (Enter Total of lines 96, 97 and 98) 149,482,259 13,826,595 99
TOTAL (Accounts 101 and 106) 4,320,051,737 239,985,229 100
(102) Electric Plant Purchased (See Instr. 8) 101
(Less) (102) Electric Plant Sold (See Instr. 8) 102
(103) Experimental Plant Unclassified 103
TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 4,320,051,737 239,985,229 104
Page 206FERC FORM NO. 1 (REV. 12-05)
(f)
Transfers Balance atEnd of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
30,964,535 48
28,655,332 49,043 49
311,464,032-27,918 4,232,393 50
17,253,303 51
299,324,482 751,245 52
165,777,290 276,819 53
3,830,622 54
3,178,541 55
2,153,985 56
57
862,602,122-27,918 5,309,500 58
59
18,139,966-1,251,620 60
34,830,606 4,429 61
156,517,973 27,918 297,345 62
2,428,752 63
461,243,463 1,270,839 64
298,797,672 96,581 65
133,960,477 35,999 66
232,245,687 272,308 67
293,764,412 157,661 68
190,188,557 63,421 69
82,138,055 12,365,355 70
3,125,624 71
72
69,804,366 703,381 73
74
1,977,185,610-1,223,702 15,267,319 75
76
77
78
79
80
81
82
83
84
85
507,277 86
10,633,456 21,359 87
1,985,065-135,335 1,009,878 88
52,859,185 780,794 89
387,400 4,430 90
6,806,217 389,760 91
1,898,077 109,389 92
30,983,867 949,882 93
47,822,654-327,878 5,418,468 94
278,483 95
154,161,681-463,213 8,683,960 96
97
98
154,161,681-463,213 8,683,960 99
4,525,328,898-1,723,496 32,984,572 100
101
102
103
4,525,328,898-1,723,496 32,984,572 104
Page 207FERC FORM NO. 1 (REV. 12-05)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
Avista Corporation X 04/15/2021 2020/Q4
Line Description and Location Date Originally Included Balance atEnd of Year(c)(b)(a)Of Property in This Account Date Expected to be usedin Utility Service (d)No.
1. Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2. For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Land and Rights: 1
2
Dec 2010Distribution Plant Land, Carlin Bay, Idaho 162,3522022-2026 3
Mar 2011Distribution Plant Land, Spokane, Washington 540,3072022-2026 4
Dec 2011Transmission Plant Land, Spokane, Washington 431,6002022-2026 5
July 2014Transmission Plant Land, Spokane, Washington 62,1682022-2026 6
Dec 2011Other Production Plant Land, Spokane, Washington 40,8962022-2026 7
Dec 2015Steam Production Plant Land, Spokane, Washington 3,544,7252022-2026 8
Mar 2016Transmission Plant Land, Noxon, Montana 3,292,1672022-2026 9
Jan 2017Transmission Plant Land, Spokane, Washington 56,3112022-2026 10
June 2019Distribution Plant Land, Spokane, Washington 2,869,9042022-2026 11
June 2019Distribution Plant Land, Colville, Washington 104,5272022-2026 12
July 2019Transmission Plant Land, Sandpoint, Idaho 486,2992022-2026 13
July 2019Transmission Plant Land, Spokane, Washington 378,3922022-2026 14
Nov 2020Distribution Plant Land, Coeur d'Alene, Idaho 775,5302022-2026 15
16
17
18
19
20
Other Property: 21
22
23
24
July 2019Distribution Structure and Improvement, Spokane, WA 32,8242022-2026 25
July 2019Transmission Structure and Improvement, Spokane, WA 44,1252022-2026 26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-96)Page 214
47 Total 12,822,127
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CONSTRUCTION WORK IN PROGRESS - - ELECTRIC (Account 107)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Description of Project Construction work in progress -
(b)(a)Electric (Account 107)
1. Report below descriptions and balances at end of year of projects in process of construction (107)
2. Show items relating to "research, development, and demonstration" projects last, under a caption Research, Development, and Demonstrating (see
Account 107 of the Uniform System of Accounts)
3. Minor projects (5% of the Balance End of the Year for Account 107 or $1,000,000, whichever is less) may be grouped.
40,181,572Cabinet Gorge Fish Passage 1
12,954,239KF Fuel Yard Equipment Replacement 2
8,516,252Irvin Sub - New Construction 3
7,123,281Energy Imbalance Market 4
6,835,301CS2 Single Phase Transformer 5
6,758,685Westside 230 kV Substation - Rebuild 6
5,693,321Lolo-Oxbow 230kV Transmission Line Rebuild Project 7
5,440,111Substation Rebuilds 8
4,466,211Protection System Upgrades for PRC-002 9
3,454,702Electric Transmission Plant-Storm 10
2,931,066Metro-Post St 115kV Underground Tx Line Rebuild 11
2,620,433Long Lake Plant Upgrades 12
2,423,155Transportation Equip 13
2,253,797LL HED Stability Enhancement 14
2,230,440Saddle Mountain Integration Phase 2 15
2,169,487Cabinet Gorge Unit 3 Protection & Control Upgrade 16
1,798,996Clark Fork Implement PME Agreement 17
1,551,470Substation Asset Mgmt Capital Maintenance 18
1,532,661CG HED Station Service Replacement 19
1,506,950New Substations 20
1,489,741Saddle Mountain Integration 21
1,298,904Transmission Minor Rebuild 22
1,167,846Colstrip Capital Additions 23
1,073,010Regulating Hydro 24
15,308,523Minor projects <$1M 25
7,971,095R&D/Strategic Initiatives 26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-87)Page 216
43 TOTAL 150,751,249
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Item Total
(c)(b)(a)(d)
Section A. Balances and Changes During Year
(c+d+e)Electric Plant inService Electric Plant Held for Future Use Electric PlantLeased to Others(e)
1. Explain in a footnote any important adjustments during year.
2. Explain in a footnote any difference between the amount for book cost of plant retired, Line 11, column (c), and that reported for
electric plant in service, pages 204-207, column 9d), excluding retirements of non-depreciable property.
3. The provisions of Account 108 in the Uniform System of accounts require that retirements of depreciable plant be recorded when
such plant is removed from service. If the respondent has a significant amount of plant retired at year end which has not been recorded
and/or classified to the various reserve functional classifications, make preliminary closing entries to tentatively functionalize the book
cost of the plant retired. In addition, include all costs included in retirement work in progress at year end in the appropriate functional
classifications.
4. Show separately interest credits under a sinking fund or similar method of depreciation accounting.
Balance Beginning of Year 1 1,503,624,342 1,503,624,342
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 123,386,421 123,386,421
(403.1) Depreciation Expense for Asset
Retirement Costs
4
(413) Exp. of Elec. Plt. Leas. to Others 5
Transportation Expenses-Clearing 6 4,616,453 4,616,453
Other Clearing Accounts 7
Other Accounts (Specify, details in footnote): 8
9
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 128,002,874 128,002,874
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 32,020,020 32,020,020
Cost of Removal 13 9,725,603 9,725,603
Salvage (Credit) 14 348,299 348,299
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 41,397,324 41,397,324
Other Debit or Cr. Items (Describe, details in
footnote):
16 16,827,096 16,827,096
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 1,607,056,988 1,607,056,988
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
346,616,483 346,616,483
Nuclear Production 21
Hydraulic Production-Conventional 22 158,689,393 158,689,393
Hydraulic Production-Pumped Storage 23
Other Production 24 147,254,839 147,254,839
Transmission 25 241,331,580 241,331,580
Distribution 26 644,634,303 644,634,303
Regional Transmission and Market Operation 27
General 28 68,530,390 68,530,390
TOTAL (Enter Total of lines 20 thru 28) 29 1,607,056,988 1,607,056,988
Page 219FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 219 Line No.: 16 Column: c
Includes:
Depreciation offset for non-recoverable plant for Boulder Park ($112,280)
AMI/MDM Deferral $10,213,392
ARO Depreciation $748,048
Change in Removal Work in Progress ($6,008,426)
Other Credits ($27,490)
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Description of Investment Date Acquired
(c)(b)(a)
Amount of Investment atBeginning of YearDate Of Maturity (d)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
1
256,138,97101/01/1997Investment in Avista Capital 2
-152,844,453Avista Capital - Equity in Earnings 3
89,816,38007/01/2014Investment in AERC 4
13,995,056AERC - Equity in Earnings 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89)Page 224
42 Total Cost of Account 123.1 $TOTAL 207,105,9540
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Equity in Subsidiary Earnings of Year Revenues for Year Amount of Investment atEnd of Year Gain or Loss from InvestmentDisposed of(e) (f) (g) (h)
4. For any securities, notes, or accounts that were pledged designate such securities, notes, or accounts in a footnote, and state the name of pledgee
and purpose of the pledge.
5. If Commission approval was required for any advance made or security acquired, designate such fact in a footnote and give name of Commission,
date of authorization, and case or docket number.
6. Report column (f) interest and dividend revenues form investments, including such revenues form securities disposed of during the year.
7. In column (h) report for each investment disposed of during the year, the gain or loss represented by the difference between cost of the investment (or
the other amount at which carried in the books of account if difference from cost) and the selling price thereof, not including interest adjustment includible
in column (f).
8. Report on Line 42, column (a) the TOTAL cost of Account 123.1
1
256,138,971 2
-155,335,303-2,490,851 3
89,816,380 4
16,790,283 5,000,000 7,795,227 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
FERC FORM NO. 1 (ED. 12-89)Page 225
42 5,304,376 5,000,000 207,410,331
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MATERIALS AND SUPPLIES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Account Balance Balance
(c)(b)(a)
Department orDepartments which
(d)
Beginning of Year End of Year Use Material
1. For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by function are acceptable. In column (d), designate the department or departments which use the class of material.
2. Give an explanation of important inventory adjustments during the year (in a footnote) showing general classes of material and supplies and the
various accounts (operating expenses, clearing accounts, plant, etc.) affected debited or credited. Show separately debit or credits to stores expense
clearing, if applicable.
4,148,891 (1) 4,088,628 1 Fuel Stock (Account 151)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
29,944,453 (1) 36,162,860 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
3,443,631 (1) 3,661,588 7 Production Plant (Estimated)
-4,267 (1) 170,727 8 Transmission Plant (Estimated)
585,679 (1) 727,662 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
12,589,323 (1),(2) 11,131,219 11 Assigned to - Other (provide details in footnote)
46,558,819 51,854,056 12 TOTAL Account 154 (Enter Total of lines 5 thru 11)
13 Merchandise (Account 155)
14 Other Materials and Supplies (Account 156)
15 Nuclear Materials Held for Sale (Account 157) (Not
applic to Gas Util)
16 Stores Expense Undistributed (Account 163)
17
18
19
50,707,710 55,942,684 20 TOTAL Materials and Supplies (Per Balance Sheet)
Page 227FERC FORM NO. 1 (REV. 12-05)
Schedule Page: 227 Line No.: 1 Column: d
(1) Electric
(2)Natural Gas
Schedule Page: 227 Line No.: 5 Column: d
(1) Electric
(2)Natural Gas
Schedule Page: 227 Line No.: 7 Column: d
(1) Electric
(2)Natural Gas
Schedule Page: 227 Line No.: 8 Column: d
(1) Electric
(2)Natural Gas
Schedule Page: 227 Line No.: 9 Column: d
(1) Electric
(2)Natural Gas
Schedule Page: 227 Line No.: 11 Column: d
(1) Electric
(2)Natural Gas
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
1. Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2. List each study separately.
3. In column (a) provide the name of the study.
4. In column (b) report the cost incurred to perform the study at the end of period.
5. In column (c) report the account charged with the cost of the study.
6. In column (d) report the amounts received for reimbursement of the study costs at end of period.
7. In column (e) report the account credited with the reimbursement received for performing the study.
the Period
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
6,936Gordon Butte Project 50 186200 22
74,477Aurora Solar Project 59 186200 23
142,508Clarkston Hts Solar Project 60 186200 24
108,776Rattlesnake II Wind Project 62 186200 25
29,556Post Falls HED Project 63 186200 26
46,251Kettle Falls Upgrade Project 66 186200 27
5,738Old Milwaukee Solar Project 67 186200 28
5,750Clearwater Wind II Project 68 186200 29
4,975Clearwater Wind III Project 69 186200 30
6,611EnerNOC Battery Storage Project 70 186200 31
14,462Geronimo Solar Project 71 186200 32
4,886Geronimo Solar Project 72 186200 33
5,577Sprague Solar Project 73 186200 34
4,358Royal City Solar Project 76 186200 35
45,841Elf II Solar Project 79 186200 36
33,886Elf 1 Solar Project 80 186200 37
3,767Ralston Solar Project 81 186200 38
3,740Haymaker Wind Project 82 186200 39
2,187Martinsdale Wind Project 83 186200 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07)Page 231
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
840Rainier Solar Project 85 186200 22
26,254Acadia Solar Project 84 186200 23
205Geronimo6 Solar Project 94 186200 24
325Geronimo2 Solar Project 90 186200 25
1,098Jane Wind 2 Project 96 186200 26
1,248Jane Wind Project 95 186200 27
17,313Lolo Solar Project 97 186200 28
73,425Rattlesnake Optional Study 186200 29
4,128Wahatis Solar Project 99 186200 30
4,314Stringtown Solar Project 100 186200 31
2,693North Cheyenne Project 101 186200 32
1,831Harrington Solar Project 103 186200 33
1,849Colville Solar Project 105 186200 34
1,985Latah Wind Project 104 186200 35
1,509Big Sky Connector Line Project 186200 36
2,252Bench Solar Project 106 186200 37
834Broadview IV Project 107 186200 38
1,752Ursus Wind Project 108 186200 39
237Rathdrum CT 109 186200 40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07)Page 231.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
Transmission Service and Generation Interconnection Study Costs
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Description Costs Incurred During
(b)(a)
Period Account Charged
(c)
ReimbursementsReceived During
(d)
Account CreditedWith Reimbursement
(e)
the Period
(continued)
Transmission Studies 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
Generation Studies 21
14,862Bafus Solar Project 77 186200 14,862 186210 22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-F/3-Q (NEW. 03-07)Page 231.2
Schedule Page: 231 Line No.: 22 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 23 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 24 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 25 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 26 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 27 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 28 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 29 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 30 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 31 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 32 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 33 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 34 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 35 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 36 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 37 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 38 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 39 Column: b
Total Life to Date Costs
Schedule Page: 231 Line No.: 40 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 22 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 23 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 24 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 25 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 26 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 27 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 28 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 29 Column: b
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 30 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 31 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 32 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 33 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 34 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 35 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 36 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 37 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 38 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 39 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 40 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 22 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 22 Column: d
Total Life to Date Reimbursements. Project Completed Q4 2020.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY ASSETS (Account 182.3)
Avista Corporation X
04/15/2021 2020/Q4
Line
No.
Description and Purpose of Debits CREDITS
Written off During the
Quarter /Year Account
Charged (d)(c)(a)
Balance at end of
Current Quarter/Year
(e)
Other Regulatory Assets Written off During
the Period Amount
(f)
1. Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Assets being amortized, show period of amortization.
Balance at Beginning
of Current
Quarter/Year
(b)
10,344,716 8,597,671 3,068,230407 1,321,185WA Excess Nat Gas Line Extension Allowance 1
210,801,207 202,321,377 12,639,368228 4,159,538Reg Asset Post Ret Liab 2
83,355,934 93,708,282 1,351,599283 11,703,947Regulatory Asset FAS109 Utility Plant 3
3,023,201 2,344,905 1,971,362283 1,293,066Regulatory Asset FAS109 DSIT Non Plant 4
133,911 133,911407Regulatory Asset- Spokane River Relicense 5
41,309,157 40,042,767 1,266,390407Regulatory Asset- Lake CDA Settlement - Varies 6
19,326,621 10,093,117 18,525,668456, 495 9,292,164Reg Assets- Decouplings Surcharge - 2 years 7
4,945,687 7,891,134 1,820,200407 4,765,647Reg Asset - Colstrip 8
6,573,588 7,794,852 7,374,854244, 175 8,596,118Commodity MTM ST & LT Regulatory Asset 9
1,800,206 1,916,300 116,094Regulatory Asset FAS143 Asset Retirement Obligation 10
1,126,296 1,017,959 206,551242 98,214Regulatory Asset Workers Comp 11
168,594,071 214,851,166 38,064,531Various 84,321,626Interest Rate Swap Asset 12
12,170,199 3,813,813 33,756,305Various 25,399,919DSM Asset 13
3,981,955 3,910,987 70,968283, 410Deferred ITC 14
13,394,821 26,378,924 68,655407,419 13,052,758Regulatory Asset MDM System 15
1,326,885 1,484,961 1,846,303407 2,004,379Regulatory Asset BPA Residential Exchange 16
3,594,035 2,720,100 1,326,173407,419 452,238Regulatory Asset FISERV - 3 years 17
44,093,659 52,370,433 27,652,017Various 35,928,791Regulatory Asset - AFUDC (PIS,WIP) & Equity DFIT 18
256,594 2,547,168 2,805,313557,419 5,095,887Regulatory Asset ID PCA Deferral - 1 year 19
13,052,304 25,913,958 4,177,507108 17,039,161Existing Meters/ERTS Retirement Def 20
1,500,000 1,500,000Regulatory Asset- Colstip Community Fund 21
2,859,947 8,520,795Various 11,380,742Regulatory Asset- COVID-19 22
194,925 58,098407 253,023Regulatory Asset- Energy Imbalance Market 23
829,587 86,636407, 419 916,223Regulatory Assset- Oregon CAT Tax 24
59,519 13,133407, 419 72,652Deferred Regulatory Fees 25
1,006,452407 1,006,452Regulatory Asset- Wildfire Resiliency 26
1,108,935 1,101,894407 2,210,829Deferral for CS2 & Colstrip (O&M, Excess Depr) 27
2,321 2,404 83Other Regulatory Assets 28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
643,207,368TOTAL :44 717,281,643 167,906,461 241,980,736
FERC FORM NO. 1/3-Q (REV. 02-04)Page 232
Schedule Page: 232 Line No.: 1 Column: a
Residential Schedule 101 customers who receive a natural gas line extension as part of
conversion to natural gas from another fuel source. Amortization for a period of 3 years
on the excess allowance exceeding the cost of the line extension.
Schedule Page: 232 Line No.: 2 Column: a
Recognition of the overfunded and underfunded status of a defined benefit postretirement
plan based on ASC 715 for financial reporting.
Schedule Page: 232 Line No.: 3 Column: a
Deferred tax flow through balance on utility plant. Amortization occurs over book life of
respective utility plant assets.
Schedule Page: 232 Line No.: 5 Column: a
Amortization for TDG Idaho ended on December 2019. Spokane River relicensing amortization
costs ended on 11/30/2020.
Schedule Page: 232 Line No.: 6 Column: a
WA Docket UE-080416 & ID Order AVU-E-08-01. Amortization thru 2059.
Schedule Page: 232 Line No.: 7 Column: a
Decoupling revenue deferrals are recognized during the period they occur, subject to
certain limitations. Revenue is expected to be collected within 24 months of the deferral.
Schedule Page: 232 Line No.: 8 Column: a
For Washington Electric,we are currently deferring ARO expenses. Amortization period to be
determined. For Idaho Electric, amortization is for 34 years as per Order 34276,
AVU-E-18-03.
Schedule Page: 232 Line No.: 9 Column: a
Washington Docket# UE-002066 and Idaho Order# 28648
Schedule Page: 232 Line No.: 10 Column: a
Regulatory Assets related to deferred ARO expenses for Kettle Falls and Coyote Springs
thermal plants. The expenses will not be collected from Customers until actual work is
performed.
Schedule Page: 232 Line No.: 11 Column: a
Quarterly adjustments to workers comp reserve for current unpaid claims.
Schedule Page: 232 Line No.: 12 Column: a
Settled swaps are amortized over the life of the associated debt.
Schedule Page: 232 Line No.: 13 Column: a
Amortization period varies depending on timing of transactions.
Schedule Page: 232 Line No.: 14 Column: a
Amortization period varies depending on underlying transactions.
Schedule Page: 232 Line No.: 15 Column: a
Washington Docket#s UE-180418, UG-180419
Schedule Page: 232 Line No.: 16 Column: a
Avista is a participant in the Residential Exchange Program with Bonneville Power
Administration. Customers served under Schedules 1, 12, 22, 32 and 48 are given a rate
adjustment based on Schedule 59 for Washington and Idaho. Amortization is based on
customer usage.
Schedule Page: 232 Line No.: 17 Column: a
Idaho Order# 33494, Docket Nos. AVU-E-16-01 and Stipulation and Settlement Docket#
AVU-E-19-04
Schedule Page: 232 Line No.: 18 Column: a
Deferring the difference between FERC formula and State approved AFUDC rates from 2010 to
present.
Schedule Page: 232 Line No.: 20 Column: a
Washington Docket#s UE-180418 and UG-180419. Amortization period to be determined.
Schedule Page: 232 Line No.: 21 Column: a
WA Order 09 in Dockets UE-190334, UE-190222. Deferral of customer portion for future rate
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
recovery. The funds are set aside to helping the Colstrip community transition away from
economic activity related to coal-fired generation.
Schedule Page: 232 Line No.: 22 Column: a
Deferral of COVID-19 costs as per Idaho PUC Order No. 34718, Oregon PUC Order No. 20-401,
Docket UM 2069 and WA UTC Order No. 01, Dockets UE-200407 and UG-200408.
Schedule Page: 232 Line No.: 23 Column: a
Idaho PUC Order No. 34606. Deferral of costs related to Avista's entry in the Energy
Imbalance Market in March 2022.
Schedule Page: 232 Line No.: 24 Column: a
Oregon PUC Order No. 20-398, Docket UM-2042.
Schedule Page: 232 Line No.: 25 Column: a
Oregon Order # 20-354. Deferral of cost of variance in annual regulatory fee rate and the
amount collected in rates.
Schedule Page: 232 Line No.: 26 Column: a
Idaho PUC Order 34883
Schedule Page: 232 Line No.: 27 Column: a
WA Order 09, Docket Nos. UE-190334, UG-190335, UE-190222.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS DEFFERED DEBITS (Account 186)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Description of Miscellaneous Debits CREDITS
Account
(c)(b)(a)
Balance at
End of Year
(d)
Deferred Debits Amount
(e)
Balance at
Beginning of Year
(f)Charged
1. Report below the particulars (details) called for concerning miscellaneous deferred debits.
2. For any deferred debit being amortized, show period of amortization in column (a)
3. Minor item (1% of the Balance at End of Year for Account 186 or amounts less than $100,000, whichever is less) may be grouped by
classes.
1
1,110,999 1,110,999Colstrip Common Facility 2
2,355,642 2,355,642Colstrip Common Facility 3
4,815,987 3,964,981 851,006VARPlant Alloc of Clearing Journal 4
496,981 517,205 20,224Gas Supply Transactions 5
540,265 394,831 145,434557WA REC Deferral 6
8,551,769 15,376,953 6,825,184Reg Asset - Decoupling Deferred 7
5,305,694 5,305,694Reg Asset - COVID 19 Deferral 8
124,313 119,125 5,188VARNez Perce Settlement 9
110,267 142,508 32,241Clarkston Hts Solar Project#60 10
-226,818 -226,818Timber Harvest Revenue 11
32,101 108,776 76,675Rattlesnake II Wind Proj #62 12
572,880 656,667 83,787Misc. Deferred Debits <$100,000 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94)Page 233
49 TOTAL
47 Misc. Work in Progress
48 Deferred Regulatory Comm.
Expenses (See pages 350 - 351)
18,484,386 29,826,563
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Description and Location Balance of Begining
(c)(b)(a)
Balance at Endof Year of Year
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes.
2. At Other (Specify), include deferrals relating to other income and deductions.
Electric 1
102,475,097 20,510,338 2
3
4
5
6
Other 7
102,475,097 20,510,338TOTAL Electric (Enter Total of lines 2 thru 7) 8
Gas 9
21,374,121 3,791,114 10
11
12
13
14
Other 15
21,374,121 3,791,114TOTAL Gas (Enter Total of lines 10 thru 15 16
92,879,318 152,755,074Other 17
216,728,536 177,056,526TOTAL (Acct 190) (Total of lines 8, 16 and 17) 18
Notes
FERC FORM NO. 1 (ED. 12-88)Page 234
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Class and Series of Stock and Number of shares
(c)(b)(a)
Call Price at
End of Year
Par or Stated
Value per share
(d)
Name of Stock Series Authorized by Charter
1. Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate series
of any general class. Show separate totals for common and preferred stock. If information to meet the stock exchange reporting
requirement outlined in column (a) is available from the SEC 10-K Report Form filing, a specific reference to report form (i.e., year and
company title) may be reported in column (a) provided the fiscal years for both the 10-K report and this report are compatible.
2. Entries in column (b) should represent the number of shares authorized by the articles of incorporation as amended to end of year.
Account 201 - Common Stock Issued 1
200,000,000 No Par Value 2
Restricted shares 3
200,000,000Total Common 4
5
6
10,000,000Account 204 - Preferred Stock Issued 7
8
9
Cumulative 10
11
12
10,000,000Total Preferred 13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-91) Page 250
AS REACQUIRED STOCK (Account 217)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCKS (Account 201 and 204) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
OUTSTANDING PER BALANCE SHEET HELD BY RESPONDENT
IN SINKING AND OTHER FUNDS
Shares(g)Cost(h)Shares SharesAmount
(Total amount outstanding without reductionfor amounts held by respondent)
Amount(e)(f)(i)(j)
3. Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4. The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5. State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
1
1,249,688,206 69,238,901 2
3,667,762 71,706 3
3,667,762 71,706 1,249,688,206 69,238,901 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (ED. 12-88) Page 251
Schedule Page: 250 Line No.: 3 Column: i
Restricted share awards vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the
end of each year if the service condition is met. Restricted stock is valued at the close of market of the Company’s common stock on
the grant date.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line Item Amount(b)(a)
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
No.
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 112. Add more
columns for any account if deemed necessary. Explain changes made in any account during the year and give the accounting entries effecting such
change.
(a) Donations Received from Stockholders (Account 208)-State amount and give brief explanation of the origin and purpose of each donation.
(b) Reduction in Par or Stated value of Capital Stock (Account 209): State amount and give brief explanation of the capital change which gave rise to
amounts reported under this caption including identification with the class and series of stock to which related.
(c) Gain on Resale or Cancellation of Reacquired Capital Stock (Account 210): Report balance at beginning of year, credits, debits, and balance at end of
year with a designation of the nature of each credit and debit identified by the class and series of stock to which related.
(d) Miscellaneous Paid-in Capital (Account 211)-Classify amounts included in this account according to captions which, together with brief explanations,
disclose the general nature of the transactions which gave rise to the reported amounts.
-10,696,711Equity transactions of subsidiaries 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
FERC FORM NO. 1 (ED. 12-87)Page 253
40 TOTAL -10,696,711
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
CAPITAL STOCK EXPENSE (Account 214)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Class and Series of Stock Balance at End of Year(b)(a)
1. Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2. If any change occurred during the year in the balance in respect to any class or series of stock, attach a statement giving particulars
(details) of the change. State the reason for any charge-off of capital stock expense and specify the account charged.
-47,076,877Common Stock - no par 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
FERC FORM NO. 1 (ED. 12-87) Page 254b
22 TOTAL -47,076,877
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Class and Series of Obligation, Coupon Rate
(c)(b)(a)
Total expense,
Premium or Discount
Principal Amount
Of Debt issued(For new issue, give commission Authorization numbers and dates)
1. Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2. In column (a), for new issues, give Commission authorization numbers and dates.
3. For bonds assumed by the respondent, include in column (a) the name of the issuing company as well as a description of the bonds.
4. For advances from Associated Companies, report separately advances on notes and advances on open accounts. Designate
demand notes as such. Include in column (a) names of associated companies from which advances were received.
5. For receivers, certificates, show in column (a) the name of the court -and date of court order under which such certificates were
issued.
6. In column (b) show the principal amount of bonds or other long-term debt originally issued.
7. In column (c) show the expense, premium or discount with respect to the amount of bonds or other long-term debt originally issued.
8. For column (c) the total expenses should be listed first for each issuance, then the amount of premium (in parentheses) or discount.
Indicate the premium or discount with a notation, such as (P) or (D). The expenses, premium or discount should not be netted.
9. Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission’s authorization of treatment other than as
specified by the Uniform System of Accounts.
42,712 5,500,000FMBS - SERIES A - 7.53% DUE 05/05/2023 1
7,766 1,000,000FMBS - SERIES A - 7.54% DUE 5/05/2023 2
54,364 7,000,000FMBS - SERIES A - 7.18% DUE 8/11/2023 3
1,296,086 51,547,000ADVANCE ASSOCIATED-AVISTA CAPITAL II (ToPRS) 4
158,304 25,000,000FMBS - 6.37% SERIES C 5
1,812,935 150,000,000FMBS - 6.25% SERIES 6
367,500 Discount- FMBS - 6.25% SERIES 7
4,702,304 150,000,000FMBS - 5.70% SERIES 8
222,000 Discount- FMBS - 5.70% SERIES 9
2,284,788 250,000,000FMBS - 5.125% SERIES 10
575,000 Discount- FMBS - 5.125% SERIES 11
66,700,000COLSTRIP 2010A PCRBs DUE 2032 12
17,000,000COLSTRIP 2010B PCRBs DUE 2034 13
385,129 52,000,000FMBS - 3.89% SERIES 14
258,834 35,000,000FMBS - 5.55% SERIES 15
692,833 85,000,0004.45% SERIES DUE 12-14-2041 16
730,833 80,000,0004.23% SERIES DUE 11-29-2047 17
428,205 60,000,000FMBS- 4.11% SERIES 18
590,761 100,000,000FMBS- 4.37% SERIES 19
1,042,569 175,000,000FMBS- 3.54% SERIES 20
552,539 90,000,000FMBS 3.91% SERIES 21
4,246,448 375,000,000FMBS 4.35% SERIES 22
378,750 Discount- FMBS - 4.350% SERIES 23
1,108,340 180,000,000FMBS 3.43% SERIES 24
1,071,782 165,000,000FMBS 3.07% SERIES 25
26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 2,120,747,000 23,010,782
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Nominal Dateof Issue Date ofMaturity
AMORTIZATION PERIOD
Date From Date To
Outstanding(Total amount outstanding withoutreduction for amounts held byrespondent)
Interest for YearAmount(d)(e)(f)(g)(h)(i)
10. Identify separate undisposed amounts applicable to issues which were redeemed in prior years.
11. Explain any debits and credits other than debited to Account 428, Amortization and Expense, or credited to Account 429, Premium
on Debt - Credit.
12. In a footnote, give explanatory (details) for Accounts 223 and 224 of net changes during the year. With respect to long-term
advances, show for each company: (a) principal advanced during year, (b) interest added to principal amount, and (c) principle repaid
during year. Give Commission authorization numbers and dates.
13. If the respondent has pledged any of its long-term debt securities give particulars (details) in a footnote including name of pledgee
and purpose of the pledge.
14. If the respondent has any long-term debt securities which have been nominally issued and are nominally outstanding at end of year,
describe such securities in a footnote.
15. If interest expense was incurred during the year on any obligations retired or reacquired before end of year, include such interest
expense in column (i). Explain in a footnote any difference between the total of column (i) and the total of Account 427, interest on
Long-Term Debt and Account 430, Interest on Debt to Associated Companies.
16. Give particulars (details) concerning any long-term debt authorized by a regulatory commission but not yet issued.
5,500,000 414,15005-05-202305-06-199305-05-202305-06-1993 1
1,000,000 75,40005-05-202305-07-199305-05-202305-07-1993 2
7,000,000 502,60008-11-202308-12-199308-11-202308-12-1993 3
51,547,000 712,86406-01-203706-03-199706-01-203706-03-1997 4
25,000,000 1,592,50006-19-202806-19-199806-19-202806-19-1998 5
150,000,000 9,375,00012-01-203511-17-200512-01-203511-17-2005 6
7
150,000,000 8,550,00007-01-203712-15-200607-01-203712-15-2006 8
9
250,000,000 12,812,50004-01-202209-22-200904-01-202209-22-2009 10
11
66,700,000 475,77510-1-203212-15-201010-1-203212-15-2010 12
17,000,000 121,4253-1-203412-15-20103-1-203412-15-2010 13
1,960,99212-20-202012-20-201012-20-202012-20-2010 14
35,000,000 1,942,50012-20-204012-20-201012-20-204012-20-2010 15
85,000,000 3,782,50012-14-204112-14-201112-14-204112-14-2011 16
80,000,000 3,384,00011-29-204711-30-201211-29-204711-30-2012 17
60,000,000 2,466,00012-1-204412-18-201412-1-204412-18-2014 18
100,000,000 4,370,00012-1-204512-16-201512-1-204512-16-2015 19
175,000,000 6,195,00012-1-205112-15-201612-1-205112-15-2016 20
90,000,000 3,519,00012-1/204712-14-201712-1-204712-14-2017 21
375,000,000 16,312,50006-1-204806-1-201806-01-204805-22-2018 22
23
180,000,000 6,174,00012-01-204912-01-201912-01-204911-26-2019 24
165,000,000 5,065,50009-30-205009-30-202009-30-205009-30-2020 25
26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 2,068,747,000 89,804,206
Schedule Page: 256 Line No.: 4 Column: a
Upon issuance Avista Capital II issued $1.5 million of Common Trust Securities to the
Company. In December 2000, the Company purchased $10.0 million of these Preferred Trust
Securities.
Schedule Page: 256 Line No.: 12 Column: a
The Company reacquired this debt in 2010. These bonds have not been retired or canceled; the Company plans, based
on liquidity needs and market conditions, to remarket these bonds at a future date.
Schedule Page: 256 Line No.: 12 Column: c
The Company reacquired these bonds in 2010.
Schedule Page: 256 Line No.: 13 Column: a
The Company reacquired this debt in 2010. These bonds have not been retired or canceled; the Company plans, based
on liquidity needs and market conditions, to remarket these bonds at a future date.
Schedule Page: 256 Line No.: 13 Column: c
The Company reacquired these bonds in 2010.
Schedule Page: 256 Line No.: 25 Column: a
The new issuance is based on the following state commission orders:
1. Order of the Washington Utilities and Transportation Commission in Docket No. 171210
entered into January 11, 2018 and Order of the Washington Utilities and Transporation
Commission in Docket No. 190554 entered into September 12, 2019;
2. Order of the Idaho Public Utilities Commission, Order No. 33978 entered January 30,
2018 and Order of the Idaho Public Utilities Commission, Order No. 34386 entered July 31,
2019;
3. Order of the Public Utility Commission of Oregon, Order No. 19-249, entered July 30,
2019;
4. Order of the Public Service Commission of the State of Montana, Default Order No. 4535
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
Avista Corporation X 04/15/2021 2020/Q4
Particulars (Details)(b)(a)Amount LineNo.
1. Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. Include in the reconciliation, as far as practicable, the same detail as furnished on Schedule M-1 of the tax return for
the year. Submit a reconciliation even though there is no taxable income for the year. Indicate clearly the nature of each reconciling amount.
2. If the utility is a member of a group which files a consolidated Federal tax return, reconcile reported net income with taxable net income as if a separate
return were to be field, indicating, however, intercompany amounts to be eliminated in such a consolidated return. State names of group member, tax
assigned to each group member, and basis of allocation, assignment, or sharing of the consolidated tax among the group members.
3. A substitute page, designed to meet a particular need of a company, may be used as Long as the data is consistent and meets the requirements of the
above instructions. For electronic reporting purposes complete Line 27 and provide the substitute Page in the context of a footnote.
134,517,322Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
8,180,842 5
6
7
8
Deductions Recorded on Books Not Deducted for Return 9
301,465,914 10
7,957,636Federal Income Tax Expense 11
-534,566State Income Tax Expense Adj 12
13
Income Recorded on Books Not Included in Return 14
-39,821,309 15
16
17
18
Deductions on Return Not Charged Against Book Income 19
-413,202,637 20
21
22
23
-5,304,376Equity in Subs Earnings 24
626,652Corporate Overhead Unallocated Subs 25
26
-6,114,523Federal Tax Net Income 27
Show Computation of Tax: 28
29
-1,284,050Federal Tax at 21% 30
31
-39,280,403Prior Year True Ups 32
33
-690,508Customer refunds related to prior years at 35 percent 34
35
-41,254,961Total Federal Current Tax Expense 36
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96)Page 261
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a)(b)(c)(d)(e)(f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
FEDERAL: 1
-315,720-5,428,255 247,648Income Tax 2014 2
-202,821-4,279,292Income Tax 2015 3
520,410-520,411Income Tax 2016 4
-104,399 333,945-104,399Income Tax 2017 5
-17,125,557-1,252,305Income Tax 2018 6
-15,456,612-6,543,388Income Tax 2019 7
-65,559Income Tax (Current) 8
-622,940-41,500,920-8,172,855 Total Federal 9
10
STATE OF WASHINGTON: 11
235,053Payroll Taxes 2020 12
-5,585 5,584Property Tax 2018 13
17,835,066-905,401 18,740,467Property Tax 2019 14
493 18,090,306Property Tax 2020 15
892,951Excise Tax 2016 16
2,981,767 66,765 2,915,002Excise Tax 2019 17
24,129,961 27,059,961Excise Tax 2020 18
1,859 1,849 490Natural Gas Use Tax 19
23,992,990 23,928,191 3,130,051Municipal Occupation Tax 20
-333,921-301,505-31,729Community Solar 21
-2,669 2,669Sales & Use Tax 2018 22
160,363 -126,166 286,528Sales & Use Tax 2019 23
1,061,712 128,835 1,048,091Sales & Use Tax 2020 24
70,065,343 68,982,672 25,942,013 Total Washington 25
26
STATE OF IDAHO: 27
-10,224-319,616Income Tax 2019 28
Income Tax 2020 29
16,105Payroll Taxes 2020 30
3,817,414 58 3,817,356Property Tax 2019 31
3,954,640 7,887,651Property Tax 2020 32
27,134 27,134Hydro Relicensing 33
11,381 2,040 9,341Sales & Use Tax 2019 34
187,358 -2,040 216,900Sales & Use Tax 2020 35
Irrigation Credits 2020 36
24,981-1,296 26,277KWH Tax 2019 37
341,275 369,390KWH Tax 2020 38
-21 21Franchise Tax 2018 39
1,103,288 21 1,103,281Franchise Tax 2019 40
-12,378,042
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 78,385,117 112,191,434 -1 38,022,918
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
1
-908,767-154,443-4,864,887 2
-420,342 194,476-4,076,471 3
341,317 701,981 4
333,945 5
689-12,282-18,377,863 6
-18,630,041-22,547,949-22,000,000 7
35,495-101,054-65,559 8
-19,581,649-21,919,271-49,050,835 9
10
11
-2,772,402 2,772,402-235,053 12
-60-5,525 13
-229,366-676,035 14
3,707,491 14,382,815 18,089,813 15
892,951 16
-77 66,842 17
6,046,771 21,013,190 2,930,000 18
1,849 480 19
5,478,423 18,449,768 3,065,253 20
-301,505 688 21
22
-1 23
1,048,091 115,214 24
12,977,366 56,005,306 24,859,345 25
26
27
-1,533-8,691-329,840 28
29
-495,425 495,425-16,105 30
8 50 31
1,759,072 6,128,579 3,933,011 32
27,134 33
34
216,900 27,502 35
-3,558 3,558 36
-1,296 37
369,390 28,115 38
39
-3,224 3,224 14 40
FERC FORM NO. 1 (ED. 12-96)Page 263
41-53,428,314 82,646,398 -21,919,271 17,657,990 45,266,874
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a)(b)(c)(d)(e)(f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
3,535,443 4,625,749Franchise Tax 2020 1
13,019,019 13,115,362-319,616 4,956,276 Total Idaho 2
3
STATE OF MONTANA: 4
-359,950-235,616-124,334Income Tax 2019 5
50-2Income Tax 2020 6
4,910Payroll Taxes 2020 7
5,753,442 -1-14,367 5,767,811Property Tax 2019 8
5,924,294 11,822,356Property Tax 2020 9
1,837 1,837Colstrip Generation Tax 10
226,610 226,610KWH Tax 2019 11
760,983 962,699KWH Tax 2020 12
66 109 15Consumer Council Fee 13
227 218 51Public Commission Fee 14
12,312,469 -1 12,537,234-124,334 5,994,487 Total Montana 15
16
STATE OF OREGON: 17
Income Tax 2019 18
100,000 100,000Income Tax 2020 19
600,000 800,004Corp Activities Tax-CAT 2020 20
9,574Payroll Taxes 2020 21
3,759,648-3,759,647Property Tax 2019 22
8,094,817 4,047,330Property Tax 2020 23
43,414 43,414Franchise Tax 2018 24
1,046,389 1,046,390Franchise Tax 2019 25
2,758,478 3,796,632Franchise Tax 2020 26
12,652,672 12,503,614-3,759,647 1,089,804 Total Oregon 27
28
STATE OF CALIFORNIA: 29
800 800Income Tax 2020 30
800 800 Total California 31
32
MISCELLANEOUS STATES: 33
-1,211 279-1,590Income Tax (Current) 34
402Payroll Taxes 2020 35
-809 279-1,590 Total Misc States 36
37
MISCELLANEOUS OTHER 38
6,664,088 14,683,386Payroll Taxes 2020 39
Timber Excise Tax (2017) 40
-12,378,042
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 78,385,117 112,191,434 -1 38,022,918
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
1,120,436 3,505,313 1,090,306 1
2,592,676 10,522,686-329,840 5,062,843 2
3
4
-235,616 5
-2-52 6
-132,045 132,045-4,910 7
-14,367 8
11,822,356 5,898,062 9
2,067-230 10
11
962,699 201,716 12
109 58 13
218 42 14
-129,978 12,667,212-52 6,094,968 15
16
17
18
70,000 30,000 19
800,004 200,004 20
-9,053 9,053-9,574 21
2,112,879 1,646,769 22
2,282,154 1,765,176-4,047,487 23
24
25
3,796,632 1,038,154 26
9,052,616 3,450,998-4,047,487 1,228,584 27
28
29
800 30
800 31
32
33
83 196-100 34
-402 35
83 196-100-402 36
37
38
14,683,386 8,019,298 39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41-53,428,314 82,646,398 -21,919,271 17,657,990 45,266,874
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Kind of Tax
(See instruction 5)
BALANCE AT BEGINNING OF YEAR
Taxes Accrued(Account 236)Prepaid Taxes(Include in Account 165)
TaxesChargedDuringYear
TaxesPaid During
Adjust-
mentsYear(a)(b)(c)(d)(e)(f)
1. Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. If the actual,
or estimated amounts of such taxes are know, show the amounts in a footnote and designate whether estimated or actual amounts.
2. Include on this page, taxes paid during the year and charged direct to final accounts, (not charged to prepaid or accrued taxes.)
Enter the amounts in both columns (d) and (e). The balancing of this page is not affected by the inclusion of these taxes.
3. Include in column (d) taxes charged during the year, taxes charged to operations and other accounts through (a) accruals credited to taxes accrued,
(b)amounts credited to proportions of prepaid taxes chargeable to current year, and (c) taxes paid and charged direct to operations or accounts other than
accrued and prepaid tax accounts.
4. List the aggregate of each kind of tax in such manner that the total tax for each State and subdivision can readily be ascertained.
-1,933,932-1,933,932WA Renewable Energy 1
-32,834 33,158Misc Distribution 2
34,724 29,456 7,180Thermal Fuel Tax 3
4,764,880 12,746,076 40,338Total Other 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
-12,378,042
FERC FORM NO. 1 (ED. 12-96)Page 262.2
TOTAL41 78,385,117 112,191,434 -1 38,022,918
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.(Taxes accrued
BALANCE AT END OF YEARPrepaid Taxes Electric(Account 408.1, 409.1)Extraordinary Items(Account 409.3)
Adjustments to Ret.OtherEarnings (Account 439)(g) (h) (i) (j) (k) (l)Account 236)(Incl. in Account 165)
DISTRIBUTION OF TAXES CHARGED
5. If any tax (exclude Federal and State income taxes)- covers more then one year, show the required information separately for each tax year, identifying
the year in column (a).
6. Enter all adjustments of the accrued and prepaid tax accounts in column (f) and explain each adjustment in a foot- note. Designate debit adjustments
by parentheses.
7. Do not include on this page entries with respect to deferred income taxes or taxes collected through payroll deductions or otherwise pending
transmittal of such taxes to the taxing authority.
8. Report in columns (i) through (l) how the taxes were distributed. Report in column (I) only the amounts charged to Accounts 408.1 and 409.1
pertaining to electric operations. Report in column (l) the amounts charged to Accounts 408.1 and 109.1 pertaining to other utility departments and
amounts charged to Accounts 408.2 and 409.2. Also shown in column (l) the taxes charged to utility plant or other balance sheet accounts.
9. For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
-1,933,932 1
-32,834 326 2
29,456 1,912 3
12,746,076 8,021,536 4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.2
41-53,428,314 82,646,398 -21,919,271 17,657,990 45,266,874
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Account Balance at Beginning
(c)(b)(a)
of YearSubdivisions AdjustmentsDeferred for Year Allocations toCurrent Year's IncomeAccount No. Amount Account No. Amount(d) (e) (f)(g)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and nonutility
operations. Explain by footnote any correction adjustments to the account balance shown in column (g).Include in column (i) the average
period over which the tax credits are amortized.
Electric Utility 1
3% 2
4% 3
7% 4
10% 5
Fed ITC 29,182,023 411 520,104 6
Idaho ITC 411 1,066,366 -12,205 411 30,382 7
TOTAL 30,248,389 -12,205 550,486 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
Gas Property (100% 7,116 411 7,116 10
Idaho ITC 411 188,456 -2,154 411 5,373 11
TOTAL PROPERTY 195,572 -2,154 12,489 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89) Page 266
Balance at End
(i)(h)
of Year
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255) (continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
3
4
5
28,661,919 6
1,023,779 7
29,685,698 8
9
10
180,929 11
180,929 12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-89) Page 267
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER DEFFERED CREDITS (Account 253)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Description and Other DEBITS
Credits
Account(c)(b)(a)
Balance at
End of Year
(d)
Deferred Credits Amount
(e)
Balance at
Beginning of Year Contra
(f)
1. Report below the particulars (details) called for concerning other deferred credits.
2. For any deferred credit being amortized, show the period of amortization.
3. Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100,000, whichever is greater) may be grouped by classes.
1,125,000Deferred Gas Exchange 1,125,000 1
297,078Kettle Falls Diesel Leak 43,072 254,006514, 545 2
193,105Bills Pole Rentals 646,335 918,828 465,598172 3
8,947,679Defer Comp Active Execs 9,173,880 2,115,126 1,888,925128 4
140,000Executive Incent Plan 140,000 5
1,243,970Unbilled Revenue 105,445 18,629,136 19,767,661908 6
14,154,482WA Energy Recovery Mechanism 11,383,248 15,861,541 18,632,775Various 7
3,526,878Decoupling Deferred Credits 1,855,168 9,917,842 11,589,552456, 495 8
Reg Liability-COVID-19 Deferral 6,660,724 6,660,724 9
31,366Misc Deferred Credits 317,157 341,916 56,125186, 550 10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (ED. 12-94)Page 269
47 TOTAL 54,445,113 52,654,642 31,450,029 29,659,558
Schedule Page: 269 Line No.: 1 Column: a
FortisBC and Avista exchange volumes of gas on a firm delivery basis during different time
periods. Amortization is recorded monthly every year. This contract ends April 2025.
Schedule Page: 269 Line No.: 2 Column: a
Kettle Falls Generation Station undergound fuel leak. Continuing remediation liability is
recorded.
Schedule Page: 269 Line No.: 7 Column: a
The Washington Energy Recovery Mechanism (ERM) allows Avista to periodically increase or
decrease electric rates. This accounting method tracks differences between actual power
supply costs, net of wholesale sales and sales of fuel, and the amount included in base
rates.
Schedule Page: 269 Line No.: 8 Column: a
Washington Decoupling for electric and natural gas for a 5 year period beginning January
1, 2015. Idaho approved for an initial term of 3 years beginning January 1, 2016, but
extended thru March 31, 2025. Oregon approved similar to Washington and Idaho beginning
March 1, 2016.
Decoupling revenue deferrals are recognized during the period they occur, subject to
certain limitations. Revenue is expected to be collected within 24 months of the deferral.
Schedule Page: 269 Line No.: 9 Column: a
Deferral of COVID-19 costs as per Idaho PUC Order No. 34718, Oregon PUC Order No. 20-401,
Docket UM 2069 and WA UTC Order No. 01, Dockets UE-200407 and UG-200408.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes rating to property not
subject to accelerated amortization
2. For other (Specify),include deferrals relating to other income and deductions.
Account 282 1
Electric 339,209,550 44,688,310 2
Gas 86,849,511 32,594,670 3
Other 88,810,946 -1,572,234 4
TOTAL (Enter Total of lines 2 thru 4) 514,870,007 75,710,746 5
6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 514,870,007 75,710,746 9
Classification of TOTAL 10
Federal Income Tax 514,870,007 75,710,746 11
State Income Tax 12
Local Income Tax 13
FERC FORM NO. 1 (ED. 12-96)Page 274
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of YearDebitsCreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Use footnotes as required.
1
398,244,120 14,346,260 2
143,910,347 24,466,166 3
61,260,966 25,977,746 4
603,415,433 25,977,746 38,812,426 5
6
7
8
603,415,433 25,977,746 38,812,426 9
10
603,415,433 25,977,746 38,812,426 11
12
13
FERC FORM NO. 1 (ED. 12-96)Page 275
NOTES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Account
(a) (b) (c) (d)
Balance atBeginning of Year
CHANGES DURING YEAR
Amounts Debited Amounts Credited to Account 410.1 to Account 411.1
1. Report the information called for below concerning the respondent’s accounting for deferred income taxes relating to amounts
recorded in Account 283.
2. For other (Specify),include deferrals relating to other income and deductions.
Account 283 1
Electric 2
745,973 1,968,358 13,393,102 Electric 3
4
5
6
7
8
745,973 1,968,358 13,393,102TOTAL Electric (Total of lines 3 thru 8) 9
Gas 10
362,272 1,762,139 2,385,096 Gas 11
12
13
14
15
16
362,272 1,762,139 2,385,096TOTAL Gas (Total of lines 11 thru 16) 17
5,921,872 163,807,011Other 18
1,108,245 9,652,369 179,585,209TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
1,108,245 9,652,369 179,585,209Federal Income Tax 21
State Income Tax 22
Local Income Tax 23
FERC FORM NO. 1 (ED. 12-96)Page 276
NOTES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
Debits CreditsAmounts Debited
to Account 410.2
Amounts Credited
to Account 411.2 AccountCredited Amount DebitedAccount Amount
(e)(f)(h)(j)(k)(g)(i)
3. Provide in the space below explanations for Page 276 and 277. Include amounts relating to insignificant items listed under Other.
4. Use footnotes as required.
1
2
12,928,052 899,441 275,061 1,063,055 3
4
5
6
7
8
12,928,052 899,441 275,061 1,063,055 9
10
3,042,547-27,961 714,455 11
12
13
14
15
16
3,042,547-27,961 714,455 17
184,147,569 14,315,742 102,944 18
200,118,168 14,315,742 899,441 350,044 1,777,510 19
20
200,118,168 14,315,742 899,441 350,044 1,777,510 21
22
23
FERC FORM NO. 1 (ED. 12-96)Page 277
NOTES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY LIABILITIES (Account 254)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Description and Purpose of DEBITS
CreditsAccount
(d)(c)(a)
Balance at End
of Current
Quarter/Year
(e)
Other Regulatory Liabilities Amount
(f)
Credited
1. Report below the particulars (details) called for concerning other regulatory liabilities, including rate order docket number, if applicable.
2. Minor items (5% of the Balance in Account 254 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3. For Regulatory Liabilities being amortized, show period of amortization.
Balance at Begining
of Current
Quarter/Year
(b)
5,191,030 1,072,903 8,874,779 4,756,652Idaho Investment Tax Credit 190 1
1,111,427 1,099,869 11,558Oregon BETC Credit 190, 283 2
17,088,285 2,042,533 15,045,752Interest Rate Swaps 427, 175 3
528,308 22,008 506,300Nez Perce 557 4
686,970 686,970Idaho Earnings Test 5
101,371 1,081,410 2,335,746 3,315,785Decoupling Rebate 495, 182 6
25,802,794 53,679,690 26,486,130 54,363,026WA ERM 182, 557 7
7,963,912 141,936 7,821,976Deferred Federal ITC - Varies 190 8
398,370,456 15,431,659 382,938,797Plant Excess Deferred 190, 282 9
11,089,633 11,015,304 74,329Non Plant Excess Deferred 108, 411 10
589,729 897,416 307,687Reg Liability MDM System 11
2,263,637 2,606,448 342,811AFUDC Equity Tax Deferral 12
952,403 13,254 1,879,242 940,093Exist Meters/ERTS Excess Depr Deferred 407 13
294,533 12,389,437 540,275 12,635,179DSM Tariff Rider 182,431,908 14
2,401,864 12,954,756 3,783,957 14,336,849Low Income Energy Assistance 242, 908 15
397,359 397,359Deferred CS2 & Colstrip O&M 407 16
4,348,735 6,385,196 994,068 3,030,529Reg Liability - Tax Reform Amortization - 1 year 407, 431 17
1,532,183 1,532,183Reg Liability - Energy Efficiency Assistance 18
1,071,334 3,357,111 4,428,445Reg Liability - Colstrip Community Fund 407, 431 19
4,288,655 4,288,655Reg Liability - COVID-19 Deferral 20
492,504 30,122 8,459,685 7,997,303Other Regulatory Liabilities - Varies 143,190,407 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04)Page 278
41 TOTAL 110,743,014 118,828,770 473,121,377 481,207,133
Schedule Page: 278 Line No.: 1 Column: a
Not amortized
Schedule Page: 278 Line No.: 2 Column: a
Not amortized
Schedule Page: 278 Line No.: 3 Column: a
Mark-to-Market gains and losses for interest rate swap derivatives. Upon settlement,
amortization of Regulatory Assets and Liabilities as a component of interest expense over
the term of the associated debt.
Schedule Page: 278 Line No.: 6 Column: a
Decoupling rebates are recognized during the period they occur, subject to certain
limitations. Rebates are returned to customers within 24 months of the deferral.
Schedule Page: 278 Line No.: 7 Column: a
The Washington Energy Recovery Mechanism allows Avista to periodically increase or
decrease electric rates. This accounting method tracks differences between actual power
supply costs, net of wholesale sales and sales of fuel, and the amount included in base
rates. Avista files yearly on or before April 1 for prudence review by the commission.
Schedule Page: 278 Line No.: 8 Column: a
Noxon ITC - 65 year amortization, ends 2077
Community Solar ITC - 20 year amortization, ends 2035
Nine Mile ITC - 65 year amortization, ends 2080
Schedule Page: 278 Line No.: 9 Column: a
Amortized over remaining book life of plant, estimated 36 years.
Schedule Page: 278 Line No.: 10 Column: a
Washington Gas and Oregon Gas costs are amortized over 1 year. Idaho Electric was offset
against Colstrip excess depreciation impacts from Docket# AVU-E-18-03 Order No. 34276.
Schedule Page: 278 Line No.: 12 Column: a
Amortization period not yet determined in all jurisdictions. Idaho Electric Settlement
AVU-E-19-04 ordered a transfer to account 254320 for Idaho portion.
Schedule Page: 278 Line No.: 13 Column: a
Washington Docket#s UE-180418 and UG-180419
Schedule Page: 278 Line No.: 14 Column: a
Washington Orders Dockets UE-190912 and UG-190920, Idaho Docket AVU-E-18-12 and
AVU-G-18-08, Oregon Order No. 19-424
Schedule Page: 278 Line No.: 15 Column: a
Washington Docket# UE-190912, UG-190920
Idaho Docket# AVU-E-18-12, AVU-G-18-08
Oregon RG 81, Docket No. ADV 1063 (Advice No. 19-10-G)
Schedule Page: 278 Line No.: 17 Column: a
Washington Docket#s UE-170485, UG-170486
Oregon Advice# ADV 923/19-01-G (Schedule 474)
Idaho Case# GNR-U-18-01
Schedule Page: 278 Line No.: 18 Column: a
Avista's contribution in the Energy Assistance Fund as per Idaho Settlement Stipulation
Case# AVU-E-19-04 (Page 10, #16 a.ii).
Schedule Page: 278 Line No.: 19 Column: a
Washington Order 09 in Dockets UE-190334, UE-190222. Deferral of funds from shareholders
and customers set aside to helping the Colstrip community transition away from economic
activity related to coal-fired generation.
Schedule Page: 278 Line No.: 20 Column: a
Deferral of COVID-19 costs as per Idaho PUC Order No. 34718, Oregon PUC Order No. 20-401,
Docket UM 2069 and WA UTC Order No. 01, Dockets UE-200407 and UG-200408.
Schedule Page: 278 Line No.: 21 Column: a
FAS 109 ITC - 18 year amortization, ends 2020.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
State income tax net operating loss carryforward of $7.5M recorded during the year and
will reverse over the period in which we are able to utilize the loss to offset taxable
income on the Idaho, Montana, and Oregon tax returns.
Deferral of depreciation expense of $0.5M per Idaho Order No. 34276, Case Nos. AVU-E-18-03
and AVU-G-18-02.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Title of Account
(c)(b)(a)
Operating Revenues Year
to Date Quarterly/Annual
1. The following instructions generally apply to the annual version of these pages. Do not report quarterly data in columns (c), (e), (f), and (g). Unbilled revenues and MWH
related to unbilled revenues need not be reported separately as required in the annual version of these pages.
2. Report below operating revenues for each prescribed account, and manufactured gas revenues in total.
3. Report number of customers, columns (f) and (g), on the basis of meters, in addition to the number of flat rate accounts; except that where separate meter readings are
added for billing purposes, one customer should be counted for each group of meters added. The -average number of customers means the average of twelve figures at the
close of each month.
4. If increases or decreases from previous period (columns (c),(e), and (g)), are not derived from previously reported figures, explain any inconsistencies in a footnote.
5. Disclose amounts of $250,000 or greater in a footnote for accounts 451, 456, and 457.2.
Operating Revenues
Previous year (no Quarterly)
Sales of Electricity 1
369,101,530(440) Residential Sales 377,785,465 2
(442) Commercial and Industrial Sales 3
317,589,170Small (or Comm.) (See Instr. 4) 303,971,920 4
114,530,530Large (or Ind.) (See Instr. 4) 113,563,149 5
7,447,635(444) Public Street and Highway Lighting 7,303,244 6
(445) Other Sales to Public Authorities 7
(446) Sales to Railroads and Railways 8
1,502,287(448) Interdepartmental Sales 1,422,102 9
810,171,152TOTAL Sales to Ultimate Consumers 804,045,880 10
81,398,279(447) Sales for Resale 82,055,793 11
891,569,431TOTAL Sales of Electricity 886,101,673 12
-2,908,847(Less) (449.1) Provision for Rate Refunds -1,601,776 13
894,478,278TOTAL Revenues Net of Prov. for Refunds 887,703,449 14
Other Operating Revenues 15
(450) Forfeited Discounts 16
342,546(451) Miscellaneous Service Revenues 150,458 17
344,332(453) Sales of Water and Water Power 515,996 18
2,797,207(454) Rent from Electric Property 2,028,311 19
(455) Interdepartmental Rents 20
69,178,898(456) Other Electric Revenues 35,962,624 21
16,342,483(456.1) Revenues from Transmission of Electricity of Others 16,370,526 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
89,005,466TOTAL Other Operating Revenues 55,027,915 26
983,483,744TOTAL Electric Operating Revenues 942,731,364 27
Page 300FERC FORM NO. 1/3-Q (REV. 12-05)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC OPERATING REVENUES (Account 400)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MEGAWATT HOURS SOLD
Previous Year (no Quarterly)Current Year (no Quarterly)
AVG.NO. CUSTOMERS PER MONTH
Year to Date Quarterly/Annual Amount Previous year (no Quarterly)
(d)(e)(f)(g)
6. Commercial and industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial) regularly used by
the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform System of Accounts. Explain basis of
classification in a footnote.)
7. See pages 108-109, Important Changes During Period, for important new territory added and important rate increase or decreases.
8. For Lines 2,4,5,and 6, see Page 304 for amounts relating to unbilled revenue by accounts.
9. Include unmetered sales. Provide details of such Sales in a footnote.
1
3,766,048 345,064 349,890 3,807,041 2
3
3,170,031 42,930 43,399 2,994,648 4
2,047,228 1,305 1,297 2,042,265 5
17,973 612 639 17,654 6
7
8
14,708 148 152 13,435 9
9,015,988 390,059 395,377 8,875,043 10
2,942,248 2,796,393 11
11,958,236 390,059 395,377 11,671,436 12
13
11,958,236 390,059 395,377 11,671,436 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
2,416,764
23,712
FERC FORM NO. 1/3-Q (REV. 12-05)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 RESIDENTIAL SALES (440)
3,639,357 332,474 10,946 0.0951 346,016,498 2 1 Residential Service
5,537 438 12,642 0.0637 352,592 3 2 Residential Service
4 3 Residential Service
88,207 15,904 5,546 0.1448 12,770,530 5 12 Res. & Farm Gen. Service
6 15 MOPS II Residential
38,095 65 586,077 0.0922 3,511,536 7 22 Res. & Farm Lg. Gen. Service
12 4 3,000 0.1524 1,829 8 30 Pumping-Special
8,805 1,785 4,933 0.1319 1,161,801 9 32 Res. & Farm Pumping Service
3,316 0.3503 1,161,570 10 48 Res. & Farm Area Lighting
11 49 Area Lighting-High-Press.
12 56 Centralia Refund
146,268 13 95 Wind Power
14 72 Residential Service
15 73 Residential Service
16 74 Residential Service
17 76 Residential Service
18 77 Residential Service
-29,996 19 58A Tax Adjustment
10,173,345 20 58 Tax Adjustment
3,783,329 350,670 10,789 0.0992 375,265,973 21 SubTotal
23,714 0.1062 2,519,493 22 Residential-Unbilled
3,807,043 350,670 10,856 0.0992 377,785,466 23 Total Residential Sales
24
25 COMMERCIAL SALES (442)
26 2 General Service
27 3 General Service
891,911 39,581 22,534 0.1151 102,700,293 28 11 General Service
29 12 Res. & Farm Gen. Service
30 16 MOPS II Commercial
31 19 Contract-General Service
1,659,809 2,630 631,106 0.0946 157,071,759 32 21 Large General Service
332,268 13 25,559,077 0.0659 21,894,391 33 25 Extra Lg. Gen. Service
34 28 Contract-Extra Large Serv
101,070 1,274 79,333 0.0919 9,287,613 35 31 Pumping Service
4,532 0.3137 1,421,609 36 47 Area Lighting-Sod. Vap
2,209 0.3094 683,514 37 49 Area Lighting-High-Press.
38 56 Centralia Refune
77,872 39 95 Wind Power
40 74 Large General Service
11,671,436 886,101,668 396,236 29,456 0.0759
21,951 2,416,764 0 0 0.1101
11,649,485 883,684,904 396,236 29,400 0.0759
FERC FORM NO. 1 (ED. 12-95)Page 304
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 75 Large General Service
2 76 Large General Service
3 77 General Service
-39,273 4 58A Tax Adjustment
10,655,764 5 58 Tax Adjustment
2,991,799 43,498 68,780 0.1015 303,753,542 6 SubTotal
2,849 0.0767 218,378 7 Commercial-Unbilled
2,994,648 43,498 68,846 0.1015 303,971,920 8 Total Commercial
9
10 INDUSTRIAL SALES (442)
11 2 General Service
12 3 General Service
13 8 Lg Gen Time of Use
10,928 239 45,724 0.1164 1,271,634 14 11 General Service
15 12 Res. & Farm Gen. Service
145,579 126 1,155,389 0.0945 13,757,416 16 21 Large General Service
1,797,372 22 81,698,727 0.0500 89,793,336 17 25 Extra Lg. Gen. Service
18 28 Contract - Extra Large Service
19 29 Contract Lg. Gen. Service
32,837 50 656,740 0.0765 2,510,581 20 30 Pumping Service - Special
56,223 714 78,744 0.0935 5,257,367 21 31 Pumping Service
3,749 126 29,754 0.0941 352,880 22 32 Pumping Svc Res & Firm
132 0.2508 33,103 23 47 Area Lighting-Sod. Vap.
55 0.2893 15,911 24 49 Area Lighting - High-Press
840 25 95 Wind Power
26 48 Area Lighting-Sod. Vap.
27 73 General Service
28 74 Large General Service
29 75 Large General Service
30 76 Pumping Service
31 77 General Service
-1,397 32 58A Tax Adjustment
892,584 33 58 Tax Adjustment
2,046,875 1,277 1,602,878 0.0556 113,884,255 34 SubTotal
-4,610 0.0697-321,107 35 Industrial-Unbilled
2,042,265 1,277 1,599,268 0.0556 113,563,148 36 Total Industrial
37
38 STREET AND HWY LIGHTING (444)
39 6 Mercury Vapor St. Ltg.
40 7 HP Sodium Vap. St. Ltg
11,671,436 886,101,668 396,236 29,456 0.0759
21,951 2,416,764 0 0 0.1101
11,649,485 883,684,904 396,236 29,400 0.0759
FERC FORM NO. 1 (ED. 12-95)Page 304.1
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES OF ELECTRICITY BY RATE SCHEDULES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Number and Title of Rate schedule MWh Sold
(b)(a)
Revenue
(c)
Average Numberof Customers(d)
KWh of SalesPer Customer(e)
Revenue PerKWh Sold(f)
1. Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2. Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. If the sales under any rate schedule are classified in more than one revenue account, List the rate schedule and sales data under each
applicable revenue account subheading.
3. Where the same customers are served under more than one rate schedule in the same revenue account classification (such as a general residential
schedule and an off peak water heating schedule), the entries in column (d) for the special schedule should denote the duplication in number of reported
customers.
4. The average number of customers should be the number of bills rendered during the year divided by the number of billing periods during the year (12 if
all billings are made monthly).
5. For any rate schedule having a fuel adjustment clause state in a footnote the estimated additional revenue billed pursuant thereto.
6. Report amount of unbilled revenue as of end of year for each applicable revenue account subheading.
1 11 General Service
35 5 7,000 0.1826 6,391 2 41 Co-Owned St. Lt. Service
14,592 536 27,224 0.4604 6,717,797 3 42 Co-Owned St. Lt. Service
4 High-Press. Sod. Vap.
5 43 Cust-Owned St. Lt. Energy
6 and Maint. Service
435 25 17,400 0.1605 69,831 7 44 Cust-Owned St. Lt. Energy
8 and Maint. Svce - High-Pres
9 Sodium Vapor
777 13 59,769 0.0842 65,400 10 45 Cust. Owned St. Lt. Energy Svc
1,815 60 30,250 0.1077 195,510 11 46 Cust. Owned St. Lt. Energy Svc
-681 12 58A Tax Adjustment
248,995 13 58 Tax Adjustment
17,654 639 27,628 0.4137 7,303,243 14 SubTotal
15 Street & Hwy Lighting-Unbilled
17,654 639 27,628 0.4137 7,303,243 16 Total Street & Hwy Lighting
17
18 OTHER SALES TO PUBLIC
19 (445)
20 None
21
13,435 152 88,388 0.1058 1,421,459 22 INTERDEPARTMENTAL SALES
643 23 58 Tax Adjustment
13,435 152 88,388 0.1059 1,422,102 24 Total Interdepartmental
25
26 SALES FOR RESALE (447)
2,796,393 0.0293 82,055,790 27 61 Sales to Other Utilities (NDA)
28
29
2,796,393 0.0293 82,055,790 30 Total Sales for Resale
31
32
33
34
35
36
37
38
39
40
11,671,436 886,101,668 396,236 29,456 0.0759
21,951 2,416,764 0 0 0.1101
11,649,485 883,684,904 396,236 29,400 0.0759
FERC FORM NO. 1 (ED. 12-95)Page 304.2
41 TOTAL Billed
42 Total Unbilled Rev.(See Instr. 6)
43 TOTAL
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Avangrid Renewables, LLC Tariff 9SF 1
Avangrid Renewables, LLC Tariff 9SF 2
Avangrid Renewables, LLC Tariff 12LF 3
BP Energy Company Tariff 9SF 4
Black Hills Power, Inc.Tariff 9SF 5
Bonneville Power Administration Tariff 8LF 6
Bonneville Power Administration Tariff 8LF 7
Bonneville Power Administration Tariff 9SF 8
Bonneville Power Administration Tariff 12LF 9
British Columbia Hydro and Power Author Tariff 12LF 10
Brookfield Energy Marketing, LP Tariff 9SF 11
California Independent System Operator Tariff 9SF 12
Calpine Energy Services LP Tariff 9SF 13
Chelan County PUD No. 1 Tariff 12LF 14
FERC FORM NO. 1 (ED. 12-90)Page 310
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
2,379,350 2,379,350 113,430 1
522,490 522,490 2
640 640 53 3
4,262,180 4,262,180 146,071 4
114,045 114,045 6,415 5
1,294,161 1,294,161 33,739 6
52,458 52,458 2,380 7
1,278,945 1,278,945 58,785 8
1,024 1,024 66 9
615 615 26 10
53,225 53,225 408 11
10,509,328 10,509,328 378,009 12
265,080 265,080 6,805 13
47 476 14
FERC FORM NO. 1 (ED. 12-90)Page 311
0
49,664,905
49,664,905
0
2,796,393
2,796,393
0 0
30,189,876
30,189,876
82,055,793
82,055,793
0
2,201,012
2,201,012
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Citigroup Energy, Inc.Tariff 9SF 1
Clatskanie Peoples PUD Tariff 9SF 2
ConocoPhillips Tariff 9SF 3
Douglas County PUD No. 1 Tariff 9SF 4
Douglas County PUD No. 1 Tariff 12LF 5
EDF Trading North America, LLC Tariff 9SF 6
EDF Trading North America, LLC Tariff 9SF 7
Energy Keepers, Inc.Tariff 9SF 8
Eugene Water & Electric Board Tariff 9SF 9
Exelon Generation Company, LLC Tariff 9SF 10
Grant County PUD No. 2 Tariff 12LF 11
Gridforce Energy Management, LLC Tariff 12LF 12
Idaho Power Company Tariff 9IF 13
Idaho Power Company Tariff 12LF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.1
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
229,800 229,800 2,400 1
36,203 36,203 1,340 2
281,687 281,687 15,076 3
80,205 80,205 2,735 4
6 62 5
1,628,524 1,628,524 74,341 6
185,925 185,925 7
80,324 80,324 2,931 8
151,109 151,109 5,552 9
490,985 490,985 19,302 10
20 205 11
3,852 3,852 174 12
1,538 1,538 71 13
158 1586 14
FERC FORM NO. 1 (ED. 12-90)Page 311.1
0
49,664,905
49,664,905
0
2,796,393
2,796,393
0 0
30,189,876
30,189,876
82,055,793
82,055,793
0
2,201,012
2,201,012
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Idaho Power Company Balancing Tariff 9SF 1
Idaho Power Company Balancing Tariff 9IF 2
Kootenai Electric Cooperative Tariff 8LF 3
Macquarie Energy, LLC Tariff 9SF 4
Macquarie Energy, LLC Tariff 9IF 5
Mizuho Securities USA, Inc.NAOS 6
Modesto Irrigation District Tariff 9SF 7
Morgan Stanley Capital Group, Inc.Tariff 9SF 8
Morgan Stanley Capital Group, Inc.Tariff 9IF 9
Morgan Stanley Capital Group, Inc.Tariff 9IF 10
Morgan Stanley Capital Group, Inc.Tariff 9SF 11
Morgan Stanley Capital Group, Inc.Tariff 9SF 12
NaturEner Power Watch, LLC Tariff 12LF 13
Nevada Power Company Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.2
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
77,727 77,727 4,917 1
196,054 196,054 7,808 2
44,297 44,297 2,122 3
2,360,730 2,360,730 113,558 4
994 994 146 5
5,703,092 5,703,092 6
19,800 19,800 330 7
9,653,776 9,653,776 514,331 8
255,998 255,998 11,690 9
8,298,785 8,298,785 410,702 10
276,696 276,696 11
645,624 645,624 12
2,399 2,399 139 13
21,250 21,250 675 14
FERC FORM NO. 1 (ED. 12-90)Page 311.2
0
49,664,905
49,664,905
0
2,796,393
2,796,393
0 0
30,189,876
30,189,876
82,055,793
82,055,793
0
2,201,012
2,201,012
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
NextEra Energy Marketing, LLC Tariff 9SF 1
NorthWestern Energy LLC Tariff 9SF 2
Northwestern Energy LLC Tariff 9IF 3
NorthWestern Energy LLC Tariff 12LF 4
NorthWestern Energy LLC Tariff 9LF 5
Okanogan County PUD Tariff 9SF 6
PacifiCorp Tariff 9SF 7
PacifiCorp Tariff 12LF 8
PacifiCorp Tariff 9LF 9
Pend Oreille Public Utility District Tariff 9IF 10
Pend Oreille Public Utility District Tariff 9IF 11
Pend Oreille Public Utility District Tariff 9IF 12
Pend Oreille Public Utility District Tariff 9SF 13
Portland General Electric Company Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.3
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
8,694 8,694 378 1
2,702,572 2,702,572 79,538 2
7,792 7,792 363 3
1,724 1,724 55 4
133,891 133,891 6,389 5
143,180 143,180 5,720 6
3,287,363 3,287,363 98,619 7
2,114 2,114 99 8
85,203 85,203 4,067 9
434,368 434,368 10
120,713 120,713 9,322 11
584,981 584,981 26,410 12
1,068,206 1,068,206 59,354 13
1,631,934 1,631,934 76,157 14
FERC FORM NO. 1 (ED. 12-90)Page 311.3
0
49,664,905
49,664,905
0
2,796,393
2,796,393
0 0
30,189,876
30,189,876
82,055,793
82,055,793
0
2,201,012
2,201,012
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Portland General Electric Company Tariff 12LF 1
Powerex Tariff 9SF 2
Powerex Tariff 9IF 3
Puget Sound Energy Tariff 9LF 4
Puget Sound Energy Tariff 9SF 5
Puget Sound Energy Tariff 12LF 6
Rainbow Energy Marketing Tariff 9SF 7
Rainbow Energy Marketing Tariff 9IF 8
Sacramento Municipal Utility District Tariff 9SF 9
Sacramento Municipal Utility District Tariff 12LF 10
Seattle City Light Tariff 9SF 11
Seattle City Light Tariff 9LF 12
Seattle City Light Tariff 12LF 13
Shell Energy N.A.Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.4
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
902 902 26 1
575,854 575,854 37,539 2
80,103 80,103 2,224 3
389,500 389,500 18,588 4
1,576,045 1,576,045 64,797 5
124 1244 6
382,461 382,461 9,457 7
24,317 24,317 699 8
80,902 80,902 841 9
278 278 10 10
188,185 188,185 10,305 11
10,186 10,186 605 12
1,993 1,993 66 13
4,071,244 4,071,244 184,467 14
FERC FORM NO. 1 (ED. 12-90)Page 311.4
0
49,664,905
49,664,905
0
2,796,393
2,796,393
0 0
30,189,876
30,189,876
82,055,793
82,055,793
0
2,201,012
2,201,012
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Shell Energy N.A.Tariff 9SF 1
Snohomish County PUD Tariff 9SF 2
Southern California Edison Company Tariff 9SF 3
Sovereign Power Tariff 9LF 4
Sovereign Power Tariff 9LF 5
Tacoma Power Tariff 9SF 6
Tacoma Power Tariff 9LF 7
Tacoma Power Tariff 12LF 8
Talen Energy Montana, LLC Tariff 9LF 9
Tenaska Power Services Co.Tariff 9SF 10
The Energy Authority Tariff 9SF 11
The Energy Authority Tariff 9IF 12
TransAlta Energy Marketing Tariff 9SF 13
TransAlta Energy Marketing Tariff 9IF 14
FERC FORM NO. 1 (ED. 12-90)Page 310.5
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
3,810 3,810 1
273,120 273,120 11,065 2
415,950 415,950 1,191 3
132,099 132,099 4
276,595 276,595 11,241 5
53,340 53,340 4,440 6
29,608 29,608 1,559 7
38 382 8
304,297 304,297 14,521 9
74,442 74,442 3,600 10
958,915 958,915 33,542 11
244 2449 12
1,946,836 1,946,836 75,620 13
3,317 3,317 158 14
FERC FORM NO. 1 (ED. 12-90)Page 311.5
0
49,664,905
49,664,905
0
2,796,393
2,796,393
0 0
30,189,876
30,189,876
82,055,793
82,055,793
0
2,201,012
2,201,012
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)Average AverageMonthly NCP Demand Monthly CP Demand
1. Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than power
exchanges during the year. Do not report exchanges of electricity ( i.e., transactions involving a balancing of debits and credits for
energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2. Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projected load for this service in its system resource planning). In addition, the reliability of requirements service must be the
same as, or second only to, the supplier's service to its own ultimate consumers.
LF - for tong-term service. "Long-term" means five years or Longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for Long-term firm service which meets the definition
of RQ service. For all transactions identified as LF, provide in a footnote the termination date of the contract defined as the earliest date
that either buyer or setter can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service except that "intermediate-term" means longer than one year but Less
than five years.
SF - for short-term firm service. Use this category for all firm services where the duration of each period of commitment for service is one
year or less.
LU - for Long-term service from a designated generating unit. "Long-term" means five years or Longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Turlock Irrigation Dist Tariff 9SF 1
Vitol, Inc.Tariff 9SF 2
Wells Fargo securities, LLC NAOS 3
IntraCompany Wheeling LF 4
IntraCompany Generation LF 5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 310.6
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SALES FOR RESALE (Account 447) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
454,400 454,400 4,800 1
47,200 47,200 2,000 2
5,433,304 5,433,304 3
-16,461,177 16,461,177 4
2,592,303 2,592,303 5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 311.6
0
49,664,905
49,664,905
0
2,796,393
2,796,393
0 0
30,189,876
30,189,876
82,055,793
82,055,793
0
2,201,012
2,201,012
Schedule Page: 310 Line No.: 2 Column: b
Capacity
Schedule Page: 310 Line No.: 3 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310 Line No.: 6 Column: b
BPA Contract Terminates September 30, 2028.
Schedule Page: 310 Line No.: 7 Column: b
Effective October 1, 2018 - This Scheduling Agreement shall remain in effect until such
time as BPA is no longer the designated scheduling agent for any Federal Load.
Schedule Page: 310 Line No.: 9 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310 Line No.: 10 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310 Line No.: 14 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 5 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 7 Column: b
Reserves
Schedule Page: 310.1 Line No.: 11 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 12 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 13 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.1 Line No.: 14 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.2 Line No.: 2 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.2 Line No.: 3 Column: b
Kootenai Contract Terminates March 31,2024
Schedule Page: 310.2 Line No.: 5 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.2 Line No.: 6 Column: b
Financial SWAP
Schedule Page: 310.2 Line No.: 9 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.2 Line No.: 10 Column: b
Resource Contingent Bundled REC - Energy and Green Attributes 03/01/2019-12/31/2023.
Schedule Page: 310.2 Line No.: 11 Column: b
Capacity
Schedule Page: 310.2 Line No.: 12 Column: b
Capacity
Schedule Page: 310.2 Line No.: 13 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.3 Line No.: 3 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.3 Line No.: 4 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.3 Line No.: 5 Column: b
NorthWestern Energy LLC sale expires October 31, 2023.
Schedule Page: 310.3 Line No.: 8 Column: b
NWPP Reserve Sharing Sales
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 310.3 Line No.: 9 Column: b
PacifiCorp sale terminates October 31, 2023.
Schedule Page: 310.3 Line No.: 10 Column: b
Contract expires 9/30/2021.
Schedule Page: 310.3 Line No.: 11 Column: b
Contract expires 9/30/2021.
Schedule Page: 310.3 Line No.: 12 Column: b
Deviation Energy
Schedule Page: 310.4 Line No.: 1 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.4 Line No.: 3 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.4 Line No.: 4 Column: b
Puget Sound Energy sale terminates October 31, 2023.
Schedule Page: 310.4 Line No.: 6 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.4 Line No.: 8 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.4 Line No.: 10 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.4 Line No.: 12 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.4 Line No.: 13 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 1 Column: b
Reserves
Schedule Page: 310.5 Line No.: 4 Column: b
Sovereign Power contract terminates 9-30-2021
Schedule Page: 310.5 Line No.: 5 Column: b
Sovereign Power Contract terminates 9-30-2021
Schedule Page: 310.5 Line No.: 7 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.5 Line No.: 8 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 9 Column: b
Talen Energy sale terminates October 31,2023.
Schedule Page: 310.5 Line No.: 12 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.5 Line No.: 14 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.6 Line No.: 3 Column: b
Financial SWAP
Schedule Page: 310.6 Line No.: 4 Column: b
IntraCompany Wheeling terminates 09/30/2023.
Schedule Page: 310.6 Line No.: 5 Column: b
IntraCompany Generation - Sale of Ancillary Services.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
1. POWER PRODUCTION EXPENSES 1
A. Steam Power Generation 2
Operation 3
(500) Operation Supervision and Engineering 4 355,496 354,806
(501) Fuel 5 30,554,741 29,506,761
(502) Steam Expenses 6 3,760,759 3,514,368
(503) Steam from Other Sources 7
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 888,160 743,487
(506) Miscellaneous Steam Power Expenses 10 3,107,546 4,636,347
(507) Rents 11 15,079
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 38,681,781 38,755,769
Maintenance 14
(510) Maintenance Supervision and Engineering 15 506,378 660,566
(511) Maintenance of Structures 16 759,694 776,895
(512) Maintenance of Boiler Plant 17 5,794,165 7,796,381
(513) Maintenance of Electric Plant 18 638,851 2,263,602
(514) Maintenance of Miscellaneous Steam Plant 19 1,222,605 1,186,306
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 8,921,693 12,683,750
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 47,603,474 51,439,519
B. Nuclear Power Generation 22
Operation 23
(517) Operation Supervision and Engineering 24
(518) Fuel 25
(519) Coolants and Water 26
(520) Steam Expenses 27
(521) Steam from Other Sources 28
(Less) (522) Steam Transferred-Cr. 29
(523) Electric Expenses 30
(524) Miscellaneous Nuclear Power Expenses 31
(525) Rents 32
TOTAL Operation (Enter Total of lines 24 thru 32) 33
Maintenance 34
(528) Maintenance Supervision and Engineering 35
(529) Maintenance of Structures 36
(530) Maintenance of Reactor Plant Equipment 37
(531) Maintenance of Electric Plant 38
(532) Maintenance of Miscellaneous Nuclear Plant 39
TOTAL Maintenance (Enter Total of lines 35 thru 39) 40
TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40) 41
C. Hydraulic Power Generation 42
Operation 43
(535) Operation Supervision and Engineering 44 2,754,616 1,909,402
(536) Water for Power 45 930,038 1,417,118
(537) Hydraulic Expenses 46 9,607,953 9,826,421
(538) Electric Expenses 47 5,884,654 5,782,034
(539) Miscellaneous Hydraulic Power Generation Expenses 48 1,070,877 1,089,381
(540) Rents 49 6,428,232 6,590,160
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 26,676,370 26,614,516
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 792,626 577,244
(542) Maintenance of Structures 54 657,326 2,148,575
(543) Maintenance of Reservoirs, Dams, and Waterways 55 1,636,470 347,512
(544) Maintenance of Electric Plant 56 2,824,428 3,116,588
(545) Maintenance of Miscellaneous Hydraulic Plant 57 947,013 672,199
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 6,857,863 6,862,118
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 33,534,233 33,476,634
FERC FORM NO. 1 (ED. 12-93) Page 320
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
D. Other Power Generation 60
Operation 61
(546) Operation Supervision and Engineering 62 228,562 387,513
(547) Fuel 63 71,500,955 53,865,752
(548) Generation Expenses 64 2,231,850 2,362,990
(549) Miscellaneous Other Power Generation Expenses 65 1,254,645 407,606
(550) Rents 66 47,044 84,304
TOTAL Operation (Enter Total of lines 62 thru 66) 67 75,263,056 57,108,165
Maintenance 68
(551) Maintenance Supervision and Engineering 69 651,663 681,138
(552) Maintenance of Structures 70 133,426 178,602
(553) Maintenance of Generating and Electric Plant 71 7,094,951 4,117,018
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 426,816 408,807
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 8,306,856 5,385,565
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 83,569,912 62,493,730
E. Other Power Supply Expenses 75
(555) Purchased Power 76 144,313,775 136,251,226
(556) System Control and Load Dispatching 77 660,144 708,451
(557) Other Expenses 78 48,105,794 33,286,543
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 193,079,713 170,246,220
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 357,787,332 317,656,103
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 1,931,225 2,195,597
84
(561.1) Load Dispatch-Reliability 85 60,658 25,215
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 1,227,913 1,203,318
(561.3) Load Dispatch-Transmission Service and Scheduling 87 1,002,020 1,008,482
(561.4) Scheduling, System Control and Dispatch Services 88
(561.5) Reliability, Planning and Standards Development 89 663,145 483,110
(561.6) Transmission Service Studies 90 655
(561.7) Generation Interconnection Studies 91 4,366
(561.8) Reliability, Planning and Standards Development Services 92
(562) Station Expenses 93 499,947 477,902
(563) Overhead Lines Expenses 94 370,882 423,608
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 17,252,820 16,539,039
(566) Miscellaneous Transmission Expenses 97 2,805,371 2,365,717
(567) Rents 98 170,983 185,537
TOTAL Operation (Enter Total of lines 83 thru 98) 99 25,984,964 24,912,546
Maintenance 100
(568) Maintenance Supervision and Engineering 101 499,807 426,853
(569) Maintenance of Structures 102 570,168 429,943
(569.1) Maintenance of Computer Hardware 103
(569.2) Maintenance of Computer Software 104
(569.3) Maintenance of Communication Equipment 105
(569.4) Maintenance of Miscellaneous Regional Transmission Plant 106
(570) Maintenance of Station Equipment 107 823,646 761,185
(571) Maintenance of Overhead Lines 108 1,002,431 1,346,772
(572) Maintenance of Underground Lines 109 47 3,651
(573) Maintenance of Miscellaneous Transmission Plant 110 73,382 35,220
TOTAL Maintenance (Total of lines 101 thru 110) 111 2,969,481 3,003,624
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 28,954,445 27,916,170
FERC FORM NO. 1 (ED. 12-93) Page 321
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
3. REGIONAL MARKET EXPENSES 113
Operation 114
(575.1) Operation Supervision 115
(575.2) Day-Ahead and Real-Time Market Facilitation 116
(575.3) Transmission Rights Market Facilitation 117
(575.4) Capacity Market Facilitation 118
(575.5) Ancillary Services Market Facilitation 119
(575.6) Market Monitoring and Compliance 120
(575.7) Market Facilitation, Monitoring and Compliance Services 121
(575.8) Rents 122
Total Operation (Lines 115 thru 122) 123
Maintenance 124
(576.1) Maintenance of Structures and Improvements 125
(576.2) Maintenance of Computer Hardware 126
(576.3) Maintenance of Computer Software 127
(576.4) Maintenance of Communication Equipment 128
(576.5) Maintenance of Miscellaneous Market Operation Plant 129
Total Maintenance (Lines 125 thru 129) 130
TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) 131
4. DISTRIBUTION EXPENSES 132
Operation 133
(580) Operation Supervision and Engineering 134 3,341,232 3,716,544
(581) Load Dispatching 135
(582) Station Expenses 136 768,839 641,798
(583) Overhead Line Expenses 137 2,206,002 2,561,515
(584) Underground Line Expenses 138 1,618,684 1,747,358
(585) Street Lighting and Signal System Expenses 139 5,265 38,628
(586) Meter Expenses 140 1,744,750 1,634,878
(587) Customer Installations Expenses 141 829,754 689,416
(588) Miscellaneous Expenses 142 7,149,060 4,826,245
(589) Rents 143 353,727 275,841
TOTAL Operation (Enter Total of lines 134 thru 143) 144 18,017,313 16,132,223
Maintenance 145
(590) Maintenance Supervision and Engineering 146 1,230,289 1,374,983
(591) Maintenance of Structures 147 532,672 566,579
(592) Maintenance of Station Equipment 148 769,884 494,075
(593) Maintenance of Overhead Lines 149 10,873,805 13,734,825
(594) Maintenance of Underground Lines 150 804,137 676,586
(595) Maintenance of Line Transformers 151 359,548 430,900
(596) Maintenance of Street Lighting and Signal Systems 152 158,130 141,014
(597) Maintenance of Meters 153 39,048 50,253
(598) Maintenance of Miscellaneous Distribution Plant 154 536,940 553,027
TOTAL Maintenance (Total of lines 146 thru 154) 155 15,304,453 18,022,242
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 33,321,766 34,154,465
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 114,406 149,519
(902) Meter Reading Expenses 160 2,042,787 1,204,370
(903) Customer Records and Collection Expenses 161 7,885,571 7,480,445
(904) Uncollectible Accounts 162 208,808 7,961,674
(905) Miscellaneous Customer Accounts Expenses 163 159,633 145,713
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 10,411,205 16,941,721
FERC FORM NO. 1 (ED. 12-93) Page 322
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Account Amount for
(c)(b)(a)Current Year Previous YearAmount for
If the amount for previous year is not derived from previously reported figures, explain in footnote.
6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES 165
Operation 166
(907) Supervision 167
(908) Customer Assistance Expenses 168 37,686,359 33,716,712
(909) Informational and Instructional Expenses 169 1,153,181 1,029,735
(910) Miscellaneous Customer Service and Informational Expenses 170 250,163 320,788
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 39,089,703 35,067,235
7. SALES EXPENSES 172
Operation 173
(911) Supervision 174
(912) Demonstrating and Selling Expenses 175
(913) Advertising Expenses 176
(916) Miscellaneous Sales Expenses 177
TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178
8. ADMINISTRATIVE AND GENERAL EXPENSES 179
Operation 180
(920) Administrative and General Salaries 181 25,372,504 27,858,120
(921) Office Supplies and Expenses 182 4,732,387 4,275,810
(Less) (922) Administrative Expenses Transferred-Credit 183 102,345 103,030
(923) Outside Services Employed 184 10,107,690 10,580,489
(924) Property Insurance 185 1,451,884 1,673,027
(925) Injuries and Damages 186 4,177,429 4,251,143
(926) Employee Pensions and Benefits 187 30,761,884 31,925,253
(927) Franchise Requirements 188 1,200 1,200
(928) Regulatory Commission Expenses 189 6,380,843 6,021,061
(929) (Less) Duplicate Charges-Cr. 190
(930.1) General Advertising Expenses 191
(930.2) Miscellaneous General Expenses 192 4,995,151 6,469,003
(931) Rents 193 312,788 566,423
TOTAL Operation (Enter Total of lines 181 thru 193) 194 88,191,415 93,518,499
Maintenance 195
(935) Maintenance of General Plant 196 12,182,064 12,476,593
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 100,373,479 105,995,092
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 569,937,930 537,730,786
FERC FORM NO. 1 (ED. 12-93) Page 323
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Adams Nielson Solar, LLC PURPALU 1
Avangrid Renewables, LLC Tariff 9SF 2
Avangrid Renewables, LLC NWPPLF 3
Avangrid Renewables, LLC Tariff 9OS 4
BP Energy Tariff 9SF 5
Black Hills Power, Inc.Tariff 9SF 6
Bonneville Power Administration Tariff 9SF 7
Bonneville Power Administration NWPPLF 8
Bonneville Power Administration Tariff 8LF 9
Bonneville Power Administration Tariff 8LF 10
Bonneville Power Administration BPA OATTOS 11
Brookfield Energy Marketing LP Tariff 9SF 12
California Independent System Operator Tariff 9SF 13
Calpine Energy Services LP Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90)Page 326
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1,796,750 1,796,750 1 45,281
1,852,515 1,852,515 2 156,203
193 193 38
3,500 3,500 4
17,950 17,950 5 5,800
12,650 12,650 6 425
2,084,017 2,084,017 7 143,686
5,494 5,494 8 227
394,640 394,640 9 17,908
30,531 30,531 10 1,783
29,843 29,843 11
228,662 228,662 12 7,444
108,747 108,747 13 5,391
174,000 174,000 14 7,828
FERC FORM NO. 1 (ED. 12-90) Page 327
5,465,161 9,313 429,763 30,688,728 99,167,441 6,395,057 136,251,226
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
City of Spokane PURPALU 1
City of Spokane PURPAIU 2
Chelan County PUD Rocky ReachIU 3
Chelan County PUD Rocky ReachIU 4
Chelan County PUD Tariff 9SF 5
Chelan County PUD NWPPLF 6
Chelan County PUD Chelan SysIU 7
Clark Fork Hydro PURPALU 8
Clatskanie PUD Tariff 9SF 9
Clearwater Paper Company PURPAIU 10
Clearwater Power Company NARQ 11
Community Solar PURPALU 12
ConocoPhillips Company Tariff 9SF 13
Deep Creek Energy, LLC PURPAIU 14
FERC FORM NO. 1 (ED. 12-90)Page 326.1
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1,896,628 1,896,628 1 51,202
5,841,923 5,841,923 2 125,281
3 21,097
4-23,893
273,450 273,450 5 18,600
268 268 6 11
16,793,744 16,793,744 7 422,794
64,064 64,064 8 1,034
8,090 8,090 9 732
10,460,373 10,460,373 10 426,954
14,451 14,451 11 180
13,252 13,252 12 534
841,235 841,235 13 28,095
14,125 14,125 14 331
FERC FORM NO. 1 (ED. 12-90)Page 327.1
5,465,161 9,313 429,763 30,688,728 99,167,441 6,395,057 136,251,226
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Douglas County PUD No. 1 WellsLU 1
Douglas County PUD No. 1 Tariff 9SF 2
Douglas County PUD No. 1 NWPPLF 3
Douglas County PUD No. 1 WellsOS 4
Douglas County PUD No. 1 Tariff 9EX 5
EDF Trading No America Tariff 9SF 6
Enel X North America, Inc.PURPALU 7
Energy Keepers, Inc.Tariff 9SF 8
Eugene Water & Electric Board Tariff 9SF 9
Exelon Generation Company, LLC Tariff 9SF 10
Ford Hydro Limited Partnership PURPALU 11
Grant County PUD No. 2 Priest RapidsLU 12
Grant County PUD No. 2 NWPPLF 13
Grant County PUD No. 2 FERC #104EX 14
FERC FORM NO. 1 (ED. 12-90)Page 326.2
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
3,915,081 3,915,081 1 500,828
123,487 123,487 2 9,650
103 103 34
493,806 493,806 4
421,632 5
11,530 11,530 6 857
7 44
5,189 5,189 8 584
46,139 46,139 9 2,934
276,876 276,876 10 19,721
258,149 258,149 11 3,990
9,979,903 9,979,903 12 351,771
451 451 13 18
29,508 29,508 14
FERC FORM NO. 1 (ED. 12-90)Page 327.2
5,465,161 9,313 429,763 30,688,728 99,167,441 6,395,057 136,251,226
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Gridforce Energy Management, LLC NWPPLF 1
Hydro Technology Systems PURPAIU 2
Idaho County Power & Light PURPALU 3
Idaho Power Company Tariff 9SF 4
Idaho Power Company Tariff 9IF 5
Inland Power & Light Company 208RQ 6
Kootenai Electric Cooperative Tariff 8LF 7
Macquarie Energy LLC Tariff 9SF 8
Mizuho Securities USA, Inc.NAOS 9
Morgan Stanley Capital Group Tariff 9SF 10
Nevada Power Company Tariff 9SF 11
NextEra Energy Power Marketing LLC Tariff 9SF 12
NorthWestern Energy LLC Tariff 9SF 13
NorthWestern Energy LLC NWPPLF 14
FERC FORM NO. 1 (ED. 12-90)Page 326.3
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
445 445 1 17
602,547 602,547 2 11,549
114,447 114,447 3 2,161
353,902 353,902 4 25,779
349 349 5 29
12,077 12,077 6 165
41,159 41,159 7 2,063
616,450 616,450 8 30,787
1,137,096 1,137,096 9
719,098 719,098 10 49,499
-10 -10 11
116,110 116,110 12 7,850
419,565 419,565 13 26,760
730 730 14 30
FERC FORM NO. 1 (ED. 12-90)Page 327.3
5,465,161 9,313 429,763 30,688,728 99,167,441 6,395,057 136,251,226
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
NorthWestern Energy LLC Tariff 9IF 1
Okanogan County PUD No. 1 Tariff 9SF 2
PacifiCorp Tariff 9SF 3
PacifiCorp NWPPLF 4
Palouse Wind LLC PPALU 5
Pend Oreille County PUD No. 1 Pend O'SF 6
Pend Oreille County PUD No. 1 Pend O'IF 7
Pend Oreille County PUD No. 1 Pend O'IF 8
Phillips Ranch PURPALU 9
Portland General Electric Company Tariff 9EX 10
Portland General Electric Company Tariff 9SF 11
Portland General Electric Company NWPPLF 12
Portland General Electric Company Tariff 9IF 13
Powerex Corp Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90)Page 326.4
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
26,966 26,966 1 848
75,980 75,980 2 7,050
624,493 624,493 3 31,552
1,559 1,559 4 63
23,352,036 23,352,036 5 370,142
3,662,630 3,662,630 6 200,192
164,063 164,063 7 11,086
451,205 451,205 8 39,005
797 797 9 26
8,131 8,130 10
870,175 870,175 11 30,615
1,235 1,235 12 50
161,657 161,657 13 7,783
1,746,688 1,746,688 14 59,572
FERC FORM NO. 1 (ED. 12-90) Page 327.4
5,465,161 9,313 429,763 30,688,728 99,167,441 6,395,057 136,251,226
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Puget Sound Energy Tariff 9SF 1
Puget Sound Energy NWPPLF 2
Puget Sound Energy Tariff 9IF 3
Rathdrum Power LLC LancasterLU 4
Rattlesnake Flat, LLC PPALU 5
Seattle City Light Tariff 9SF 6
Seattle City Light NWPPLF 7
Sheep Creek Hydro PURPALU 8
Shell Energy Tariff 9SF 9
Snohomish County PUD No. 1 Tariff 9SF 10
Sovereign Power SovereignLF 11
Spokane County PURPALU 12
Stimson Lumber PURPAIU 13
Tacoma Power Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90)Page 326.5
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
1,637,168 1,637,168 1 76,800
1,414 1,414 2 56
55 55 33
28,069,627 28,069,627 4 1,685,079
807,070 807,070 5 37,157
236,225 236,225 6 14,375
617 617 7 25
277,164 277,164 8 8,697
1,391,825 1,391,825 9 110,522
222,490 222,490 10 15,310
192,255 192,255 11 13,777
52,908 52,908 12 1,055
1,694,707 1,694,707 13 36,523
382,474 382,474 14 16,357
FERC FORM NO. 1 (ED. 12-90) Page 327.5
5,465,161 9,313 429,763 30,688,728 99,167,441 6,395,057 136,251,226
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER (Account 555)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Name of Company or Public Authority
(c)(b)(a)
FERC Rate Monthly BillingAverage
(d)
Statistical
cationClassifi- Schedule orTariff Number Demand (MW)
(e) (f)
(Footnote Affiliations)
Actual Demand (MW)
Average AverageMonthly NCP Demand Monthly CP Demand
(Including power exchanges)
1. Report all power purchases made during the year. Also report exchanges of electricity (i.e., transactions involving a balancing of
debits and credits for energy, capacity, etc.) and any settlements for imbalanced exchanges.
2. Enter the name of the seller or other party in an exchange transaction in column (a). Do not abbreviate or truncate the name or use
acronyms. Explain in a footnote any ownership interest or affiliation the respondent has with the seller.
3. In column (b), enter a Statistical Classification Code based on the original contractual terms and conditions of the service as follows:
RQ - for requirements service. Requirements service is service which the supplier plans to provide on an ongoing basis (i.e., the supplier
includes projects load for this service in its system resource planning). In addition, the reliability of requirement service must be the
same as, or second only to, the supplier’s service to its own ultimate consumers.
LF - for long-term firm service. "Long-term" means five years or longer and "firm" means that service cannot be interrupted for economic
reasons and is intended to remain reliable even under adverse conditions (e.g., the supplier must attempt to buy emergency energy from
third parties to maintain deliveries of LF service). This category should not be used for long-term firm service firm service which meets
the definition of RQ service. For all transaction identified as LF, provide in a footnote the termination date of the contract defined as the
earliest date that either buyer or seller can unilaterally get out of the contract.
IF - for intermediate-term firm service. The same as LF service expect that "intermediate-term" means longer than one year but less
than five years.
SF - for short-term service. Use this category for all firm services, where the duration of each period of commitment for service is one
year or less.
LU - for long-term service from a designated generating unit. "Long-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
IU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote for each adjustment.
Tacoma Power NWPPLF 1
Tenaska Power Services Co Tariff 9SF 2
The City of Cove PURPALU 3
The Energy Authority Tariff 9SF 4
TransAlta Energy Marketing Tariff 9SF 5
Turlock Irrigation District Tariff 9SF 6
Vitol Inc.Tariff 9SF 7
Wells Fargo Securities, LLC NAOS 8
IntraCompany Generation Services OATTOS 9
Other - Inadvertent Interchange EX 10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 326.6
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASED POWER(Account 555) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
348 348 1 14
13,385 13,385 2 1,763
109,479 109,479 3 2,895
391,058 391,058 4 28,351
2,614,207 2,614,207 5 135,547
33,280 33,280 6 8,045
47,400 47,400 7 2,800
2,109,002 2,109,002 8
2,592,302 2,592,302 9
1,183 10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90)Page 327.6
5,465,161 9,313 429,763 30,688,728 99,167,441 6,395,057 136,251,226
Schedule Page: 326 Line No.: 3 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326 Line No.: 4 Column: a
Pondage
Schedule Page: 326 Line No.: 8 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326 Line No.: 9 Column: a
BPA Contract Terminates September 30, 2028
Schedule Page: 326 Line No.: 10 Column: a
Effective October 1, 2018 - This Scheduling Agreement shall remain in effect until such
time as BPA is no longer the designated scheduling agent for any Federal Load.
Schedule Page: 326 Line No.: 11 Column: a
Ancillary Services - Spinning & Supplemental
Schedule Page: 326.1 Line No.: 6 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.1 Line No.: 11 Column: a
Service to Ahsahka, Idaho from Clearwater Power Company. No demand charges associated
with the agreement.
Schedule Page: 326.2 Line No.: 3 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.2 Line No.: 4 Column: a
Canadian Entitlement associated with Wells contract.
Schedule Page: 326.2 Line No.: 5 Column: a
Exchange
Schedule Page: 326.2 Line No.: 13 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.3 Line No.: 1 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.3 Line No.: 5 Column: a
Financially Settled Transmission Losses
Schedule Page: 326.3 Line No.: 6 Column: a
Service to Deer Lake from Inland Power and Light. No demand charges associated with the
agreement.
Schedule Page: 326.3 Line No.: 7 Column: a
Kootenai Contract Terminates March 31, 2024
Schedule Page: 326.3 Line No.: 9 Column: a
Financial SWAP
Schedule Page: 326.3 Line No.: 11 Column: a
Energy Imbalance Charges
Schedule Page: 326.3 Line No.: 14 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.4 Line No.: 1 Column: a
Financially Settled Transmission Losses
Schedule Page: 326.4 Line No.: 4 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.4 Line No.: 7 Column: a
Pend Oreille County PUD contract expires 09/30/2021. Deviation Energy.
Schedule Page: 326.4 Line No.: 12 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.4 Line No.: 13 Column: a
Financially Settled Transmission Losses
Schedule Page: 326.5 Line No.: 2 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 326.5 Line No.: 3 Column: a
Financially Settled Transmission Losses
Schedule Page: 326.5 Line No.: 7 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.5 Line No.: 11 Column: a
Sovereign Contract Terminates September 30, 2021. Deviation Energy.
Schedule Page: 326.6 Line No.: 1 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.6 Line No.: 8 Column: a
Financial SWAP
Schedule Page: 326.6 Line No.: 9 Column: a
Ancillary Services
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying
facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
PacifiCorp PacifiCorp PacifiCorp OLF 1
Seattle City Light Seattle City Light Grant County PUD OLF 2
Tacoma Power Tacoma Power Grant County PUD OLF 3
Grant County Public Utility District Grant County PUD Grant County PUD OLF 4
Spokane Tribe Bonneville Power Administration Spokane Tribe of Indians LFP 5
East Greenacres Bonneville Power Administration East Greenacres LFP 6
Consolidated Irrigation District Bonneville Power Administration Consolidated Irrigation District LFP 7
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO 8
City of Spokane City of Spokane Avista Corporation OLF 9
Stimson Plummer Avista Corporation OLF 10
Hydro Tech Industries Meyers Falls Avista Corporation OLF 11
Shell Energy North America (US) LP Bonneville Power Administration NorthWestern Energy SFP 12
Deep Creek Hydro Deep Creek Avista Corporation OLF 13
Shell Energy North America (US) LP Bonneville Power Administration Idaho Power Company SFP 14
Shell Energy North America (US) LP Grant County PUD Idaho Power Company SFP 15
Morgan Stanley Capital Group Avista Corporation Idaho Power Company SFP 16
Douglas County PUD Chelan County PUD Avista Corporation NF 17
Morgan Stanley Capital Group Avista Corporation NorthWestern Energy SFP 18
Shell Energy North America (US) LP PacifiCorp Bonneville Power Administration SFP 19
Morgan Stanley Capital Group Bonneville Power Administration NorthWestern Energy SFP 20
Morgan Stanley Capital Group NorthWestern Energy Idaho Power Company SFP 21
Morgan Stanley Capital Group NorthWestern Energy Bonneville Power Administration SFP 22
Idaho Power Company Grant County PUD Idaho Power Company NF 23
Morgan Stanley Capital Group Grant County PUD Idaho Power Company SFP 24
Morgan Stanley Capital Group Grant County PUD NorthWestern Energy SFP 25
Morgan Stanley Capital Group PacifiCorp Idaho Power Company SFP 26
Shell Energy North America (US) LP Chelan County PUD NorthWestern Energy SFP 27
EDR Trading North America LLC Bonneville Power Administration NorthWestern Energy NF 28
PacifiCorp PacifiCorp PacifiCorp SFP 29
Idaho Power Company Avista Corporation Idaho Power Company SFP 30
EDR Trading North America LLC NorthWestern Energy Avista Corporation NF 31
Idaho Power Company Bonneville Power Administration Idaho Power Company SFP 32
EDR Trading North America LLC Avista Corporation NorthWestern Energy NF 33
Idaho Power Company PacifiCorp Idaho Power Company SFP 34
FERC FORM NO. 1 (ED. 12-90)Page 328
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
Dry GulchRS No. 182 Dry Gulch 22,384 22,384 1
Chelan-StratfordFERC Trf No. 8 Stratford 126,003 126,003 2
Chelan-StratfordFERC Trf No. 8 Stratford 125,983 125,983 3
StratfordRS No. 104 Coulee City/Wilson 86,685 86,685 4
AVA.BPATFERC Trf No. 8 AVA.SYS 3 3,202 3,202 5
AVA.BPATFERC Trf No. 8 AVA.SYS 3 2,726 2,726 6
AVA.BPATFERC Trf No. 8 AVA.SYS 4 6,270 6,270 7
AVA.BPATFERC Trf No. 8 AVA.SYS 2,019,544 2,019,544 8
PURPA 9
PURPA 10
PURPA 11
FERC Trf No. 8 1,810 1,810 12
PURPA 13
FERC Trf No. 8 34,757 34,757 14
FERC Trf No. 8 84,841 84,841 15
FERC Trf No. 8 1,200 1,200 16
FERC Trf No. 8 48 48 17
FERC Trf No. 8 964 964 18
FERC Trf No. 8 188 188 19
FERC Trf No. 8 7,994 7,994 20
FERC Trf No. 8 23,723 23,723 21
FERC Trf No. 8 19,784 19,784 22
FERC Trf No. 8 75 75 23
FERC Trf No. 8 21,809 21,809 24
FERC Trf No. 8 419 419 25
FERC Trf No. 8 34,979 34,979 26
FERC Trf No. 8 37 37 27
FERC Trf No. 8 2,553 2,553 28
FERC Trf No. 8 216 216 29
FERC Trf No. 8 1,624 1,624 30
FERC Trf No. 8 36 36 31
FERC Trf No. 8 184,050 184,050 32
FERC Trf No. 8 50 50 33
FERC Trf No. 8 3,336 3,336 34
FERC FORM NO. 1 (ED. 12-90)Page 329
13 3,510,201 3,510,201
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
301,661 301,661 1
154,228 244,456 90,228 2
208,000 298,228 90,228 3
28,479 28,479 4
18,000 25,113 7,113 5
10,800 16,344 5,544 6
32,160 41,492 9,332 7
6,612,430 9,162,592 2,550,162 8
27,973 27,973 9
8,448 8,448 10
6,120 6,120 11
5,329 5,329 12
603 603 13
209,586 209,586 14
291,128 291,128 15
4,333 4,333 16
2,354 2,354 17
3,350 3,350 18
1,186 1,186 19
25,472 25,472 20
92,324 92,324 21
102,389 102,389 22
433 433 23
85,929 85,929 24
2,108 2,108 25
126,094 126,094 26
233 233 27
15,893 15,893 28
1,355 1,355 29
7,072 7,072 30
209 209 31
876,203 876,203 32
319 319 33
17,282 17,282 34
FERC FORM NO. 1 (ED. 12-90)Page 330
12,628,226 16,370,526 3,742,300 0
This Page Intentionally Left Blank
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying
facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Idaho Power Company Chelan County PUD Idaho Power Company SFP 1
Idaho Power Company PacifiCorp NorthWestern Energy NF 2
Macquarie Energy LLC Avista Corporation NorthWestern Energy NF 3
Avangrid Renewables Bonneville Power Administration NorthWestern Energy NF 4
Powerex Chelan County PUD NorthWestern Energy NF 5
Bonneville Power Administration Bonneville Power Administration Idaho Power Company NF 6
Shell Energy North America (US) LP Bonneville Power Administration Idaho Power Company NF 7
Shell Energy North America (US) LP Bonneville Power Administration NorthWestern Energy NF 8
Shell Energy North America (US) LP NorthWestern Energy Bonneville Power Administration NF 9
Shell Energy North America (US) LP NorthWestern Energy Grant County Public Utility NF 10
Kootenai Electric Avista Corporation Idaho Power Company LFP 11
Morgan Stanley Capital Group Avista Corporation Idaho Power Company NF 12
Shell Energy North America (US) LP Grant County PUD NorthWestern Energy SFP 13
Energy Keepers Inc Bonneville Power Administration NorthWestern Energy SFP 14
Morgan Stanley Capital Group Bonneville Power Administration Idaho Power Company NF 15
Morgan Stanley Capital Group Bonneville Power Administration NorthWestern Energy NF 16
Morgan Stanley Capital Group NorthWestern Energy Bonneville Power Administration NF 17
Rainbow Energy Marketing Corp Bonneville Power Administration Idaho Power Company NF 18
Morgan Stanley Capital Group NorthWestern Energy Idaho Power Company NF 19
Morgan Stanley Capital Group NorthWestern Energy Grant County PUD NF 20
Rainbow Energy Marketing Corp Bonneville Power Administration NorthWestern Energy NF 21
Rainbow Energy Marketing Corp NorthWestern Energy PacifiCorp NF 22
Morgan Stanley Capital Group Avista Corporation Bonneville Power Administration NF 23
Morgan Stanley Capital Group Grant County PUD Idaho Power Company NF 24
Morgan Stanley Capital Group Grant County PUD NorthWestern Energy NF 25
Morgan Stanley Capital Group Chelan County PUD Idaho Power Company NF 26
Morgan Stanley Capital Group Chelan County PUD NorthWestern Energy NF 27
Morgan Stanley Capital Group Avista Corporation NorthWestern Energy NF 28
Bonneville Power Administration Bonneville Power Administration Avista Corporation SFP 29
Powerex Bonneville Power Administration Idaho Power Company NF 30
Idaho Power Company Bonneville Power Administration NorthWestern Energy SFP 31
PacifiCorp PacifiCorp Bonneville Power Administration NF 32
PacifiCorp PacifiCorp Idaho Power Company NF 33
PacifiCorp Idaho Power Company PacifiCorp NF 34
FERC FORM NO. 1 (ED. 12-90)Page 328.1
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Trf No. 8 13,168 13,168 1
FERC Trf No. 8 2,176 2,176 2
FERC Trf No. 8 11 11 3
FERC Trf No. 8 75 75 4
FERC Trf No. 8 430 430 5
FERC Trf No. 8 23,523 23,523 6
FERC Trf No. 8 8,890 8,890 7
FERC Trf No. 8 234 234 8
FERC Trf No. 8 78 78 9
FERC Trf No. 8 67 67 10
AVA.SYSFERC Trf No. 8 LOLO 3 15,278 15,278 11
FERC Trf No. 8 145 145 12
FERC Trf No. 8 3,174 3,174 13
FERC Trf No. 8 1,470 1,470 14
FERC Trf No. 8 13,802 13,802 15
FERC Trf No. 8 18,117 18,117 16
FERC Trf No. 8 2,484 2,484 17
FERC Trf No. 8 1,414 1,414 18
FERC Trf No. 8 12,116 12,116 19
FERC Trf No. 8 651 651 20
FERC Trf No. 8 274 274 21
FERC Trf No. 8 100 100 22
FERC Trf No. 8 10 10 23
FERC Trf No. 8 7,243 7,243 24
FERC Trf No. 8 1,330 1,330 25
FERC Trf No. 8 6,946 6,946 26
FERC Trf No. 8 702 702 27
FERC Trf No. 8 78 78 28
FERC Trf No. 8 11,969 11,969 29
FERC Trf No. 8 1,166 1,166 30
FERC Trf No. 8 34,679 34,679 31
FERC Trf No. 8 25,252 25,252 32
FERC Trf No. 8 5,573 5,573 33
FERC Trf No. 8 5,775 5,775 34
FERC FORM NO. 1 (ED. 12-90)Page 329.1
13 3,510,201 3,510,201
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
57,446 57,446 1
16,629 16,629 2
63 63 3
433 433 4
2,513 2,513 5
138,625 138,625 6
40,279 40,279 7
1,344 1,344 8
935 935 9
803 803 10
72,000 94,549 22,549 11
948 948 12
13,128 13,128 13
7,384 7,384 14
91,751 91,751 15
120,617 120,617 16
15,802 15,802 17
11,311 11,311 18
79,719 79,719 19
4,111 4,111 20
2,176 2,176 21
606 606 22
59 59 23
45,996 45,996 24
8,432 8,432 25
45,195 45,195 26
4,637 4,637 27
535 535 28
29
7,303 7,303 30
271,816 271,816 31
182,050 182,050 32
40,104 40,104 33
39,180 39,180 34
FERC FORM NO. 1 (ED. 12-90)Page 330.1
12,628,226 16,370,526 3,742,300 0
This Page Intentionally Left Blank
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying
facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Idaho Power Company Bonneville Power Administration Idaho Power Company NF 1
Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration OS 2
Rainbow Energy Marketing Corp PacifiCorp Idaho Power Company NF 3
Rainbow Energy Marketing Corp Avista Corporation Idaho Power Company NF 4
Shell Energy North America (US) LP Grant County Public Utility Idaho Power Company NF 5
Transalta Energy Marketing PacifiCorp Idaho Power Company NF 6
NorthWestern Energy Bonneville Power Administration NorthWestern Energy NF 7
Portland General Electric NorthWestern Energy Bonneville Power Administration NF 8
Avangrid Renewables Bonneville Power Administration Idaho Power Company NF 9
The Energy Authority Bonneville Power Administration Avista Corporation NF 10
Shell Energy North America (US) LP Grant County PUD NorthWestern Energy NF 11
Energy Keepers, Inc.Bonneville Power Administration NorthWestern Energy NF 12
Transalta Energy Marketing Puget Sound Energy Idaho Power Company NF 13
Macquarie Energy LLC Bonneville Power Administration NorthWestern Energy NF 14
Idaho Power Company PacifiCorp Idaho Power Company NF 15
Transalta Energy Marketing Bonneville Power Administration NorthWestern Energy NF 16
Transalta Energy Marketing Grant County PUD Idaho Power Company NF 17
NorthWestern Energy NorthWestern Energy Bonneville Power Administration NF 18
Transalta Energy Marketing Chelan County PUD Idaho Power Company NF 19
PacifiCorp PacifiCorp Bonneville Power Company SFP 20
Transalta Energy Marketing Avista Corporation Bonneville Power Administration NF 21
PacifiCorp PacifiCorp PacifiCorp NF 22
Transalta Energy Marketing Avista Corporation Idaho Power Company NF 23
Idaho Power Company Bonneville Power Administration PacifiCorp SFP 24
Idaho Power Company PacifiCorp NorthWestern Energy SFP 25
Powerex Bonneville Power Administration NorthWestern Energy NF 26
Powerex NorthWestern Energy Bonneville Power Administration NF 27
Idaho Power Company Puget Sound Energy NorthWestern Energy SFP 28
Idaho Power Company Grant County PUD NorthWestern Energy SFP 29
Idaho Power Company Chelan County PUD NorthWestern Energy SFP 30
Idaho Power Company Avista Corporation NorthWestern Energy SFP 31
The Energy Authority Bonneville Power Administration NorthWestern Energy NF 32
Idaho Power Company Idaho Power Company Grant County PUD SFP 33
Macquarie Energy LLC Bonneville Power Administration NorthWestern Energy SFP 34
FERC FORM NO. 1 (ED. 12-90)Page 328.2
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Trf No. 8 6,271 6,271 1
RS No. T1110 2
FERC Trf No. 8 550 550 3
FERC Trf No. 8 931 931 4
FERC Trf No. 8 22,169 22,169 5
FERC Trf No. 8 1,547 1,547 6
FERC Trf No. 8 8,928 8,928 7
FERC Trf No. 8 7,528 7,528 8
FERC Trf No. 8 348 348 9
FERC Trf No. 8 62 62 10
FERC Trf No. 8 1,068 1,068 11
FERC Trf No, 8 1,662 1,662 12
FERC Trf No. 8 60 60 13
FERC Trf No. 8 2,902 2,902 14
FERC Trf No. 8 125 125 15
FERC Trf No. 8 1,575 1,575 16
FERC Trf No. 8 20 20 17
FERC Trf No. 8 3,148 3,148 18
FERC Trf No. 8 42 42 19
FERC Trf No. 8 28,805 28,805 20
FERC Trf No. 8 70 70 21
FERC Trf No. 8 668 668 22
FERC Trf No. 8 15 15 23
FERC Trf No. 8 2,000 2,000 24
FERC Trf No. 8 400 400 25
FERC Trf No. 8 3,627 3,627 26
FERC Trf No. 8 75 75 27
FERC Trf No. 8 2,000 2,000 28
FERC Trf No. 8 800 800 29
FERC Trf No. 8 1,800 1,800 30
FERC Trf No. 8 176 176 31
FERC Trf No. 8 110 110 32
FERC Trf No. 8 2,382 2,382 33
FERC Trf No. 8 1,971 1,971 34
FERC FORM NO. 1 (ED. 12-90)Page 329.2
13 3,510,201 3,510,201
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
39,686 39,686 1
924,000 924,000 2
3,331 3,331 3
9,574 9,574 4
130,864 130,864 5
9,602 9,602 6
53,618 53,618 7
44,873 44,873 8
3,727 3,727 9
653 653 10
5,511 5,511 11
10,259 10,259 12
400 400 13
16,889 16,889 14
721 721 15
20,309 20,309 16
115 115 17
19,845 19,845 18
280 280 19
180,666 180,666 20
466 466 21
6,249 6,249 22
87 87 23
8,707 8,707 24
9,277 9,277 25
21,740 21,740 26
490 490 27
16,243 16,243 28
3,483 3,483 29
7,598 7,598 30
766 766 31
866 866 32
9,230 9,230 33
11,722 11,722 34
FERC FORM NO. 1 (ED. 12-90)Page 330.2
12,628,226 16,370,526 3,742,300 0
This Page Intentionally Left Blank
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456.1)
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Payment By
(c)(b)(a)(d)
Statistical
cation
Classifi-
(Footnote Affiliation)
(Including transactions referred to as 'wheeling')
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)
(Footnote Affiliation)
(Company of Public Authority)Energy Received From Energy Delivered To
1. Report all transmission of electricity, i.e., wheeling, provided for other electric utilities, cooperatives, other public authorities, qualifying
facilities, non-traditional utility suppliers and ultimate customers for the quarter.
2. Use a separate line of data for each distinct type of transmission service involving the entities listed in column (a), (b) and (c).
3. Report in column (a) the company or public authority that paid for the transmission service. Report in column (b) the company or
public authority that the energy was received from and in column (c) the company or public authority that the energy was delivered to.
Provide the full name of each company or public authority. Do not abbreviate or truncate name or use acronyms. Explain in a footnote
any ownership interest in or affiliation the respondent has with the entities listed in columns (a), (b) or (c)
4. In column (d) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNO - Firm Network Service for Others, FNS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLF - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NF - non-firm transmission service, OS - Other Transmission Service and AD - Out-of-Period Adjustments. Use this code
for any accounting adjustments or "true-ups" for service provided in prior reporting periods. Provide an explanation in a footnote for each
adjustment. See General Instruction for definitions of codes.
Transalta Energy Marketing NorthWestern Energy Bonneville Power Administration NF 1
Transalta Energy Marketing Bonneville Power Administration Idaho Power Company NF 2
Morgan Stanley Capital Group Idaho Power Company Bonneville Power Administration SFP 3
Morgan Stanley Capital Group NorthWestern Energy Grant County Public Utility SFP 4
Idaho Power Company Puget Sound Energy Idaho Power Company SFP 5
Idaho Power Company Grant County Public Utility Idaho Power Company SFP 6
Morgan Stanley Capital Group Idaho Power Company Chelan County PUD SFP 7
Morgan Stanley Capital Group Avista Corporation Bonneville Power Administration SFP 8
PacifiCorp PacifiCorp Idaho Power Company SFP 9
Avangrid Renewables Bonneville Power Administration NorthWestern Energy SFP 10
Powerex Bonneville Power Administration Idaho Power Company SFP 11
Powerex Bonneville Power Administration NorthWestern Energy SFP 12
Powerex Chelan County PUD Idaho Power Company SFP 13
Rainbow Energy Marketing Corp Bonneville Power Administration Idaho Power Company SFP 14
Rainbow Energy Marketing Corp Bonneville Power Administration NorthWestern Energy SFP 15
The Energy Authority Bonneville Power Administration Idaho Power Company NF 16
Rainbow Energy Marketing Corp PacifiCorp Idaho Power Company SFP 17
PacifiCorp Idaho Power Company PacifiCorp SFP 18
Rainbow Energy Marketing Corp Puget Sound Energy Idaho Power Company SFP 19
Rainbow Energy Marketing Corp Grant County PUD Idaho Power Company SFP 20
Rainbow Energy Marketing Corp Avista Corporation Bonneville Power Administration SFP 21
The Energy Authority Bonneville Power Administration Avista Corporation SFP 22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90)Page 328.3
TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(Including transactions reffered to as 'wheeling')
FERC RateSchedule of
Tariff Number
(e)
Point of Receipt(Subsatation or Other
Designation)
(f)
Point of Delivery(Substation or Other
(g)
BillingDemand
(MW)
(h)
TRANSFER OF ENERGY
MegaWatt HoursReceived(i)Delivered(j)
MegaWatt HoursDesignation)
5. In column (e), identify the FERC Rate Schedule or Tariff Number, On separate lines, list all FERC rate schedules or contract
designations under which service, as identified in column (d), is provided.
6. Report receipt and delivery locations for all single contract path, "point to point" transmission service. In column (f), report the
designation for the substation, or other appropriate identification for where energy was received as specified in the contract. In column
(g) report the designation for the substation, or other appropriate identification for where energy was delivered as specified in the
contract.
7. Report in column (h) the number of megawatts of billing demand that is specified in the firm transmission service contract. Demand
reported in column (h) must be in megawatts. Footnote any demand not stated on a megawatts basis and explain.
8. Report in column (i) and (j) the total megawatthours received and delivered.
FERC Trf No. 8 60 60 1
FERC Trf No. 8 1,880 1,880 2
FERC Trf No. 8 213,207 213,207 3
FERC Trf No. 8 196 196 4
FERC Trf No. 8 5,183 5,183 5
FERC Trf No. 8 1,607 1,607 6
FERC Trf No. 8 19 19 7
FERC Trf No. 8 1,200 1,200 8
FERC Trf No. 8 44,220 44,220 9
FERC Trf No. 8 1,602 1,602 10
FERC Trf No. 8 61,746 61,746 11
FERC Trf No. 8 4,400 4,400 12
FERC Trf No. 8 2,676 2,676 13
FERC Trf No. 8 7,528 7,528 14
FERC Trf No. 8 8,659 8,659 15
FERC Trf No. 8 205 205 16
FERC Trf No. 8 200 200 17
FERC Trf No. 8 12,410 12,410 18
FERC Trf No. 8 2,654 2,654 19
FERC Trf No. 8 600 600 20
FERC Trf No. 8 400 400 21
FERC Trf No. 8 24 24 22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90)Page 329.3
13 3,510,201 3,510,201
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(m)(l)(k)(n)
(k+l+m)
Total Revenues ($)
(Including transactions reffered to as 'wheeling')
($)
Energy Charges
($)
(Other Charges)Demand Charges
($)
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
9. In column (k) through (n), report the revenue amounts as shown on bills or vouchers. In column (k), provide revenues from demand
charges related to the billing demand reported in column (h). In column (I), provide revenues from energy charges related to the amount
of energy transferred. In column (m), provide the total revenues from all other charges on bills or vouchers rendered, including out of
period adjustments. Explain in a footnote all components of the amount shown in column (m). Report in column (n) the total charge
shown on bills rendered to the entity Listed in column (a). If no monetary settlement was made, enter zero (11011) in column (n).
Provide a footnote explaining the nature of the non-monetary settlement, including the amount and type of energy or service rendered.
10. The total amounts in columns (i) and (j) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11. Footnote entries and provide explanations following all required data.
379 379 1
13,703 13,703 2
700,165 700,165 3
1,198 1,198 4
24,431 24,431 5
7,208 7,208 6
73 73 7
3,713 3,713 8
202,599 202,599 9
6,184 6,184 10
268,226 268,226 11
15,481 15,481 12
9,503 9,503 13
42,610 42,610 14
48,347 48,347 15
1,200 1,200 16
1,430 1,430 17
50,765 50,765 18
18,262 18,262 19
2,308 2,308 20
2,233 2,233 21
92 92 22
23
24
25
26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90)Page 330.3
12,628,226 16,370,526 3,742,300 0
Schedule Page: 328 Line No.: 2 Column: m
Use of facilities
Schedule Page: 328 Line No.: 3 Column: m
Use of facilities
Schedule Page: 328 Line No.: 5 Column: m
Ancillary services
Schedule Page: 328 Line No.: 6 Column: m
Ancillary services
Schedule Page: 328 Line No.: 7 Column: m
Ancillary services
Schedule Page: 328 Line No.: 8 Column: m
Ancillary services
Schedule Page: 328 Line No.: 9 Column: e
PURPA Interconnection under state jurisdiction
Schedule Page: 328 Line No.: 9 Column: m
Use of facilities
Schedule Page: 328 Line No.: 10 Column: e
PURPA Interconnection under state jurisdiction
Schedule Page: 328 Line No.: 10 Column: m
Use of facilities
Schedule Page: 328 Line No.: 11 Column: e
PURPA Interconnection under state jurisdiction
Schedule Page: 328 Line No.: 11 Column: m
Use of facilities
Schedule Page: 328 Line No.: 13 Column: e
PURPA Interconnection under state jurisdiction
Schedule Page: 328 Line No.: 13 Column: m
Use of facilities
Schedule Page: 328.1 Line No.: 11 Column: m
Ancillary services
Schedule Page: 328.2 Line No.: 2 Column: m
Parallel Capacity Support Agreement
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
LFP 1,505,764 1,505,764Bonneville Power Admin 1
LFP 12,609,600 2,160,672 10,448,928Bonneville Power Admin 2
OS 54,432 54,432Bonneville Power Admin 3
FNS 1,344,208 228,515 1,115,693Bonneville Power Admin 4
NF 38,612 38,612 7,258 7,258Bonneville Power Admin 5
NF 5,815 5,815 1,397 1,397Idaho Power Company 6
LFP 47,538 47,538Kootenai Electric Coop 7
LFP 137,268 137,268Northern Lights 8
SFP 83,499 3,111 80,388NorthWestern Energy 9
NF 43,725 43,725 12,036 12,036NorthWestern Energy 10
LFP 642,989 14,989 628,000Portland General Elec 11
NF 3,453 3,453 3,047 3,047Portland General Elec 12
NF 5,011 5,011 4,302 4,302Snohomish County PUD 13
NF 396-139 535 240 240Puget Sound Energy 14
NF 11,322 11,322 2,664 2,664Energy Keepers, Inc 15
NF 5,278 5,278 3,781 3,781Seattle City Light 16
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332
34,828 34,828 13,963,579 113,880 2,461,580 16,539,039TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Name of Company or Public
(d)(c)(a)Authority (Footnote Affiliations)
TRANSFER OF ENERGY
Magawatt-hoursReceived
Magawatt-
Deliveredhours
EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHERS
DemandCharges($)(e)
EnergyCharges
(f)($)
OtherCharges($)
(g)($)
Total Cost ofTransmission
(h)
(Including transactions referred to as "wheeling")
1. Report all transmission, i.e. wheeling or electricity provided by other electric utilities, cooperatives, municipalities, other public
authorities, qualifying facilities, and others for the quarter.
2. In column (a) report each company or public authority that provided transmission service. Provide the full name of the company,
abbreviate if necessary, but do not truncate name or use acronyms. Explain in a footnote any ownership interest in or affiliation with the
transmission service provider. Use additional columns as necessary to report all companies or public authorities that provided
transmission service for the quarter reported.
3. In column (b) enter a Statistical Classification code based on the original contractual terms and conditions of the service as follows:
FNS - Firm Network Transmission Service for Self, LFP - Long-Term Firm Point-to-Point Transmission Reservations. OLF - Other
Long-Term Firm Transmission Service, SFP - Short-Term Firm Point-to- Point Transmission Reservations, NF - Non-Firm Transmission
Service, and OS - Other Transmission Service. See General Instructions for definitions of statistical classifications.
4. Report in column (c) and (d) the total megawatt hours received and delivered by the provider of the transmission service.
5. Report in column (e), (f) and (g) expenses as shown on bills or vouchers rendered to the respondent. In column (e) report the demand
charges and in column (f) energy charges related to the amount of energy transferred. On column (g) report the total of all other charges
on bills or vouchers rendered to the respondent, including any out of period adjustments. Explain in a footnote all components of the
amount shown in column (g). Report in column (h) the total charge shown on bills rendered to the respondent. If no monetary settlement
was made, enter zero in column (h). Provide a footnote explaining the nature of the non-monetary settlement, including the amount and
type of energy or service rendered.
6. Enter "TOTAL" in column (a) as the last line.
7. Footnote entries and provide explanations following all required data.
Statistical
Classification(b)
NF 129 129 103 103The Energy Authority 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
FERC FORM NO. 1/3-Q (REV. 02-04)Page 332.1
34,828 34,828 13,963,579 113,880 2,461,580 16,539,039TOTAL
Schedule Page: 332 Line No.: 2 Column: g
Ancillary Services
Schedule Page: 332 Line No.: 3 Column: g
Use of Facilities
Schedule Page: 332 Line No.: 4 Column: g
Ancillary Services
Schedule Page: 332 Line No.: 9 Column: g
Ancillary Services and Regulation & Frequency Response
Schedule Page: 332 Line No.: 11 Column: g
Ancillary Services
Schedule Page: 332 Line No.: 14 Column: g
Ancillary Services
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MISCELLANEOUS GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Avista Corporation X 04/15/2021 2020/Q4
Line Description Amount
(b)(a)No.
1,156,732Industry Association Dues 1
Nuclear Power Research Expenses 2
Other Experimental and General Research Expenses 3
787,388Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4
Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5
481,418Community Relations 6
1,468,746Board of Director Activities 7
92,686Education, Information & Training 8
2,031,738Emergency Operating Procedure Events 9
41,782Misc Employee Expenses 10
5,135Misc Labor 11
181,490Misc Legal, Professional, and General Services 12
196,414Misc Transportation 13
25,474Other Misc Expenses <$5,000 14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
6,469,003
FERC FORM NO. 1 (ED. 12-94) Page 335
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403, 404, 405)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Functional Classification Depreciation
(d)(b)(a)
Amortization of
Total
(Except amortization of aquisition adjustments)
A. Summary of Depreciation and Amortization Charges
Expense(Account 403)
Limited TermElectric Plant Amortization ofOther ElectricPlant (Acc 405)(e) (f)
1. Report in section A for the year the amounts for : (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2. Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3. Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. Identify at the bottom of Section C the type of plant included
in any sub-account used.
In column (b) report all depreciable plant balances to which rates are applied showing subtotals by functional Classifications and showing
composite total. Indicate at the bottom of section C the manner in which column balances are obtained. If average balances, state the
method of averaging used.
For columns (c), (d), and (e) report available information for each plant subaccount, account or functional classification Listed in column
(a). If plant mortality studies are prepared to assist in estimating average service Lives, show in column (f) the type mortality curve
selected as most appropriate for the account and in column (g), if available, the weighted average remaining life of surviving plant. If
composite depreciation accounting is used, report available information called for in columns (b) through (g) on this basis.
4. If provisions for depreciation were made during the year in addition to depreciation provided by application of reported rates, state at the
bottom of section C the amounts and nature of the provisions and the plant items to which related.
(Account 404)(c)
DepreciationExpense for AssetRetirement Costs(Account 403.1)
4,734,362 4,734,362 1 Intangible Plant
26,466,230 26,466,230 2 Steam Production Plant
3 Nuclear Production Plant
14,525,512 14,525,512 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
10,583,010 10,583,010 6 Other Production Plant
17,309,358 17,309,358 7 Transmission Plant
50,168,069 50,168,069 8 Distribution Plant
9 Regional Transmission and Market Operation
4,461,715 4,334,242 127,473 10 General Plant
46,672,839 18,672,863 27,999,976 11 Common Plant-Electric
174,921,095 142,059,284 32,861,811 12 TOTAL
FERC FORM NO. 1 (REV. 12-03)Page 336
B. Basis for Amortization Charges
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f)(g)(Percent)
STEAM PLANT 12
Colstrip No. 3 13
70.00 -6.00 1.99 7.50S1.5311 57,709 14
60.00 -6.00 2.67 7.50R1312 86,478 15
-6.00 9.22 7.50R2.5313 343 16
40.00 -6.00 8.34 7.50R0.5314 23,854 17
50.00 -6.00 2.97 7.50R3315 10,548 18
53.00 -6.00 3.96 7.50R2316 9,916 19
Subtotal 188,848 20
21
Colstrip No. 4 22
70.00 -7.00 2.95 7.50S1.5311 54,319 23
60.00 -7.00 4.79 7.50R1312 60,447 24
-7.00 9.34 7.50R2.5313 738 25
40.00 -7.00 7.59 7.50R0.5314 15,766 26
50.00 -7.00 3.72 7.50R3315 8,014 27
53.00 -7.00 4.74 7.50R2316 5,249 28
Subtotal 144,533 29
30
Kettle Falls 31
1.32 12.00SQ310 433 32
70.00 -4.00 2.49 11.70S1.5311 28,776 33
55.00 -4.00 3.18 11.30R1312 46,845 34
35.00 -4.00 2.25 10.20R0.5314 18,632 35
50.00 -4.00 4.06 11.40R3315 12,389 36
55.00 -4.00 2.97 11.30R2316 2,477 37
Subtotal 109,552 38
39
HYDRO PLANT 40
Cabinet Gorge 41
100.00 1.90 38.10R4330 9,383 42
55.00 -16.00 1.73 42.45R2331 24,010 43
60.00 -16.00 2.03 45.53R1332 44,638 44
65.00 -16.00 2.59 40.80R1.5333 46,085 45
40.00 -16.00 2.10 29.40S1334 13,685 46
50.00 -16.00 1.89 41.38R1335 5,578 47
55.00 -16.00 2.00 29.30S2.5336 1,671 48
Subtotal 145,050 49
50
FERC FORM NO. 1 (REV. 12-03)Page 337
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f)(g)(Percent)
Noxon Rapids 12
100.00 1.64 52.50R4330 30,477 13
55.00 -24.00 2.23 44.50R2331 24,705 14
60.00 -24.00 2.22 47.23R1332 36,033 15
65.00 -24.00 2.41 44.90R1.5333 88,683 16
40.00 -24.00 4.09 27.40S1334 18,642 17
50.00 -24.00 2.04 41.68R1335 4,371 18
55.00 -24.00 2.96 26.20S2.5336 260 19
Subtotal 203,171 20
21
Post Falls 22
80.00 1.91 24.25R4330 2,908 23
55.00 -4.00 1.53 38.10R2331 4,403 24
60.00 -4.00 2.48 36.90R1332 25,932 25
65.00 -4.00 0.79 33.60R1.5333 2,234 26
40.00 -4.00 1.20 23.20S1334 1,977 27
60.00 -4.00 2.39 36.90R1335 804 28
55.00 -4.00 2.62 26.20S2.5336 578 29
Subtotal 38,836 30
31
Long Lake 32
80.00 1.91 25.70R4330 418 33
55.00 -7.00 1.64 33.70R2331 9,459 34
60.00 -7.00 1.85 34.00R1332 36,757 35
65.00 -7.00 0.45 33.70R1.5333 8,736 36
40.00 -7.00 0.85 29.20S1334 3,926 37
60.00 -7.00 1.69 32.60R1335 826 38
55.00 -7.00 2.62 26.20S2.5336 39
Subtotal 60,122 40
41
Little Falls 42
80.00 1.28 19.60R4330 4,217 43
110.00 -7.00 1.87 41.60R2331 4,242 44
100.00 -7.00 1.17 39.80R1332 6,434 45
65.00 -7.00 1.40 39.10R1.5333 39,074 46
40.00 -7.00 2.72 32.30S1334 13,895 47
60.00 -7.00 1.67 36.30R1335 549 48
Subtotal 68,411 49
50
FERC FORM NO. 1 (REV. 12-03)Page 337.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f)(g)(Percent)
Upper Falls 12
100.00 1.38 18.60R4330 64 13
50.00 -7.00 3.36 30.80R2331 1,082 14
110.00 -7.00 1.82 40.70R1332 7,729 15
65.00 -7.00 0.22 38.00R1.5333 1,166 16
40.00 -7.00 3.11 29.90S1334 4,299 17
60.00 -7.00 2.14 34.70R1335 104 18
55.00 -7.00 2.53 26.20S2.5336 508 19
Subtotal 14,952 20
21
Nine Mile 22
100.00 1.50 25.25R4330 11 23
110.00 -4.00 2.41 40.10R2331 20,419 24
110.00 -4.00 2.10 37.30R1332 30,904 25
65.00 -4.00 2.58 39.40R1.5333 41,757 26
40.00 -4.00 2.92 33.40S1334 17,923 27
60.00 -4.00 2.68 38.00R1335 1,071 28
55.00 -4.00 2.70 26.20S2.5336 595 29
Subtotal 112,680 30
31
Monroe Street 32
55.00 -7.00 2.39 40.80R2331 12,128 33
110.00 -7.00 1.91 49.80R1332 9,972 34
65.00 -7.00 2.22 40.80R1.5333 11,575 35
40.00 -7.00 3.66 25.60S1334 3,178 36
60.00 -7.00 2.30 40.50R1335 34 37
55.00 -7.00 2.89 31.10R2.5336 50 38
Subtotal 36,937 39
40
OTHER PRODUCTION 41
Northeast Turbine 42
55.00 -5.00 30.78 2.00S4341 751 43
55.00 -5.00 R3342 37 44
60.00 -5.00 2.51 2.00S2.5343 9,058 45
45.00 -5.00 2.56 2.00R1344 2,609 46
20.00 -5.00 16.94 2.00S1345 1,243 47
35.00 -5.00 23.28 1.90R2.5346 399 48
Subtotal 14,097 49
50
FERC FORM NO. 1 (REV. 12-03)Page 337.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f)(g)(Percent)
Rathdrum Turbine 12
55.00 -4.00 3.70 16.00S4341 3,565 13
55.00 -4.00 3.56 17.60R3342 1,696 14
60.00 -4.00 3.77 17.60S2.5343 5,722 15
45.00 -4.00 3.94 16.40R1344 50,500 16
20.00 -4.00 8.22 11.90S1345 3,457 17
35.00 -4.00 5.69 17.40R2.5346 249 18
Subtotal 65,189 19
20
Kettle Falls CT 21
55.00 -1.00 1.36 11.00S43419 22
55.00 -1.00 3.33 11.80R3342 89 23
60.00 -1.00 3.45 11.90S2.5343 8,670 24
45.00 -1.00 4.11 11.30R1344 759 25
20.00 -1.00 8.00 11.00S1345 13 26
Subtotal 9,540 27
28
Boulder Park 29
55.00 -2.00 2.56 25.90S4341 1,274 30
55.00 -2.00 2.62 25.00R3342 162 31
60.00 -2.00 2.38 25.30S2.5343 57 32
45.00 -2.00 2.43 22.20R1344 31,285 33
20.00 -2.00 6.42 15.10S1345 662 34
35.00 -2.00 3.99 23.70R2.5346 65 35
Subtotal 33,505 36
37
Coyote Springs 2 38
55.00 -3.00 2.37 26.80S4341 11,849 39
55.00 -3.00 2.45 25.60R3342 19,000 40
45.00 -3.00 3.36 23.40R1344 138,025 41
20.00 -3.00 5.25 11.70S1345 17,123 42
35.00 -3.00 4.27 22.10R2.5346 935 43
Subtotal 186,932 44
45
Solar Power 46
25.00 -3.00 7.46 12.70S2.5344 & 345 482 47
Subtotal 482 48
49
Lancaster 50
FERC FORM NO. 1 (REV. 12-03)Page 337.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f)(g)(Percent)
55.00 -5.00 3.07 23.40R3342 92 12
45.00 -5.00 3.52 21.50R1344 209 13
20.00 -5.00 6.19 16.70S1345 49 14
Subtotal 350 15
16
TRANSMISSION PLANT 17
80.00 1.13 55.85R4350 22,799 18
65.00 -10.00 1.63 52.90S1.5352 29,270 19
44.00 -10.00 2.41 32.60R2353 316,164 20
75.00 -15.00 1.51 41.90R4354 17,254 21
63.00 -30.00 1.93 51.70R2.5355 301,952 22
70.00 -30.00 1.90 45.90R3356 166,779 23
60.00 1.64 47.40R4357 3,831 24
50.00 2.06 29.30S3358 3,179 25
70.00 1.41 42.80R4359 2,161 26
Subtotal 863,389 27
28
DISTRIBUTION PLANT 29
75.00 1.34 69.40R4360 4,139 30
60.00 -10.00 1.72 46.70S1.5361 35,477 31
42.00 -10.00 2.68 30.40R1.5362 158,013 32
15.00 6.80 13.50L3363 2,598 33
67.00 -60.00 2.47 51.70R2.5364 - WA 302,630 34
65.00 -60.00 2.57 51.70R2.5364 - ID 159,053 35
68.00 -50.00 2.27 44.40R3365 - WA 191,455 36
65.00 -50.00 2.45 44.40R3.5365 - ID 108,031 37
60.00 -30.00 1.56 46.50R1.5366 - WA 88,440 38
60.00 -30.00 2.14 46.50S2.5366 - ID 45,790 39
35.00 -30.00 3.44 24.70S1.5367 - WA 154,626 40
35.00 -20.00 2.99 24.70S1.5367 - ID 77,996 41
47.00 -10.00 2.16 35.50R2368 293,857 42
65.00 -40.00 2.10 50.40R4369 190,214 43
35.00 -2.00 2.89 S0370 - AN 157 44
15.00 9.06 7.70S2.5370.2 - ID 23,750 45
35.00 2.89 26.50S0370.3 - WA 58,292 46
10.00 10.36 9.50S1371 3,152 47
37.00 -20.00 1.87 27.90R2.5373 25,497 48
37.00 -20.00 3.04 29.20R2.5373.4 27,769 49
37.00 -20.00 3.17 36.10R2.5373.5 16,552 50
FERC FORM NO. 1 (REV. 12-03)Page 337.4
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Account No.
(c)(b)(a)(d)(e)
C. Factors Used in Estimating Depreciation Charges
Depreciable
Plant Base(In Thousands)
Estimated
Avg. ServiceLife
Net
Salvage(Percent)
Applied
Depr. rates
Mortality
CurveType
Average
RemainingLife(f)(g)(Percent)
Subtotal 1,967,488 12
13
GENERAL PLANT 14
50.00 -5.00 1.90 42.20R2.5390.1 10,676 15
15.00 6.67 15.00SQ3918 16
5.00 20.00 1.70SQ391.1 2,514 17
25.00 4.00 14.60SQ393 387 18
20.00 5.00 11.00SQ394 6,813 19
15.00 6.67 7.40SQ395 1,908 20
15.00 6.67 8.50SQ397 48,895 21
10.00 10.00 6.60SQ398 279 22
Subtotal 71,480 23
24
MISC POWER 25
16.00 5.48 12.20L2.5392 8,508 26
22.00 3.75 14.80S1396 4,001 27
Subtotal 12,509 28
29
30
31
32
33
34
35
36
37
38
TOTAL COMPANY 4,348,053 39
40
41
42
43
44
45
46
47
48
49
50
FERC FORM NO. 1 (REV. 12-03)Page 337.5
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Description Assessed by
(c)(b)(a)
Total Expense forExpenses
of
(d)
(Furnish name of regulatory commission or body the Regulatory
docket or case number and a description of the case)Commission Utility Current Year(b) + (c)
Deferredin Account182.3 at Beginning of Year(e)
1. Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if being
amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2. Report in columns (b) and (c), only the current year's expenses that are not deferred and the current year's amortization of amounts
deferred in previous years.
Federal Energy Regulatory Commission 1
Charges include annual fee and license fees 2
for the Spokane River Project, the Cabinet 3
Gorge Project and the Noxon Rapids Project. 2,629,180 34,224 2,663,404 4
5
6
7
8
Washington Utilities and Transportation 9
Commission: includes annual fee and various 10
other electric dockets 1,099,656 687,609 1,787,265 11
12
Includes annual fee and various other natural 13
gas dockets 295,440 153,301 448,741 14
15
Idaho Public Utilities Commission 16
Includes annual fee and various other electric 17
dockets 684,318 160,523 844,841 18
19
Includes annual fee and various other natural 20
gas dockets 163,671 46,147 209,818 21
22
Public Utility Commission of Oregon 23
Includes annual fees and various other natural 24
gas dockets 611,398 351,510 962,908 25
26
Not directly assigned electric 725,551 725,551 27
Not directly assigned natural gas 311,991 311,991 28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 350
46 TOTAL 5,483,663 2,470,856 7,954,519
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
REGULATORY COMMISSION EXPENSES (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(j)(i)(f)(k) (l)
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO
Department AccountNo.(g)
Amount
(h)
Deferred to
Account 182.3
Contra
Account Amount Deferred in Account 182.3End of Year
3. Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4. List in column (f), (g), and (h) expenses incurred during year which were charged currently to income, plant, or other accounts.
5. Minor items (less than $25,000) may be grouped.
1
2
3
Electric 4 2,663,404928
5
6
7
8
9
10
Electric 11 1,787,265928
12
13
Gas 14 448,741928
15
16
17
Electric 18 844,841928
19
20
Gas 21 209,818928
22
23
24
59,519 13,133407.4 72,367Gas 25 962,908928
26
Electric 27 725,551928
Gas 28 311,991928
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 351
46 7,954,519 72,367 13,133 59,519
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Description
(b)(a)
Classification
1. Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D & D)
project initiated, continued or concluded during the year. Report also support given to others during the year for jointly-sponsored projects.(Identify
recipient regardless of affiliation.) For any R, D & D work carried with others, show separately the respondent's cost for the year and cost chargeable to
others (See definition of research, development, and demonstration in Uniform System of Accounts).
2. Indicate in column (a) the applicable classification, as shown below:
Classifications:
A. Electric R, D & D Performed Internally:a. Overhead
(1) Generation b. Underground
a. hydroelectric (3) Distribution
i. Recreation fish and wildlife (4) Regional Transmission and Market Operation
ii Other hydroelectric (5) Environment (other than equipment)
b. Fossil-fuel steam (6) Other (Classify and include items in excess of $50,000.)
c. Internal combustion or gas turbine (7) Total Cost Incurred
d. Nuclear B. Electric, R, D & D Performed Externally:
e. Unconventional generation (1) Research Support to the electrical Research Council or the Electric
f. Siting and heat rejection Power Research Institute
(2) Transmission
Battery Storage and Electric Vehicle Supply EquipA. Electric (3) Distribution 1
2
3
4
5
6
7
8
9
10
HUB-Morris Center Lab Test FacilityA. Electric (6) Other - Testing Lab & Facility 11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 352
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
AMOUNTS CHARGED IN CURRENT YEAR
(e)(c)
Costs Incurred Internally
Current Year Costs Incurred Externally
Current Year
(d)Account Amount(f)
Unamortized
Accumulation
(g)
(2) Research Support to Edison Electric Institute
(3) Research Support to Nuclear Power Groups
(4) Research Support to Others (Classify)
(5) Total Cost Incurred
3. Include in column (c) all R, D & D items performed internally and in column (d) those items performed outside the company costing $50,000 or more,
briefly describing the specific area of R, D & D (such as safety, corrosion control, pollution, automation, measurement, insulation, type of appliance, etc.).
Group items under $50,000 by classifications and indicate the number of items grouped. Under Other, (A (6) and B (4)) classify items by type of R, D & D
activity.
4. Show in column (e) the account number charged with expenses during the year or the account to which amounts were capitalized during the year,
listing Account 107, Construction Work in Progress, first. Show in column (f) the amounts related to the account charged in column (e)
5. Show in column (g) the total unamortized accumulating of costs of projects. This total must equal the balance in Account 188, Research,
Development, and Demonstration Expenditures, Outstanding at the end of the year.
6. If costs have not been segregated for R, D &D activities or projects, submit estimates for columns (c), (d), and (f) with such amounts identified by "Est."
7. Report separately research and related testing facilities operated by the respondent.
1,992,325 1 609,473 107 2,601,798
2 1,422 108 1,422
3 248,828 182 248,828
4 17,989 557 17,989
173,909 5 27,987 580 201,896
1,954 6587 1,954
67,886 7 9,768 598 77,654
200,595 8-1,350 920 199,245
9 16,858 930 16,858
10
453,374 11 3,965,780 107 4,419,154
58,348 12182 58,348
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
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
DISTRIBUTION OF SALARIES AND WAGES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Electric 1
Operation 2
13,667,061Production 3
4,359,748Transmission 4
Regional Market 5
9,555,026Distribution 6
6,615,674Customer Accounts 7
473,347Customer Service and Informational 8
Sales 9
27,189,564Administrative and General 10
61,860,420TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
4,612,103Production 13
907,722Transmission 14
Regional Market 15
5,236,480Distribution 16
Administrative and General 17
10,756,305TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
18,279,164Production (Enter Total of lines 3 and 13) 20
5,267,470Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
14,791,506Distribution (Enter Total of lines 6 and 16) 23
6,615,674Customer Accounts (Transcribe from line 7) 24
473,347Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
27,189,564Administrative and General (Enter Total of lines 10 and 17) 27
81,758,666 9,141,941 72,616,725TOTAL Oper. and Maint. (Total of lines 20 thru 27) 28
Gas 29
Operation 30
Production-Manufactured Gas 31
Production-Nat. Gas (Including Expl. and Dev.) 32
1,104,381Other Gas Supply 33
6,045Storage, LNG Terminaling and Processing 34
Transmission 35
5,936,287Distribution 36
2,930,182Customer Accounts 37
294,694Customer Service and Informational 38
Sales 39
11,457,871Administrative and General 40
21,729,460TOTAL Operation (Enter Total of lines 31 thru 40) 41
Maintenance 42
Production-Manufactured Gas 43
Production-Natural Gas (Including Exploration and Development) 44
Other Gas Supply 45
Storage, LNG Terminaling and Processing 46
1,955,158Transmission 47
FERC FORM NO. 1 (ED. 12-88) Page 354
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
DISTRIBUTION OF SALARIES AND WAGES (Continued)
3,487,785Distribution 48
Administrative and General 49
5,442,943TOTAL Maint. (Enter Total of lines 43 thru 49) 50
Total Operation and Maintenance 51
Production-Manufactured Gas (Enter Total of lines 31 and 43) 52
Production-Natural Gas (Including Expl. and Dev.) (Total lines 32, 53
1,104,381Other Gas Supply (Enter Total of lines 33 and 45) 54
6,045Storage, LNG Terminaling and Processing (Total of lines 31 thru 47) 55
1,955,158Transmission (Lines 35 and 47) 56
9,424,072Distribution (Lines 36 and 48) 57
2,930,182Customer Accounts (Line 37) 58
294,694Customer Service and Informational (Line 38) 59
Sales (Line 39) 60
11,457,871Administrative and General (Lines 40 and 49) 61
30,377,344 3,204,941 27,172,403TOTAL Operation and Maint. (Total of lines 52 thru 61) 62
Other Utility Departments 63
Operation and Maintenance 64
112,136,010 12,346,882 99,789,128TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
51,479,159 6,589,540 44,889,619Electric Plant 68
14,139,782 2,383,819 11,755,963Gas Plant 69
Other (provide details in footnote): 70
65,618,941 8,973,359 56,645,582TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
1,997,016 166,241 1,830,775Electric Plant 73
665,816 55,425 610,391Gas Plant 74
Other (provide details in footnote): 75
2,662,832 221,666 2,441,166TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
-2,463,257 2,463,257Stores Expense (163) 78
79
-4,652,116 4,652,116Small Tool Expense (184) 80
1,269,599 1,269,599Miscellaneous Deferred Debits (186) 81
407,078 407,078Non-operating Expenses (417) 82
135,681 135,681RetirementBonus/SERP/HRA Settlement (228) 83
864,971 864,971Activities (426) 84
-12,199,466 12,199,466Employee Incentive Plan (232380) 85
-2,227,068 2,227,068DSM Tarrif Rider and (242600) 86
152,034 152,034Incentive / Stock Compensation (238000) 87
19,670,743 19,670,743Payroll Equalization Liability(242700) 88
89
90
91
92
93
94
22,500,106-21,541,907 44,042,013TOTAL Other Accounts 95
202,917,889 202,917,889TOTAL SALARIES AND WAGES 96
FERC FORM NO. 1 (ED. 12-88) Page 355
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMMON UTILITY PLANT AND EXPENSES
Avista Corporation X
04/15/2021 2020/Q4
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts
as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the
respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including explanation
of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
1 & 2. Common Plant in service and accumulated provision for depreciation
Acct. No. Description
303 Intangible 304,344,902
389 Land and Land Rights 13,914,952
390 Structures and Improvements 159,691,791
391 Office Furniture and Equipment 85,031,246
392 Transportation Equipment 14,561,590
393 Stores Equipment 5,027,374
394 Tools, Shop & Garage Equipment 14,641,292
395 Laboratory Equipment 1,610,417
396 Power Operated Equipment 1,953,262
397 Communications Equipment 90,260,645
398 Miscellaneous Equipment 692,982
399 Asset Retirement Cost 0
Total Common Plant 691,730,453
Const. Work in Progress 17,575,548
Total Utility Plant 709,306,001
Acc. Prov. for Dep. & Amort.236,921,589
Net Utility Plant 472,384,412
3. Common Expenses allocated to Electric and Gas departments:
Allocation to Allocated to
Acct. No. Description Total Electric Dept Gas Dept Basis of Allocation
901 Cust acct/collect supervision 285,636 149,519 136,117 # of Customers
902 Meter reading expenses 1,991,082 1,203,191 787,891 # of Customers
903 Cust rec & collectn expenses 13,992,504 7,415,685 6,576,819 # of Customers
904 Uncollectible accounts 0 0 0 # of Customers
905 Misc cust acct expenses 279,808 145,713 134,095 # of Customers
907 Cust svce & Info exp supervision 0 0 0 # of Customers
908 Cust assistance expenses 534,483 322,119 212,364 # of Customers
909 Info & instruct advert expenses1,704,434 1,029,972 674,462 # of Customers
910 Misc cust serv & info expenses 616,000 320,788 295,212 # of Customers
911 Sales expense -supervision 0 0 0 # of Customers
912 Demo and selling expenses 0 0 0 # of Customers
FERC FORM NO. 1 (ED. 12-87)Page 356
Name of Respondent This Report Is:
(1) An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of
COMMON UTILITY PLANT AND EXPENSES
Avista Corporation X
04/15/2021 2020/Q4
1. Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by accounts
as provided by Plant Instruction 13, Common Utility Plant, of the Uniform System of Accounts. Also show the allocation of such plant costs to the
respective departments using the common utility plant and explain the basis of allocation used, giving the allocation factors.
2. Furnish the accumulated provisions for depreciation and amortization at end of year, showing the amounts and classifications of such accumulated
provisions, and amounts allocated to utility departments using the Common utility plant to which such accumulated provisions relate, including explanation
of basis of allocation and factors used.
3. Give for the year the expenses of operation, maintenance, rents, depreciation, and amortization for common utility plant classified by accounts as
provided by the Uniform System of Accounts. Show the allocation of such expenses to the departments using the common utility plant to which such
expenses are related. Explain the basis of allocation used and give the factors of allocation.
4. Give date of approval by the Commission for use of the common utility plant classification and reference to order of the Commission or other
authorization.
913 Advertising expenses 0 0 0 # of Customers
916 Misc sales expenses 0 0 0 # of Customers
920 Admin & gen salaries 37,468,341 26,233,828 11,234,513 Four Factor
921 Office supplies & expenses 5,940,261 4,150,086 1,790,175 Four Factor
922 Admin expenses tranf-credit 0 0 0 Four Factor
923 Outside services employed 14,294,431 9,998,838 4,295,593 Four Factor
924 Property insurance 1,895,653 1,323,583 572,070 Four Factor
925 Injuries and damages 6,913,181 4,948,673 1,964,508 Four Factor
926 Employee pensions&benefits 94,320,328 65,999,683 28,320,645 Four Factor
927 Franchise requirement 0 0 0 Four Factor
928 Regulatory commission expenses 1,722,828 1,255,660 467,168 Four Factor
929 Duplicate charges-credit 0 0 0 Four Factor
930.1 General advertising expenses 0 0 0 Four Factor
930.2 Misc general expenses 7,786,009 5,450,509 2,335,500 Four Factor
931 Rents 532,877 373,300 159,577 Four Factor
935 Maint of general plant 15,771,036 11,175,850 4,595,186 Four Factor
403 Depreciation 26,398,612 18,672,863 7,725,749 Four Factor
404 Amort of LTD term plant 39,682,805 27,999,976 11,682,829 Four Factor
Note 1: The 4 factor allocator is made up of 25% each -customer counts, direct labor, direct O&M & Net
direct plant
4. Letters of approval received from staffs of State Regulatory Commissions in 1993
FERC FORM NO. 1 (ED. 12-87)Page 356.1
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Description of Item(s)Balance at End of
(c)(b)(a)
Balance at End of
AMOUNTS INCLUDED IN ISO/RTO SETTLEMENT STATEMENTS
Quarter 1 Quarter 2
Balance at End of
Quarter 3
(d)(e)
1. The respondent shall report below the details called for concerning amounts it recorded in Account 555, Purchase Power, and Account 447, Sales for
Resale, for items shown on ISO/RTO Settlement 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 determining
whether a net purchase or sale has occurred. In 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.
Balance at End of
Year
Energy 1
Net Purchases (Account 555) 2 112,077 5,639 48,058 109,281
Net Sales (Account 447) 3 ( 10,567,487)( 3,822,515) ( 5,962,090) ( 7,757,268)
Transmission Rights 4
Ancillary Services 5 ( 37,898)( 7,297) ( 14,142) ( 24,226)
Other Items (list separately) 6
Access Charge 7 16,454 1,582
Cost Recovery 8 ( 11,292)( 7,654) ( 11,596) ( 11,243)
Day Ahead Energy-Congestion Losses 9 ( 3,975)( 3) ( 5) ( 3,528)
FERC Fees 10 235 146
GMC 11 157,048 51,416 96,584 126,745
Hour Ahead Scheduling Process-RT 12 ( 2,105) 254 427 ( 1,980)
Other 13 ( 2,568)32 ( 1,055)( 1,186)
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
( 10,339,511)( 3,780,128) ( 5,843,819) ( 7,561,677)
FERC FORM NO. 1/3-Q (NEW. 12-05)Page 397
46 TOTAL
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
PURCHASES AND SALES OF ANCILLARY SERVICES
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Type of Ancillary Service
(a)
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1) On line 1 columns (b), (c), (d), (e), (f) and (g) report the amount of ancillary services purchased and sold during the year.
(2) On line 2 columns (b) (c), (d), (e), (f), and (g) report the amount of reactive supply and voltage control services purchased and sold
during the year.
(3) On line 3 columns (b) (c), (d), (e), (f), and (g) report the amount of regulation and frequency response services purchased and sold
during the year.
(4) On line 4 columns (b), (c), (d), (e), (f), and (g) report the amount of energy imbalance services purchased and sold during the year.
(5) On lines 5 and 6, columns (b), (c), (d), (e), (f), and (g) report the amount of operating reserve spinning and supplement services
purchased and sold during the period.
(6) On line 7 columns (b), (c), (d), (e), (f), and (g) report the total amount of all other types ancillary services purchased or sold during the
year. Include in a footnote and specify the amount for each type of other ancillary service provided.
Number of Units
Unit of
Measure Dollars
(b) (c) (d)
Number of Units
Unit of
Measure Dollars
(e) (f) (g)
Usage - Related Billing Determinant Usage - Related Billing Determinant
Amount Purchased for the Year Amount Sold for the Year
Scheduling, System Control and Dispatch 1
Reactive Supply and Voltage 2
1,062,984MW 82Regulation and Frequency Response 3
1,390,916MWh 38,240 466,330MWh 21,754Energy Imbalance 4
797,238MW 61Operating Reserve - Spinning 5
734,478MW 61Operating Reserve - Supplement 6
10,475,077MW 836 10,475,077MW 836Other 7
14,460,693 39,280 10,941,407 22,590Total (Lines 1 thru 7) 8
FERC FORM NO. 1 (New 2-04) Page 398
Schedule Page: 398 Line No.: 4 Column: d
Includes both Energy Imbalance and Generator Imbalance
Schedule Page: 398 Line No.: 4 Column: g
Includes both Energy Imbalance and Generator Imbalance
Schedule Page: 398 Line No.: 7 Column: d
Amounts reported are offsetting imputed amounts reflecting the self-provision of ancillary
service for bundled retail native load customers under state jurisdiction.
Schedule Page: 398 Line No.: 7 Column: g
Amounts reported are offsetting imputed amounts reflecting the self-provision of ancillary
service for bundled retail native load customers under state jurisdiction.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
This Page Intentionally Left Blank
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Monthly Peak
MW - Total
(c)(b)(a)
Month
NAME OF SYSTEM:
Day of
Monthly
Peak
(1) Report the monthly peak load on the respondent's transmission system. If the respondent has two or more power systems which are not physically
integrated, furnish the required information for each non-integrated system.
(2) Report on Column (b) by month the transmission system's peak load.
(3) Report on Columns (c ) and (d) the specified information for each monthly transmission - system peak load reported on Column (b).
(4) Report on Columns (e) through (j) by month the system' monthly maximum megawatt load by statistical classifications. See General Instruction for the
definition of each statistical classification.
(d)
Hour of
Monthly
Peak
(e)
Firm Network
Service for Self
(f)
Firm Network
Service for
Others
(g)
Long-Term Firm
Point-to-point
Reservations
(h)
Other Long-
Term Firm
Service
(i)
Short-Term Firm
Point-to-point
Reservation
(j)
Other
Service
11 95 130 282 355 1,536190014 2,268January 1
12 305 377 282 286 1,3161800 6 2,189February 2
15 85 485 286 299 1,311 80010 1,981March 3
38 485 992 850 940 4,163Total for Quarter 1 4
5 85 393 297 274 1,1901000 1 1,846April 5
15 95 300 302 253 1,258180029 1,908May 6
15 369 806 298 273 1,362180024 2,302June 7
35 549 1,499 897 800 3,810Total for Quarter 2 8
15 457 545 296 343 1,650170031 2,746July 9
21 736 353 297 316 1,553160019 2,901August 10
22 488 275 290 298 1,4161800 4 2,492September 11
58 1,681 1,173 883 957 4,619Total for Quarter 3 12
10 539 284 288 334 1,350 90026 2,511October 13
9 118 67 282 295 1,364180030 2,059November 14
17 124 76 282 309 1,4181800 7 2,133December 15
36 781 427 852 938 4,132Total for Quarter 4 16
167 3,496 4,091 3,482 3,635 16,724
Total Year to
Date/Year
17
FERC FORM NO. 1/3-Q (NEW. 07-04)Page 400
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
ELECTRIC ENERGY ACCOUNT
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Item
(a)(b)(a)(b)
Line
No.MegaWatt Hours Item MegaWatt Hours
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
SOURCES OF ENERGY1
Generation (Excluding Station Use):2
1,485,162Steam3
Nuclear4
3,650,548Hydro-Conventional5
Hydro-Pumped Storage6
1,988,395Other7
Less Energy for Pumping8
7,124,105Net Generation (Enter Total of lines 3
through 8)
9
5,465,161Purchases10
Power Exchanges:11
9,313Received12
429,763Delivered13
-420,450Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
3,510,201Received16
3,510,201Delivered17
Net Transmission for Other (Line 16 minus
line 17)
18
Transmission By Others Losses19
12,168,816TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
8,875,043Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
Requirements Sales for Resale (See
instruction 4, page 311.)
23
2,796,393Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
44,593Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
452,787Total Energy Losses27
12,168,816TOTAL (Enter Total of Lines 22 Through
27) (MUST EQUAL LINE 20)
28
FERC FORM NO. 1 (ED. 12-90)Page 401a
(d)
Day of Month
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
MONTHLY PEAKS AND OUTPUT
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Total Monthly Energy Megawatts
(c)(b)(a)
Hour
(e)
MONTHLY PEAK
Month
NAME OF SYSTEM:
Monthly Non-RequirmentsSales for Resale &Associated Losses (See Instr. 4)
1. Report the monthly peak load and energy output. If the respondent has two or more power which are not physically integrated, furnish the required
information for each non- integrated system.
2. Report in column (b) by month the system’s output in Megawatt hours for each month.
3. Report in column (c) by month the non-requirements sales for resale. Include in the monthly amounts any energy losses associated with the sales.
4. Report in column (d) by month the system’s monthly maximum megawatt load (60 minute integration) associated with the system.
5. Report in column (e) and (f) the specified information for each monthly peak load reported in column (d).
(f)
January 29 14 1,613 248,892 1900 1,152,209
February 30 4 1,512 231,269 1800 1,049,271
March 31 10 1,362 246,047 0800 1,060,578
April 32 1 1,262 406,733 1000 1,107,339
May 33 29 1,303 308,891 1800 987,788
June 34 23 1,445 222,362 1700 896,267
July 35 31 1,708 246,947 1600 1,038,492
August 36 17 1,721 189,422 1600 1,002,989
September 37 4 1,473 156,712 1700 847,969
October 38 26 1,416 170,737 1000 922,806
November 39 30 1,423 180,789 1300 997,749
December 40 7 1,479 187,592 1800 1,105,359
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 12,168,816 2,796,393
Spokane N.E.Coyote Springs 2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Gas TurbineGas Turbine 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Not ApplicableNot Applicable 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
19782003 3 Year Originally Constructed
19782003 4 Year Last Unit was Installed
61.80295.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
44282 6 Net Peak Demand on Plant - MW (60 minutes)
216736 7 Plant Hours Connected to Load
65295 8 Net Continuous Plant Capability (Megawatts)
0295 9 When Not Limited by Condenser Water
0295 10 When Limited by Condenser Water
115 11 Average Number of Employees
6660001767332000 12 Net Generation, Exclusive of Plant Use - KWh
1387530 13 Cost of Plant: Land and Land Rights
75102511848521 14 Structures and Improvements
13343648175083507 15 Equipment Costs
0351682 16 Asset Retirement Costs
14233426187283710 17 Total Cost
230.3143634.8600 18 Cost per KW of Installed Capacity (line 17/5) Including
4225126688 19 Production Expenses: Oper, Supv, & Engr
1630725388467 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
417601784704 25 Electric Expenses
4394130027 26 Misc Steam (or Nuclear) Power Expenses
087122 27 Rents
00 28 Allowances
21053174095 29 Maintenance Supervision and Engineering
1617174581 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
432403612570 32 Maintenance of Electric Plant
21963202092 33 Maintenance of Misc Steam (or Nuclear) Plant
15455931680346 34 Total Production Expenses
0.23210.0179 35 Expenses per Net KWh
Gas Gas 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
MCF MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
11629411 0 0 8062 0 0 38 Quantity (Units) of Fuel Burned
1020000 0 0 1020000 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
2.183 0.000 0.000 2.023 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
2.183 0.000 0.000 2.023 0.000 0.000 41 Average Cost of Fuel per Unit Burned
2.140 0.000 0.000 1.983 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.014 0.000 0.000 0.024 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
6712.000 0.000 0.000 12347.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03)Page 402
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
RathdrumColstripKettle Falls
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
Gas TurbineSteam Steam 1
Not ApplicableConventional Conventional 2
19951983 1984 3
19951983 1985 4
166.5050.70 233.40 5
16198 235 6
12843759 6916 7
16754 222 8
054 222 9
054 222 10
128 249 11
171022000264851000 1220311000 12
6216822573941 1289395 13
356511828775717 112028649 14
6162433080342935 221351503 15
0323787 14387288 16
65811130112016380 349056835 17
395.26202209.3961 1495.5306 18
13258205292 149532 19
32233347093295 22413469 20
00 0 21
0537501 2976867 22
00 0 23
00 0 24
242375709798 33359 25
19942387759 4121891 26
00 0 27
00 0 28
41274105987 549910 29
0140959 635889 30
01657292 6138583 31
62878308156 1958141 32
68289213320 973011 33
367135011359359 39950652 34
0.02150.0429 0.0327 35
Wood Gas GasCoal Oil 36
Ton MCF MCFTonBBL 37
462472 4743 0 2016263 0 0762615 2755 0 38
8600000 1020000 0 1020000 0 016970000 5880000 0 39
15.314 2.364 0.000 1.599 0.000 0.00029.096 81.344 0.000 40
15.314 2.364 0.000 1.599 0.000 0.00029.096 81.344 0.000 41
1.781 2.317 0.000 1.567 0.000 0.0001.715 13.834 0.000 42
0.027 0.035 0.000 0.019 0.000 0.0000.018 0.000 0.000 43
15035.000 0.000 0.000 12025.000 0.000 0.00010618.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03)Page 403
Boulder Park
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Internal Comb 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Conventional 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
2002 3 Year Originally Constructed
2002 4 Year Last Unit was Installed
0.0024.60 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
035 6 Net Peak Demand on Plant - MW (60 minutes)
02289 7 Plant Hours Connected to Load
025 8 Net Continuous Plant Capability (Megawatts)
00 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
02 11 Average Number of Employees
048140000 12 Net Generation, Exclusive of Plant Use - KWh
0185629 13 Cost of Plant: Land and Land Rights
01273892 14 Structures and Improvements
032230931 15 Equipment Costs
00 16 Asset Retirement Costs
033690452 17 Total Cost
01369.5306 18 Cost per KW of Installed Capacity (line 17/5) Including
09512 19 Production Expenses: Oper, Supv, & Engr
0840291 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
0228328 25 Electric Expenses
021332 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
058062 29 Maintenance Supervision and Engineering
0400 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
0388157 32 Maintenance of Electric Plant
0108042 33 Maintenance of Misc Steam (or Nuclear) Plant
01654124 34 Total Production Expenses
0.00000.0344 35 Expenses per Net KWh
Gas 36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
MCF 37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
432653 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
1020000 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
1.942 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
1.942 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
1.904 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.017 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
9167.000 0.000 0.000 0.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03)Page 402.1
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
1
2
3
4
0.000.00 0.00 5
00 0 6
00 0 7
00 0 8
00 0 9
00 0 10
00 0 11
00 0 12
00 0 13
00 0 14
00 0 15
00 0 16
00 0 17
00 0 18
00 0 19
00 0 20
00 0 21
00 0 22
00 0 23
00 0 24
00 0 25
00 0 26
00 0 27
00 0 28
00 0 29
00 0 30
00 0 31
00 0 32
00 0 33
00 0 34
0.00000.0000 0.0000 35
36
37
0 0 0 0 0 0000 38
0 0 0 0 0 0000 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03)Page 403.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
2 Type of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was Installed
0.000.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
00 6 Net Peak Demand on Plant - MW (60 minutes)
00 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
00 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
00 12 Net Generation, Exclusive of Plant Use - KWh
00 13 Cost of Plant: Land and Land Rights
00 14 Structures and Improvements
00 15 Equipment Costs
00 16 Asset Retirement Costs
00 17 Total Cost
00 18 Cost per KW of Installed Capacity (line 17/5) Including
00 19 Production Expenses: Oper, Supv, & Engr
00 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
00 25 Electric Expenses
00 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
00 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
00 32 Maintenance of Electric Plant
00 33 Maintenance of Misc Steam (or Nuclear) Plant
00 34 Total Production Expenses
0.00000.0000 35 Expenses per Net KWh
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
0 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
0 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
0.000 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
0.000 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.000 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
0.000 0.000 0.000 0.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03)Page 402.2
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
1
2
3
4
0.000.00 0.00 5
00 0 6
00 0 7
00 0 8
00 0 9
00 0 10
00 0 11
00 0 12
00 0 13
00 0 14
00 0 15
00 0 16
00 0 17
00 0 18
00 0 19
00 0 20
00 0 21
00 0 22
00 0 23
00 0 24
00 0 25
00 0 26
00 0 27
00 0 28
00 0 29
00 0 30
00 0 31
00 0 32
00 0 33
00 0 34
0.00000.0000 0.0000 35
36
37
0 0 0 0 0 0000 38
0 0 0 0 0 0000 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03)Page 403.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End ofAvista Corporation X 04/15/2021 2020/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
2 Type of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was Installed
0.000.00 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
00 6 Net Peak Demand on Plant - MW (60 minutes)
00 7 Plant Hours Connected to Load
00 8 Net Continuous Plant Capability (Megawatts)
00 9 When Not Limited by Condenser Water
00 10 When Limited by Condenser Water
00 11 Average Number of Employees
00 12 Net Generation, Exclusive of Plant Use - KWh
00 13 Cost of Plant: Land and Land Rights
00 14 Structures and Improvements
00 15 Equipment Costs
00 16 Asset Retirement Costs
00 17 Total Cost
00 18 Cost per KW of Installed Capacity (line 17/5) Including
00 19 Production Expenses: Oper, Supv, & Engr
00 20 Fuel
00 21 Coolants and Water (Nuclear Plants Only)
00 22 Steam Expenses
00 23 Steam From Other Sources
00 24 Steam Transferred (Cr)
00 25 Electric Expenses
00 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
00 29 Maintenance Supervision and Engineering
00 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
00 32 Maintenance of Electric Plant
00 33 Maintenance of Misc Steam (or Nuclear) Plant
00 34 Total Production Expenses
0.00000.0000 35 Expenses per Net KWh
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
0 0 0 0 0 0 38 Quantity (Units) of Fuel Burned
0 0 0 0 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
0.000 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
0.000 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
0.000 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.000 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
0.000 0.000 0.000 0.000 0.000 0.000 44 Average BTU per KWh Net Generation
FERC FORM NO. 1 (REV. 12-03)Page 402.3
9. Items under Cost of Plant are based on U. S. of A. Accounts. Production expenses do not include Purchased Power, System Control and Load
Dispatching, and Other Expenses Classified as Other Power Supply Expenses. 10. For IC and GT plants, report Operating Expenses, Account Nos.
547 and 549 on Line 25 "Electric Expenses," and Maintenance Account Nos. 553 and 554 on Line 32, "Maintenance of Electric Plant." Indicate plants
designed for peak load service. Designate automatically operated plants. 11. For a plant equipped with combinations of fossil fuel steam, nuclear
steam, hydro, internal combustion or gas-turbine equipment, report each as a separate plant. However, if a gas-turbine unit functions in a combined cycle
operation with a conventional steam unit, include the gas-turbine with the steam plant. 12. If a nuclear power generating plant, briefly explain by
footnote (a) accounting method for cost of power generated including any excess costs attributed to research and development; (b) types of cost units
used for the various components of fuel cost; and (c) any other informative data concerning plant type fuel used, fuel enrichment type and quantity for the
report period and other physical and operating characteristics of plant.
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(e) (f)
Plant
Name:
Plant
Name:
(d)
Plant
Name:
(Continued)
1
2
3
4
0.000.00 0.00 5
00 0 6
00 0 7
00 0 8
00 0 9
00 0 10
00 0 11
00 0 12
00 0 13
00 0 14
00 0 15
00 0 16
00 0 17
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00 0 20
00 0 21
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00 0 32
00 0 33
00 0 34
0.00000.0000 0.0000 35
36
37
0 0 0 0 0 0000 38
0 0 0 0 0 0000 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03)Page 403.3
Schedule Page: 402 Line No.: -1 Column: b
Operated by Portland General Electric.
Schedule Page: 402 Line No.: -1 Column: c
Designed for peak load service
Schedule Page: 403 Line No.: -1 Column: e
Jointly owned project operated by Talen Montana LLC.
Schedule Page: 403 Line No.: -1 Column: f
Designed for peak load service
Schedule Page: 402.1 Line No.: -1 Column: b
Designed for peak load service
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2021
Year/Period of Report
2020/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
This Page Intentionally Left Blank
2545
Upper Falls
2545
Monroe Street
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Run-of-River Run-of-River
Plant Construction type (Conventional or Outdoor) 2 Conventional Conventional
Year Originally Constructed 3 1890 1922
Year Last Unit was Installed 4 1992 1922
Total installed cap (Gen name plate Rating in MW) 5 14.80 10.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 15 11
Plant Hours Connect to Load 7 7,440 8,760
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 15 10
(b) Under the Most Adverse Oper Conditions 10 15 10
Average Number of Employees 11 4 4
Net Generation, Exclusive of Plant Use - Kwh 12 83,100,000 58,141,000
Cost of Plant 13
Land and Land Rights 14 51,600 1,081,854
Structures and Improvements 15 12,114,919 1,082,308
Reservoirs, Dams, and Waterways 16 9,972,020 7,728,573
Equipment Costs 17 14,506,197 5,569,698
Roads, Railroads, and Bridges 18 50,448 508,242
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 36,695,184 15,970,675
Cost per KW of Installed Capacity (line 20 / 5) 21 2,479.4043 1,597.0675
Production Expenses 22
Operation Supervision and Engineering 23 4,943 2,343
Water for Power 24 0 0
Hydraulic Expenses 25 991 975
Electric Expenses 26 513,228 486,287
Misc Hydraulic Power Generation Expenses 27 15,259 18,629
Rents 28 0 0
Maintenance Supervision and Engineering 29 17,377 5,228
Maintenance of Structures 30 1,861 51,218
Maintenance of Reservoirs, Dams, and Waterways 31 22,638 6,701
Maintenance of Electric Plant 32 97,440 43,109
Maintenance of Misc Hydraulic Plant 33 4,446 20,223
Total Production Expenses (total 23 thru 33) 34 678,183 634,713
Expenses per net KWh 35 0.0082 0.0109
FERC FORM NO. 1 (REV. 12-03)Page 406
2545
Nine Mile Falls Cabinet Gorge
2058
Post Falls
2545
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Storage StorageRun-of-River 1
Conventional OutdoorConventional 2
1906 19521908 3
1980 19531994 4
14.80 265.0037.60 5
16 25828 6
7,203 5,9526,863 7
8
18 25538 9
18 29538 10
5 25 11
77,008,000 1,002,706,000117,927,000 12
13
4,161,522 16,380,17833,429 14
4,403,016 24,009,67420,040,785 15
25,932,396 44,638,42130,903,663 16
5,014,893 65,347,79660,751,179 17
577,944 1,671,013594,870 18
0 00 19
40,089,771 152,047,082112,323,926 20
2,708.7683 573.76262,987.3385 21
22
20,391 62,4158,322 23
0 90 24
3,309 3,932428 25
638,156 1,127,312671,901 26
78,666 194,050192,719 27
0 00 28
12,693 26,7074,188 29
30,389 1,376,77428,757 30
55,167 58,35810,028 31
152,085 995,943180,660 32
16,807 41,3035,962 33
1,007,663 3,886,8031,102,965 34
0.0131 0.00390.0094 35
FERC FORM NO. 1 (REV. 12-03)Page 407
2545
Long Lake
2058
Noxon Rapids
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Storage Storage
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1959 1915
Year Last Unit was Installed 4 1977 1924
Total installed cap (Gen name plate Rating in MW) 5 487.80 71.10
Net Peak Demand on Plant-Megawatts (60 minutes) 6 541 92
Plant Hours Connect to Load 7 4,901 6,566
Net Plant Capability (in megawatts) 8
(a) Under Most Favorable Oper Conditions 9 581 90
(b) Under the Most Adverse Oper Conditions 10 623 90
Average Number of Employees 11 11 1
Net Generation, Exclusive of Plant Use - Kwh 12 1,596,412,000 502,673,000
Cost of Plant 13
Land and Land Rights 14 36,130,081 2,500,473
Structures and Improvements 15 24,705,239 9,378,027
Reservoirs, Dams, and Waterways 16 36,033,151 36,757,010
Equipment Costs 17 111,695,555 13,487,799
Roads, Railroads, and Bridges 18 259,750 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 208,823,776 62,123,309
Cost per KW of Installed Capacity (line 20 / 5) 21 428.0930 873.7456
Production Expenses 22
Operation Supervision and Engineering 23 137,155 8,645
Water for Power 24 0 0
Hydraulic Expenses 25 68,375 6,219
Electric Expenses 26 930,495 691,502
Misc Hydraulic Power Generation Expenses 27 197,349 146,203
Rents 28 0 0
Maintenance Supervision and Engineering 29 16,726 3,543
Maintenance of Structures 30 135,807 120,318
Maintenance of Reservoirs, Dams, and Waterways 31 116,773 10,777
Maintenance of Electric Plant 32 482,523 301,786
Maintenance of Misc Hydraulic Plant 33 89,721 26,684
Total Production Expenses (total 23 thru 33) 34 2,174,924 1,315,677
Expenses per net KWh 35 0.0014 0.0026
FERC FORM NO. 1 (REV. 12-03)Page 406.1
2545
Little Falls
0 0
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
FERC Licensed Project No.
(e)(d)(f)
Plant Name:
FERC Licensed Project No.
Plant Name:
FERC Licensed Project No.
Plant Name:
Line
No.
5. The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6. Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
Run-of-River 1
Conventional 2
1910 3
1911 4
0.00 0.0043.20 5
0 044 6
0 06,566 7
8
0 043 9
0 043 10
0 01 11
0 0212,533,000 12
13
0 04,325,371 14
0 04,242,067 15
0 06,434,060 16
0 053,518,018 17
0 00 18
0 00 19
0 068,519,516 20
0.0000 0.00001,586.0999 21
22
0 02,978 23
0 00 24
0 06,173 25
0 0580,733 26
0 076,190 27
0 01,035,399 28
0 011,228 29
0 0136,724 30
0 037,630 31
0 0207,812 32
0 040,152 33
0 02,135,019 34
0.0000 0.00000.0100 35
FERC FORM NO. 1 (REV. 12-03)Page 407.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Name of Plant
Installed Capacity
(c)(b)(a)
Cost of PlantNet PeakDemand
(d)
YearOrig.Const.Name Plate Rating
(In MW)MW(60 min.)
Net GenerationExcludingPlant Use
(e)(f)
1. Small generating plants are steam plants of, less than 25,000 Kw; internal combustion and gas turbine-plants, conventional hydro plants and pumped
storage plants of less than 10,000 Kw installed capacity (name plate rating). 2. Designate any plant leased from others, operated under a license from
the Federal Energy Regulatory Commission, or operated as a joint facility, and give a concise statement of the facts in a footnote. If licensed project, give
project number in footnote.
7.20 10.0 1,235,000 9,567,5002002Kettle Falls CT 1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 410
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
GENERATING PLANT STATISTICS (Small Plants) (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.(i)(h)(g)(j) (k) (l)
Operation
Exc'l. Fuel
Production Expenses
Fuel Maintenance Kind of Fuel Fuel Costs (in cents
(per Million Btu)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl AssetRetire. Costs) Per MW
199 9,434 27,210 1,323,903 1Nat Gas 90,581
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
FERC FORM NO. 1 (REV. 12-03) Page 411
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
60.00 60.00 1.00 1 Group Sum
2
115.00 115.00 1,564.00 3 Group Sum
4
Steel Pole 230.00 230.00 1.00 1 5 Beacon Sub #4 BPA Bell Sub
H Type 230.00 230.00 5.00 1 6 Beacon Sub #4 BPA Bell Sub
Steel Tower 230.00 230.00 3.00 1 7 Beacon Sub #5 BPA Bell Sub
H Type 230.00 230.00 3.00 1 8 Beacon Sub #5 BPA Bell Sub
Steel Tower 230.00 230.00 1.00 1 9 Beacon Cabinet Gorge Plant
Steel Pole 230.00 230.00 41.00 2 10 Beacon Cabinet Gorge Plant
H Type 230.00 230.00 53.00 1 11 Beacon Cabinet Gorge Plant
Steel Tower 230.00 230.00 1.00 1 12 Beacon Sub Lolo Sub
Steel Pole 230.00 230.00 37.00 2 13 Beacon Sub Lolo Sub
H Type 230.00 230.00 62.00 1 14 Beacon Sub Lolo Sub
H Type 230.00 230.00 8.00 1 15 Beacon Sub Lolo Sub
Steel Pole 230.00 230.00 1.00 1 16 Benewah Shawnee
Steel Pole 230.00 230.00 59.00 1 17 Benewah Shawnee
Steel Pole 230.00 230.00 29.00 1 18 Noxon Plant Pine Creek Sub
H Type 230.00 230.00 1.00 1 19 Noxon Plant Pine Creek Sub
H Type 230.00 230.00 14.00 1 20 Noxon Plant Pine Creek Sub
H Type 230.00 230.00 2.00 1 21 Cabinet Gorge Plant Noxon
H Type 230.00 230.00 17.00 1 22 Cabinet Gorge Plant Noxon
H Type 230.00 230.00 43.00 1 23 Benewah Sw. Station Pine Creek Sub
H Type 230.00 230.00 43.00 1 24 Divide Creek Lolo Sub
H Type 230.00 230.00 39.00 1 25 N. Lewiston Walla Walla
H Type 230.00 230.00 4.00 1 26 N. Lewiston Walla Walla
Steel Pole 230.00 230.00 4.00 1 27 N. Lewiston Walla Walla
Steel Pole 230.00 230.00 7.00 1 28 N. Lewiston Shawnee
H Type 230.00 230.00 27.00 1 29 N. Lewiston Shawnee
Steel Pole 230.00 230.00 2.00 1 30 Saddle Mtn-Walla Walla Wanapum
H Type 230.00 230.00 79.00 1 31 Saddle Mtn-Walla Walla Wanapum
Steel Tower 230.00 230.00 1.00 1 32 BPA (Libby)Noxon Plant
Steel Tower 230.00 230.00 1.00 1 33 BPA/Hot Springs #1 Noxon Plant
Steel Pole 230.00 230.00 2.00 1 34 BPA/Hot Springs #2 Noxon Plant
H Type 230.00 230.00 68.00 1 35 BPA/Hot Springs #2 Noxon Plant
FERC FORM NO. 1 (ED. 12-87) Page 422
36 TOTAL 2,253.00 1.00 39
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
772,231 636,193 136,038 1
2
287,172,620 274,811,363 12,361,257 1,415,173 693,722 721,451 3
4
1272 ACSS 5
1,447,3331272 ACSS 1,429,421 17,912 5,634 5,634 6
1272 ACSS 7
3,305,6801272 ACSS 3,275,357 30,323 10,145 888 9,257 8
1590 ACSS 9
1590 ACSS 10
42,936,9781590 ACSR 41,780,782 1,156,196 26,542 17,540 9,002 11
1590 ACSS 12
1590 ACSS 13
1272 AAC 14
23,429,8321272 ACSS 22,973,670 456,162 31,230 6,105 25,125 15
1622 ACSS 16
49,318,9401590 ACSS 48,748,733 570,207 3,373 2,740 633 17
1272 ACSR 18
1590 ACSS 19
20,248,253954 AAC 19,150,574 1,097,679 265,624 244,468 21,156 20
795 ACSR 21
2,107,289954 AAC 1,923,078 184,211 78,664 55,732 22,932 22
5,610,140954 AAC 5,222,681 387,459 17,441 17,441 23
7,256,8361272 AAC 7,091,503 165,333 48,844 46,745 2,099 24
1272 AAC 25
1272 ACSR 26
7,354,5431272 ACSR 6,730,559 623,984 27
1272 ACSR 28
10,915,5311272 ACSR 10,043,381 872,150 29
1590 ACSS 30
14,253,9391272 AAC 14,004,803 249,136 31
1272 ACSR 32
19,5211272 ACSR 19,521 9,650 9,650 33
1272 ACSR 34
13,672,3591272 AAC 10,069,035 3,603,324 55,887 24,864 31,023 35
FERC FORM NO. 1 (ED. 12-87) Page 423
36 22,912,609 510,288,801 533,201,410 943,470 1,243,798 87,681 2,274,949
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(c)(b)(a)(d)(e)
DESIGNATION
From To
(f)(g)
VOLTAGE (KV)(Indicate whereother than60 cycle, 3 phase)
Operating Designed
Type of
Supporting
Structure
LENGTH (Pole miles)(In the case of underground linesreport circuit miles)
On Structureof LineDesignated
On Structuresof AnotherLine
Number
Of
Circuits
(h)
1. Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2. Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3. Report data by individual lines for all voltages if so required by a State commission.
4. Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5. Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction by
the use of brackets and extra lines. Minor portions of a transmission line of a different type of construction need not be distinguished from the remainder
of the line.
6. Report in columns (f) and (g) the total pole miles of each transmission line. Show in column (f) the pole miles of line on structures the cost of which is
reported for the line designated; conversely, show in column (g) the pole miles of line on structures the cost of which is reported for another line. Report
pole miles of line on leased or partly owned structures in column (g). In a footnote, explain the basis of such occupancy and state whether expenses with
respect to such structures are included in the expenses reported for the line designated.
Steel Pole 230.00 230.00 2.00 2 1 Coulee West Side Sub
Steel Pole 230.00 230.00 2.00 2 2 BPA Line West Side Sub
H Type 230.00 230.00 7.00 1 3 Hatwai N. Lewiston Sub
H Type 230.00 230.00 20.00 1 4 Divide Creek Imnaha
500.00 500.00 5 Colstrip Plant Broadview
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 422.1
36 TOTAL 2,253.00 1.00 39
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINE STATISTICS (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
COST OF LINE (Include in Column (j) Land,
Size of
Conductor
and Material
Land rights, and clearing right-of-way)EXPENSES, EXCEPT DEPRECIATION AND TAXES
OperationExpenses Maintenance Rents TotalLand Construction andOther Costs Total Cost
(i)(j)(k)(l)(m)(n)(o)(p)Expenses Expenses
7. Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. If two or more transmission line structures support lines of the same voltage, report the
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g)
8. Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company,
give name of lessor, date and terms of Lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which
the respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the
arrangement and giving particulars (details) of such matters as percent ownership by respondent in the line, name of co-owner, basis of sharing expenses
of the Line, and how the expenses borne by the respondent are accounted for, and accounts affected. Specify whether lessor, co-owner, or other party is
an associated company.
9. Designate any transmission line leased to another company and give name of Lessee, date and terms of lease, annual rent for year, and how
determined. Specify whether lessee is an associated company.
10. Base the plant cost figures called for in columns (j) to (l) on the book cost at end of year.
8,4821272 ACSR 8,482 1
630,5931272 ACSR 594,132 36,461 2
2,771,3971590 ACSR 2,616,153 155,244 2,872 159 2,713 3
1,517,4861272 AAC 1,312,224 205,262 16,588 16,588 4
38,451,427 37,855,638 595,789 287,282 87,681 101,522 98,079 5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
FERC FORM NO. 1 (ED. 12-87) Page 423.1
36 22,912,609 510,288,801 533,201,410 943,470 1,243,798 87,681 2,274,949
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(c)(b)(a) (d) (e)
LINE DESIGNATION
From To
LineLengthinMiles
SUPPORTING STRUCTURE
Type AverageNumber perMiles
CIRCUITS PER STRUCTURE
Present Ultimate
(f)(g)
1. Report below the information called for concerning Transmission lines added or altered during the year. It is not necessary to report
minor revisions of lines.
2. Provide separate subheadings for overhead and under- ground construction and show each transmission line separately. If actual
costs of competed construction are not readily available for reporting columns (l) to (o), it is permissible to report in these columns the
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
FERC FORM NO. 1 (REV. 12-03)Page 424
44 TOTAL
Total
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSMISSION LINES ADDED DURING YEAR (Continued)
Avista Corporation X 04/15/2021 2020/Q4
Line
No.
(k)(j)(h) (l) (m)
CONDUCTORS
Size Configuration
Voltage
KV
LINE COST
Land and Poles, Towers
and Fixtures Conductors
(n)(p)
Specification and Spacing (Operating)Land Rights and Devices(i)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (l) with appropriate footnote, and costs of Underground Conduit in column (m).
3. If design voltage differs from operating voltage, indicate such fact by footnote; also where line is other than 60 cycle, 3 phase, indicate
such other characteristic.
Asset
(o)Retire. Costs
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
FERC FORM NO. 1 (REV. 12-03)Page 425
44
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
STATE OF WASHINGTON 1
Airway Heights 13.80 115.00Distr. Unattended 2
Barker Road 13.80 115.00Distr. Unattended 3
Beacon 115.00 230.00 13.80Trnsm. & Distr Unatt 4
Boulder 115.00 230.00 13.80Trnsm. & Distr Unatt 5
Chester 13.80 115.00Distr. Unattended 6
Chewelah 115Kv 13.20 115.00Distr. Unattended 7
Colbert 13.80 115.00Distr. Unattended 8
College & Walnut 13.80 115.00Distr. Unattended 9
Colville 115Kv 13.80 115.00Distr. Unattended 10
Critchfield 13.80 115.00Distr. Unattended 11
Deer Park 13.80 115.00Dist. Unattended 12
Dry Creek 115.00 230.00 13.80Transm. Unattended 13
Dry Gulch 13.80 115.00Distr. Unattended 14
East Colfax 13.80 115.00Distr. Unattended 15
East Farms 13.80 115.00Distr. Unattended 16
Fort Wright 13.80 115.00Distr. Unattended 17
Francis and Cedar 13.80 115.00Distr. Unattended 18
Gifford 34.00 115.00Distr. Unattended 19
Glenrose 13.80 115.00Distr. Unattended 20
Greenacres 13.80 115.00Distr. Unattended 21
Greenwood 13.80 115.00Distr. Unattended 22
Hallett & White 13.80 115.00Distr. Unattended 23
Indian Trail 13.80 115.00Dist. Unattended 24
Industrial Park 13.80 115.00Dist. Unattended 25
Kettle Falls 13.80 115.00Distr. Unattended 26
Lee & Reynolds 13.80 115.00Distr. Unattended 27
Liberty Lake 13.80 115.00Distr. Unattended 28
Lind 13.80 115.00Dist. Unattended 29
Little Falls 115/34Kv 34.00 115.00Distr. Unattended 30
Lyons & Standard 13.80 115.00Distr. Unattended 31
Mead 13.80 115.00Distr. Unattended 32
Metro 13.80 115.00Distr. Unattended 33
Milan 13.80 115.00Distr. Unattended 34
Millwood 13.80 115.00Dist. Unattended 35
Ninth & Central 13.80 115.00Dist. Unattended 36
Northeast 13.80 115.00Distr. Unattended 37
Northwest 13.80 115.00Distr. Unattended 38
Opportunity 13.80 115.00Dist. Unattended 39
Othello 13.80 115.00Distr. Unattended 40
FERC FORM NO. 1 (ED. 12-96) Page 426
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i)(j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
1
24 2 40 39Frcd Oil&Air Fan&Cap 2
12 1 201Two Stage Fan 3
536 4 5602Two Stage Fan 4
318 3 5303Two Stage Fan 5
24 2 402Frcd Oil & Air Fan 6
12 1 201Two Stage Fan 7
12 1 20 16Frcd Oil&Air Fan&Cap 8
36 2 602Two Stage Fan 9
32 3 493Frcd Oil & Air Fan 10
12 1 201Two Stage Fan 11
12 1 201Two Stage Fan 12
150 1 250 223Two Stage Fan & Caps 13
12 1 201Frcd Oil & Air Fan 14
12 1 201FrOil/Air Fan 15
12 1 201Two Stage Fan 16
24 2 402Fr Oil/Air/2StgFan 17
36 2 602Two Stage Fan 18
16 2 171One Stage Fan 19
12 1 201Frcd Oil & Air Fan 20
18 1 301Two Stage Fan 21
12 1 201Two Stage Fan 22
36 2 602Two Stage Fan 23
12 1 201Two Stage Fan 24
24 2 40 14Two Stg/Frcd Oil&Cap 25
12 1 201Frcd Oil & Air Fan 26
36 2 602Two Stage Fan 27
24 2 402Two Stage Fan 28
12 1 201Two Stage Fan 29
12 1 30
36 2 602Two Stage Fan 31
18 1 301Two Stage Fan 32
24 2 402Two Stage Fan 33
24 2 402Frcd Oil & Air Fan 34
24 2 402Two Stage Fan 35
36 2 602Two Stage Fan 36
24 2 402Two Stage Fan 37
24 2 402Two Stage Fan 38
12 1 201Two Stage Fan 39
24 2 402FrOil/AirFan/2StgFn 40
FERC FORM NO. 1 (ED. 12-96)Page 427
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Post Street 13.80 115.00Distr. Unattended 1
Pound Lane 13.80 115.00Distr. Unattended 2
Ross Park 13.80 115.00Distr. Unattended 3
Roxboro 24.00 115.00Distr. Unattended 4
Saddle Mountain 115.00 230.00 13.80Trans. Unattended 5
Shawnee 115.00 230.00 13.80Trans. Unattended 6
Silver Lake 13.80 115.00Distr. Unattended 7
Southeast 13.80 115.00Distr. Unattended 8
South Othello 13.80 115.00Distr. Unattended 9
South Pullman 13.80 115.00Distr. Unattended 10
Sunset 13.80 115.00Distr. Unattended 11
Terre View 13.80 115.00Distr. Unattended 12
Third & Hatch 13.80 115.00Distr. Unattended 13
Turner 13.80 115.00Distr. Unattended 14
Waikiki 13.80 115.00Distr. Unattended 15
West Side 115.00 230.00 13.80Trans. Unattended 16
Other: 27 substations less than 10MVA Distr. Unattended 17
18
STATE OF IDAHO 19
Appleway 13.80 115.00Dist. Unattended 20
Avondale 13.80 115.00Dist. Unattended 21
Benewah 115.00 230.00 13.80Trans. Unattended 22
Big Creek 13.80 115.00Distr. Unattended 23
Blue Creek 13.80 115.00Distr. Unattended 24
Bunker Hill Limited 13.80 115.00Distr. Unattended 25
Cabinet Gorge (Switchyard) 115.00 230.00 13.80Trans. Unattended 26
Clark Fork 21.80 115.00Distr. Unattended 27
Coeur d'Alene 15th Ave 13.80 115.00Distr. Unattended 28
Cottonwood 24.90 115.00Distr. Unattended 29
Dalton 13.80 115.00Distr. Unattended 30
Grangeville 13.80 115.00Distr. Unattended 31
Holbrook 13.80 115.00Distr. Unattended 32
Huetter 13.80 115.00Distr. Unattended 33
Idaho Road 13.80 115.00Distr Unattended 34
Juliaetta 13.80 115.00Distr. Unattended 35
Kamiah 13.80 115.00Dist. Unattended 36
Kooskia 13.80 115.00Distr. Unattended 37
Lewiston Mill Rd 13.20 115.00Distr. Unattended 38
Lolo 115.00 230.00 13.80Tran & Dist Unattnd 39
Moscow 13.80 115.00Distr. Unattended 40
FERC FORM NO. 1 (ED. 12-96) Page 426.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i)(j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
36 2 602Frcd Oil 1
24 2 402Two Stage Fan 2
33 2 572Two Stage Fan 3
24 2 402Two Stage Fan 4
150 1 2501Two Stage Fan 5
150 1 2501Two Stage Fan 6
12 1 201Two Stage Fan 7
36 2 602Two Stage Fan 8
12 1 201Two Stage Fan 9
30 2 502Two Stage Fan 10
33 2 55 50Two Stage Fan & Caps 11
12 1 201Two Stage Fan 12
54 3 90 103Two Stg Fan & Cap 13
36 2 602Two Stg Fan 14
24 2 402Two Stage Fan 15
300 2 5002Two Stage Fan 16
164 28 17
18
19
36 2 602Two Stage Fan 20
12 1 201Two Stage Fan 21
75 1 125 223Two Stage Fan & Caps 22
18 2 222Portable Fan 23
12 1 201Two Stage Fan 24
12 1 161Frcd Air Fan 25
75 1 1251Two Stage Fan 26
10 1 131Frcd Air Fan 27
36 2 602Two Stage Fan 28
12 1 201Two Stage Fan 29
36 2 602Two Stage Fan 30
25 4 34 17FrcdOil/Air/Pt Fan&C 31
12 1 201Two Stage Fan 32
12 1 201Two Stage Fan 33
12 1 201Two Stage Fan 34
12 1 201Frcd Oil & Air Fan 35
12 1 201Two Stage Fan 36
15 3 203Frcd Air Fan 37
18 1 301Two Stage Fan 38
262 3 2701Frcd Oil/Air/Two Stg 39
24 2 402FrOil/Air/2Stg Fan 40
FERC FORM NO. 1 (ED. 12-96)Page 427.1
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Moscow 230Kv 115.00 230.00 13.80Tran & Dist Unattnd 1
North Lewiston 230kV 115.00 230.00 13.80Tran & Dist Unattnd 2
North Moscow 13.80 115.00Distr. Unattended 3
Oden 21.80 115.00Distr. Unattended 4
Oldtown 21.80 115.00Distr. Unattended 5
Orofino 24.00 115.00Distr. Unattended 6
Osburn 13.80 115.00Distr. Unattended 7
Pine Creek 115.00 230.00 13.80Tran & Dist Unattnd 8
Pleasant View 13.80 115.00Distr. Unattended 9
Plummer 13.80 115.00Dist Unattended 10
Post Falls 13.80 115.00Distr. Unattended 11
Potlatch 24.90 115.00Distr. Unattended 12
Prarie 13.80 115.00Distr. Unattended 13
Priest River 20.80 115.00Distr. Unattended 14
Rathdrum 115.00 230.00 13.80Trans & Distr Unattd 15
Sagle 21.80 115.00Dist. Unattended 16
Sandpoint 20.80 115.00Distr. Unattended 17
South Lewiston 13.80 115.00Distr. Unattended 18
Sweetwater 24.90 115.00Distr. Unattended 19
St. Maries 23.90 115.00Distr. Unattended 20
Tenth & Stewart 13.80 115.00Distr. Unattended 21
22
Other: 13 substations less than 10 MVA Distr. Unattended 23
24
STATE OF MONTANA 25
Other: 1 substation less than 10 MVA Distr. Unattended 26
27
SUBSTA. @ GENERATING PLANTS 28
STATE OF WASHINGTON 29
Boulder Park 13.80 115.00Trans. Attended 30
Kettle Falls 13.80 115.00Trans. Attended 31
Long Lake 4.00 115.00Trans. Attended 32
Nine Mile 13.80 115.00Trans. Attended 33
Little Falls 4.00 115.00Trans. Attended 34
Northeast 13.80 115.00Trans. Attended 35
Post Street 4.00 13.80Trans. Attended 36
37
STATE OF IDAHO 38
Cabinet Gorge (HED) 13.80 230.00Trans. Attended 39
Post Falls 2.30 115.00Trans. Attended 40
FERC FORM NO. 1 (ED. 12-96) Page 426.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i)(j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
162 2 270 76Frcd Air Fan & Caps 1
258 2 260 48Frcd Air Fan & Caps 2
12 1 201Two Stage Fan 3
10 1 131Frcd Air Fan 4
18 2 222Frcd Air Fan 5
20 2 281Frcd Oil & Air Fan 6
12 1 151Portable Fan 7
212 3 270 45Two Stg Fan/Capacito 8
12 1 201Two Stage Fan 9
12 1 201Two Stage Fan 10
18 1 301Two Stage Fan 11
15 2 192Portable Fan 12
12 1 201Frcd Oil & Air Fan 13
10 1 131Frcd Air Fan 14
474 4 490 50Frcd Oil & Air Fan 15
12 1 201Two Stage Fan 16
30 3 383Frcd Air Fan 17
27 4 394Port Fan/FrcdOil/Air 18
12 1 201Frcd Oil & Air Fan 19
24 2 402Two Stage Fan 20
30 2 502Frcd Oil/Air/Two Stg 21
22
73 13 23
24
25
5 1 26
27
28
29
36 1 601Two Stage Fan 30
34 1 1 621Two Stage Fan 31
80 4 1 32
42 2 561Two Stage Fan 33
24 2 402Frcd Oil & Air Fan 34
36 1 601Two Stage Fan 35
35 2 36
37
38
300 6 1 39
16 2 212Frcd Air/Oil/Air Fan 40
FERC FORM NO. 1 (ED. 12-96)Page 427.2
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
Rathdrum 13.80 115.00Trans. Attended 1
2
STATE OF MONTANA 3
Noxon 13.80 230.00Trans. Attended 4
5
STATE OF OREGON 6
Coyote Springs II 13.80 500.00 18.00Trans. Attended 7
8
SUMMARY: 9
Washington: 4 subs Trans. Unattended 10
76 subs Distr. Unattended 11
2 subs Tran & Dist Unattnd 12
7 subs Trans. Attended 13
Idaho 2 subs Trans. Unattended 14
48 subs Distr. Unattended 15
5 subs Tran & Dist Unattnd 16
3 subs Trans. Attended 17
Montana: 1 sub Trans. Attended 18
1 sub Distr. Unattended 19
Oregon: 1 sub Trans. Unattended 20
Total System: 150 subs 2927.90 14543.80 197.40 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
SUBSTATIONS
Avista Corporation X 04/15/2021 2020/Q4
Line
No.Number of Units
(g)(f) (h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT
(k)
Total Capacity
(Continued)
Capacity of Substation
(In Service) (In MVa)
Number ofTransformersIn Service Spare Type of Equipment
Number of
Transformers (In MVa)(i)(j)
5. Show in columns (I), (j), and (k) special equipment such as rotary converters, rectifiers, condensers, etc. and auxiliary equipment for
increasing capacity.
6. Designate substations or major items of equipment leased from others, jointly owned with others, or operated otherwise than by
reason of sole ownership by the respondent. For any substation or equipment operated under lease, give name of lessor, date and
period of lease, and annual rent. For any substation or equipment operated other than by reason of sole ownership or lease, give name
of co-owner or other party, explain basis of sharing expenses or other accounting between the parties, and state amounts and accounts
affected in respondent's books of account. Specify in each case whether lessor, co-owner, or other party is an associated company.
114 2 1 1902Two Stage Fan 1
2
3
435 9 1 6356Two Stage Fan 4
5
6
213 1 3551Two Stage fan 7
8
9
750 10
1274 11
854 12
287 13
150 14
683 15
1368 16
430 17
435 18
5 19
213 20
12900 238 5 8,389 1050 21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
Avista Corporation X 04/15/2021 2020/Q4
Line
No. Description of the Non-Power Good or Service
Name of
(c)(b)(a)(d)
Associated/AffiliatedCompany
AccountCharged orCredited
Amount
Credited
1. Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2. The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed toan associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should notattempt to include or aggregate amounts in a nonspecific category such as "general".3. Where amounts billed to or received from the associated (affiliated) company are based on an allocation process, explain in a footnote.
Charged or
1 Non-power Goods or Services Provided by Affiliated
2 Other 155,496Steam Plant Square 931000
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 243,657Salix Inc.146000
22 Corporate Support 157,414Avista Development 146000
23 Corporate Support 75,581Avista Capital 146000
24 Corporate Support 23,967AELP 146000
25 Corporate Support 2,753AJT Mining 146000
26 Corporate Support 155,000Steam Plant Square 146000
27 Corporate Support 350,426Avista Edge 146000
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (New)Page 429
FERC FORM NO. 1-F (New)

Avista Corp.

2020

IDAHO

State Electric Annual Report

(IC 61-405)

This Page Intentionally Left Blank
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
1.
2.
Line Refer to
No.Form 1
Page
(b)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400)300-301
3 Operating Expenses
4 Operation Expenses (401)320-323
5 Maintenance Expenses (402)320-323
6 Depreciation Expense (403)336-337
7 Depreciation Expense for Asset Retirement Costs (403.1)336-337
8 mortization & Depletion of Utilit Plant 404-405 336-337
9 Amortization of Utility Plant Acquisition Adjustment (406)336-337
10 Amort. of Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11 Amortization of Conversion Expenses (407)
12 Regulatory Debits (407.3)
13 (Less) Regulatory Credits (407.4)
14 Taxes Other Than Income Taxes (408.1)262-263
15 Income Taxes - Federal (409.1)262-263
16 - Other (409.1)262-263
17 Provision for Deferred Income Taxes 410.1 234, 272-277
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1)234, 272-277
19 Investment Tax Credit Adjustment - Net (411.4)266
20 (Less) Gains from Disposition of Utility Plant (411.6)
21 Losses from Disposition Of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8)
23 Losses from Disposition of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utility Operating Expenses (Total of line 4 through 24)
26 Net Utility Operating Income (Total line 2 less 25)75,423,724
-
-
335,243,213
-
6,046,073
-
(170,725)
-
-
2,803,455
(8,396,725)
18,930,820
4,413,421
STATEMENT OF UTILITY OPERATING INCOME - IDAHO
2020 / Q4
For each account below, report the amount attributable to the state of Idaho based on Idaho jurisdictional Results of Operations.
04/15/2021
Provide any necessary important notes regarding this statement of utility operating income in a footnote in the available space at the bottom of this
TOTAL SYSTEM - IDAHO
Account
327,882,920
73,591,907
-
(168,096)
-
-
-
(12,771,604)
21,042,881
1,579,230
-
6,241,945
(a)
Current Year Prior Year
(d)
401,474,827
222,680,326
22,558,272
52,013,390
-
(c)
-
-
9,690,048
(333,312)
-
410,666,937
229,746,234
22,442,747
-
-
11,408,775
67,304
-
-
3,230,497
-
50,071,177
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.114-115
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
page or in a separate schedule.
3.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
-
-
77,526,728
14,282,301
2,428,152
-
(4,152)
-
-
-
-
-
-
1,765,552
-
-
-
-
-
-
88,318,789
55,714,297
2,876,871
7,947,311
393,735
(222,432)
3,034,377
(362,781)
59,380,194
3,469,855
7,644,228
2,048,489
-
91,809,029
61,141,423
3,617,921
-
(166,573)
-
-
14,279,898
2,498,422
-
(1,038)
74,038,891 253,844,029
2,409,720
(8,174,293)
15,896,443
4,776,202
-
-
7,924,496
(333,312)
-
-
-
-
-
257,716,485
59,312,009
3,743,523
(167,058)
313,156,038
166,966,029
19,681,401
44,066,079
9,360,286
67,304
2,425,018
(12,327,802)
17,626,332
2,402,917
2020 / Q4
STATEMENT OF UTILITY OPERATING INCOME - IDAHO
Explain in a footnote if the previous year's figures are different from those reported in prior reports.
04/15/2021
GAS UTILITY
Current Year Prior Year
ELECTRIC UTILITY
Current Year Prior Year
(e)(f)
OTHER UTILITY
Current Year Prior Year
(i)(j)
318,857,908
170,366,040
18,972,892
42,426,949
(g)(h)
805,479
(443,802)
3,416,549
(823,687)
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.114-115
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
1.
2.
Line
No.
1 Utility Plant
2 In Service
3 Plant in Service (Classified)
4 Property Under Capital Leases
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 Experimental Plant Unclassified
8 Total (Total lines 3 through 7)
9 Leased to Others
10 Held for Future Use
11 Construction Work in Progress
12 cquisition Ad ustments
13 Total Utility Plant (Total lines 8 through 12)
14 Accumulated Provision for Depreciation, Amortization, and Depletion
15 Net Utility Plant (Line 13 less line 14)
16 Detail of Accumulated Provision for Depreciation, Amortization, and Depletion
17 In Service
18 Depreciation
19 Amortization and Depletion of Producing Natural Gas Lands / Land Rights
20 Amortization of Underground Storage Lands / Land Rights
21 Amortization of Other Utility Plant
22 Total (Total lines 18 through 21)
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use
31 Abandonment of Leases (Natural Gas)
32 Amortization of Plant Acquisition Adjustment
33 Total Accumulated Provision (Total lines 22, 26, 30, 31, 32)
(1) A small portion of the Company's electric distribution plant is located in Montana. For jurisdictional reporting purposes, those amounts are
included as Idaho plant.
(2) Common Property Under Capital Lease is comprised of ROU Assets
748,745,320 582,560,104
- -
- -
- -
- -
748,745,320 582,560,104
42,575,538 8,229,965
-
-
- -
- -
- -
- -
706,169,782 574,330,139
1,345,586,408 998,512,772
748,745,320 582,560,104
2,094,331,728 1,581,072,876
-
55,129,303 49,431,352
1,614,766 1,424,181
-
2,037,587,659 1,530,217,343
-
Report in column (c) the amount for electric function, in column (d) the amount for gas function, in columns (e), (f), and (g) report other (specify),
accumulated provisions for depreciation, amortization, and depletion attributable to that plant in service.
-
-
24,173,936
2,013,413,723 1,530,217,343
Report below the original cost of utility plant in service necessary to furnish utility service to customers in the state of Idaho, and the
2020 / Q4
04/15/2021
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION - IDAHO
(a)(b)(c)
Account End of Current Year Electric
Total Company
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.200-201
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
3.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
- - - - -
99,683,748 - - - 66,501,468
- - - - -
99,683,748 - - - 66,501,468
146,061 34,199,512
99,537,687 32,301,956
99,683,748 - - - 66,501,468
195,410,361 - - - 151,663,275
295,094,109 - - - 218,164,743
190,585
683,990 5,013,961
294,219,534 - - - 213,150,782
Other (Specify)
(f)
Other (Specify)
(g)
Gas Other (Specify)
188,976,846
24,173,936
Common
(h)
plant not directly assigned is allocated to the state of Idaho as appropriate and included in column (c) and (d).
In order to accurately reflect utility plant in service necessary to furnish utility service to customers in the state of Idaho, electric and gas
294,219,534
and in column (h) common function.
2020 / Q4
04/15/2021
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION - IDAHO
(d)(e)
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.200-201
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
1.
2.
3.
4.
5.
6.
Line
No.
1 1. INTANGIBLE PLANT
2 301 Organization
3 302 Franchises and Consents
4 303 Miscellaneous Intangible Plant
5 TOTAL Intangible Plant (Total of lines 2, 3, and 4)
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 310 Land and Land Rights
9 311 Structures and Improvements
10 312 Boiler Plant Equipment
11 313 En ines and En ine-Driven Generators
12 314 Turbogenerator Units
13 315 Accessory Electric Equipment
14 316 Miscellaneous Power Plant Equipment
15 317 Asset Retirement Costs for Steam Production
16 TOTAL Steam Production Plant (Total of lines 8 through 15)
17 B. Nuclear Production Plant
18 320 Land and Land Rights
19 321 Structures and Improvements
20 322 Reactor Plant Equipment
21 323 Turbogenerator Units
22 324 Accessory Electric Equipment
23 325 Miscellaneous Power Plant Equipment
24 326 Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Total of lines 18 through 24)
26 C. Hydraulic Production Plant
27 330 Land and Land Rights
28 331 Structures and Improvements
29 332 Reservoirs, Dams, and Waterways
30 333 Water Wheels, Turbines, and Generators
31 334 Accessory Electric Equipment
32 335 Miscellaneous Power Plant Equipment
33 336 Roads, Railroads, and Bridges
34 337 Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Total of lines 27 through 34)
36 D. Other Production Plant
37 340 Land and Land Rights
38 341 Structures and Improvements
39 342 Fuel Holders, Products, and Accessories
40 343 Prime Movers
41 344 Generators
42 345 Accessory Electric Equipment
43 346 Miscellaneous Power Plant Equipment
44 347 Asset Retirement Costs for Other Production
45 TOTAL Other Production Plant (Total of lines 37 through 44)
46 TOTAL Production Plant (Total of lines 16, 25, 35, and 45)
(1) A small portion of the Company's electric distribution plant is located in Montana. For jurisdictional reporting purposes, those amounts are
included as Idaho plant.
80,457,288 (886,419)
23,979,923 6,102,872
5,217,390 29,970
21,995,285 544,390
33,350,642 (323,528)
66,210,000 304,002
-
151,913,475
106,052,970 1,113,992
5,899,409 99,270
1,254,114
-
232,464,642 5,771,287
490,431,087 9,106,124
7,679,903 65,519
585,123 (23,494)
-
7,349,726 (109,800)
8,077,133 -
76,150,660 1,082,497
311,016
Balance
- -
-
-
-
-
-
-
2,220,845
-
5,753,102 360,018
10,207,540 423,988
19,784,168 329,217
2,931 369,652
66,622,238 363,757
48,313,933 374,213
1,229,563 -
23,027,284 1,659,924
7,891,973 1,659,924
15,135,311
Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such amounts.
Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year in column (b). Likewise, if the respondent has a significant amount of plant
Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
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.
-
(a)(b)(c)
Account Beginning of Year Additions
retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements,
on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of
Report below the original cost of electric plant in service necessary to furnish electric utility service to customers in the state of Idaho.
In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold;
Account 103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
2020 / Q4
04/15/2021
ELECTRIC PLANT IN SERVICE - IDAHO (Account 101, 102, 103 and 106)
Include electric plant not directly assigned as allocated to the state of Idaho.
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.204-205
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
actuall in service at end of ear.
7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102; include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For account 399, state the nature and use of plant included in this account, and, if substantial in amount, submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each account comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46496,835,395
8,100,640
76,993,153
7,767,921
565,705
-
107,009,477
-
235,523,190
311,921
6,009,688
7,260,449
33,853,022
66,935,729
80,620,562
25,995,658
4,496,137
1,257,764
-
-
-
-
22,364,318
154,302,728
-
-
-
-
67,010,246
371,346
20,124,075
10,659,882
6,104,479
-
9,404,062
24,583,423
1,331,305
48,701,395
(234,293)
27,652
4,076
421,727
1,141,454
(3,952,675)
(749,896)
3,650
-
(175,357)
1,245,910
(131,535)
(1,884,523)
(2,065,187)
905
26,095
20,523
23,507
(1,237)
13,822
29,502
(8,641)
312,199
-
-
44,050
151,029
195,079
101,742
68,527
-
-
-
25,950
817,293
-
15,086
-
-
5,711
5,153
134,462
1,327
647,552
-
3,132
420,002
-
1,148
143,791
91,761
Adjustments
(e)
298,864
298,864
date of transaction. If proposed journal entries have been filed as required by the Uniform System of Accounts, give also the date of such filing.
Retirements
(d)
-
108,484
55,278
84,233
-
15,179,361
Transfers
(f)
End of Year
Balance
(g)
-
these tentative classifications in columns (c) and (d), including the reversals of the prior year's tentative account distributions of these amounts. Careful
2020 / Q4
04/15/2021
ELECTRIC PLANT IN SERVICE - IDAHO (Account 101, 102, 103 and 106)
observance of these instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent's plant
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.204-205
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Line
No.
47 3. TRANSMISSION PLANT
48 350 Land and Land Rights
49 352 Structures and Improvements
50 353 Station Equipment
51 354 Towers and Fixtures
52 355 Poles and Fixtures
53 356 Overhead Conductors and Devices
54 357 Underground Conduit
55 358 Underground Conductors and Devices
56 359 Roads and Trails
57 359.1 Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant Total of lines 48 throu h 57
59 4. DISTRIBUTION PLANT
60 360 Land and Land Rights
61 361 Structures and Improvements
62 362 Station Equipment
63 363 Storage Battery Equipment
64 364 Poles, Towers, and Fixtures
65 365 Overhead Conductors and Devices
66 366 Underground Conduit
67 367 Underground Conductors and Devices
68 368 Line Transformers
69 369 Services
70 370 Meters
71 371 Installations on Customer Premises
72 372 Leased Property on Customer Premises
73 373 Street Lighting and Signal Systems
74 374 Asset Retirement Costs for Distribution Plant
75 TOTAL Distribution Plant (Total of lines 60 through 74)
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 380 Land and Land Rights
78 381 Structures and Improvements
79 382 Computer Hardware
80 383 Computer Software
81 384 Communication Equipment
82 385 Miscellaneous Regional Transmission and Market Operation Plant
83 386 Asset Retirement Costs for Regional Transmission and Operation Plant
84 TOTAL Transmission and Market Operation Plant (Total lines 77 through 83)
85 6. GENERAL PLANT
86 389 Land and Land Rights
87 390 Structures and Improvements
88 391 Office Furniture and Equipment
89 392 Transportation Equipment
90 393 Stores Equipment
91 394 Tools, Shop and Garage Equipment
92 395 Laboratory Equipment
93 396 Power Operated Equipment
94 397 Communication Equipment
95 398 Miscellaneous Equipment
96 SUBTOTAL Total of lines 86 throu h 95
97 399 Other Tan ible Propert
98 399.1 Asset Retirement Costs for General Plant
99 TOTAL General Plant (Total of lines 96, 97 and 98)
100 TOTAL (Accounts 101 and 106)
101 102 Electric Plant Purchased
102 102 (Less) Electric Plant Sold
103 103 Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Total of lines 100 through 103)
-
-
1,463,515,320 58,117,043
50,536,013 3,570,188
1,463,515,320 58,117,043
50,536,013 3,570,188
-
-
12,093,902 43,215
15,988,082 734,367
64,311 -
437,804 54,490
1,824,214 335,831
121,356 -
14,981,654 1,296,313
513,754 427,558
4,141,640 678,414
369,296
- -
-
-
-
-
-
-
-
623,009,525 37,161,012
-
23,246,128 1,490,182
- -
- -
23,988,831 226,967
61,726,743 3,376,424
86,895,646 4,221,941
74,090,735 3,994,386
43,170,873 2,660,023
100,818,443 7,023,647
151,844,143 7,400,567
- -
46,111,264 6,440,944
6,794,686 325,931
4,322,033 -
276,511,411 6,619,795
-
724,401
894,454 (37,662)
1,117,813 (37,662)
54,547,530 594,735
8,724,011 1,277,325
95,799,428 2,798,010
5,942,873 31,911
Account Beginning of Year Additions
98,548,745 1,911,462
Balance
2020 / Q4
04/15/2021
ELECTRIC PLANT IN SERVICE - IDAHO (Account 101, 102, 103 and 106) (Continued)
10,212,156 81,676
(a)(b)(c)
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.206-207
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Line
No.
47
48
49
50
51
52
53
54
55
56
57
58
59
60
61
62
63
64
65
66
67
68
69
70
71
72
73
74
75
76
77
78
79
80
81
82
83
84
85
86
87
88
89
90
91
92
93
94
95
96
97
98
99
100
101
102
103
104
-
6,981,245 - 15,566,225 1,530,217,343
-
-
3,093,994 - 1,286,614 52,298,821
6,981,245 - 15,566,225 1,530,217,343
-
-
- 28,736 93,047
3,093,994 - 1,286,614 52,298,821
649,257 28,680 11,516,540
1,848,276 905,589 15,779,762
- 12,708 505,002
115,173 2,116 2,046,988
2,014 3,595 122,937
154,371 276,638 16,400,234
320,475 (14,451) 606,386
4,428 42,793 4,858,419
210 369,506
- - - -
-
-
-
-
-
-
-
1,166,906 - 154,104 659,157,735
-
254,002 24,482,308
- -
- -
310,723 23,905,075
26,832 65,076,335
44,114 1 91,073,474
123,033 - 77,962,088
34,365 (1) 45,796,530
27,227 15,972 107,830,835
314,813 - 158,929,897
- - -
31,797 138,133 52,658,544
(1) 7,120,616
- 4,322,033
1,604,188 - 15,814,951 297,341,969
-
18,027 742,428
238,789 1,095,581
239,881 1,320,032
37,422 2,065,551 57,170,394
107,248,873
16,834 (99,048) 9,885,454
74,724 4,685,451 103,208,165
- 1,078 5,975,862
Retirements Adjustments Transfers
1,475,208 8,263,874
Balance
2020 / Q4
04/15/2021
ELECTRIC PLANT IN SERVICE - IDAHO (Account 101, 102, 103 and 106) (Continued)
401,348 10,695,180
End of Year
(d)(e)(f)(g)
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.206-207
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
1.
2.
meter readings are added for billing purposes, one customer should be counted for each group of meters added. The average number of customers
means the average of twelve figures at the close of each month.
3. If increases or decreases from previous period (columns (c), (e), and (g)) are not derived from previously reported figures, explain any inconsistencies
in a footnote in the available space at the bottom of the page, or in a separate schedule.
Line
No.
1 Sales of Electricity
2 440 Residential Sales
3 442 Commercial and Industrial Sales (3)
4 Small (or Commercial)
5 Large (or Industrial)
6 444 Public Street and Highway Lighting
7 445 Other Sales to Public Authorities
8 446 Sales to Railroads and Railways
9 448 Interdepartmental Sales
10 TOTAL Sales to Ultimate Customers (1)
11 447 Sales for Resale
12 TOTAL Sales of Electricity
13 449.1 (Less) Provision for Rate Refunds
14 TOTAL Revenues Net of Provision for Refunds
15 Other Operating Revenues
16 450 Forfeited Discounts
17 451 Miscellaneous Service Revenues
18 453 Sales of Water and Water Power
19 454 Rent from Electric Property
20 455 Interdepartmental Rents
21 456 Other Electric Revenues (4)
22 456.1 Revenues from Transmission of Electricity for Others
23 457.1 Regional Control Service Revenues
24 457.2 Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues
27 TOTAL Electric Operating Revenues 313,156,038 318,857,908
18,602,350 28,573,531
6,015 5,615,277
17,949,115 21,442,785
-
-
-
421,424 1,268,815
177,812 118,312
47,984 128,342
-
294,553,688 290,284,377
(78,338)
294,553,688 290,362,715
28,276,426 27,968,449
266,277,262 262,394,266
248,741 274,645
-
-
2,723,779 2,669,672
53,578,621 50,408,829
85,688,459 89,886,994
(a)(b)(c)
Account Current Year Prior Year
2020 / Q4
04/15/2021
ELECTRIC OPERATING REVENUES - IDAHO
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
Report below operating revenues attributable to the state of Idaho 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.
ELECTRIC OPERATING REVENUE
124,037,662 119,154,126
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.300-301
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
4.
5.
regularly used by the respondent if such basis of classification is not generally greater than 1000 Kw of demand. (See Account 442 of the Uniform
System of Accounts. Explain basis of classification in a footnote.)
6. See pages 108-109 in the FERC Form 1, Important Changes During Period, for important new territory added and important rate increases or
decreases.
7.
Line
No.
1
2
3
4
5
6
7
8
9
2 10
11
12
13
14
1 Includes $222,931 of unbilled revenues.
2 Includes 6,464 MWH relatin to unbilled revenues.
(3) Segregation of Commercial and Industrial made on basis of utilization of energy and not on size of account.
4 Includes 62,791$ associated with a special contract for wheeling over the distribution system on file with the IPUC, recorded
in sub-account 456700.
3,344,067 137,010 134,510 3,414,317
- - -
3,344,067 137,010 134,510 3,414,317
955 - 964
3,343,112 137,010 134,510 3,413,353
3,022 45 41 2,754
- -
- -
7,243 177 169 7,146
1,095,960 413 428 1,171,472
1,005,069 17,989 17,751 973,813
1,258,168
Previous Year
(d)(e)(f)(g)
Current Year Previous Year Current Year
2020 / Q4
04/15/2021
ELECTRIC OPERATING REVENUES - IDAHO
Disclose amounts of $250,000 or greater in a footnote at the bottom of the page or in a separate schedule for accounts 451, 456, and 457.2.
Commercial and Industrial Sales, Account 442, may be classified according to the basis of classification (Small or Commercial, and Large or Industrial)
MEGAWATT HOURS SOLD AVG. NO. OF CUSTOMERS PER MONTH
Include unmetered sales. Provide details of such Sales in a footnote in the available space at the bottom of this page or in a separate schedule.
1,231,818 118,386 116,121
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.300-301
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
1.
2.
Line
No.
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 500 Operation Supervision and Engineering
5 501 Fuel
6 502 Steam Expenses
7 503 Steam from Other Sources
8 504 (Less) Steam Transferred-Cr.
9 505 Electric Expenses
10 506 Miscellaneous Steam Power Expenses
11 507 Rents
12 509 Allowances
13 TOTAL Operation (Total of lines 4 through 12)
14 Maintenance
15 510 Maintenance Supervision and Engineering
16 511 Maintenance of Structures
17 512 Maintenance of Boiler Plant
18 513 Maintenance of Electric Plant
19 514 Maintenance of Miscellaneous Steam Plant
20 TOTAL Maintenance (Total of Lines 15 through 19)
21 TOTAL Steam Power Generation Expenses (Total lines 13 & 20)
22 B. Nuclear Power Generation
23 Operation
24 517 Operation Supervision and Engineering
25 518 Fuel
26 519 Coolants and Water
27 520 Steam Expenses
28 521 Steam from Other Sources
29 522 (Less) Steam Transferred-Cr.
30 523 Electric Expenses
31 524 Miscellaneous Nuclear Power Expenses
32 525 Rents
33 TOTAL Operation (Total of lines 24 through 32)
34 Maintenance
35 528 Maintenance Supervision and Engineering
36 529 Maintenance of Structures
37 530 Maintenance of Reactor Plant Equipment
38 531 Maintenance of Electric Plant
39 532 Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Total of lines 35 through 39)
41 TOTAL Nuclear Power Generation Expenses (Total lines 33 & 40)
42 C. Hydraulic Power Generation
43 Operation
44 535 Operation Supervision and Engineering
45 536 Water for Power
46 537 Hydraulic Expenses
47 538 Electric Expenses
48 539 Miscellaneous Hydraulic Power Generation Expenses
49 540 Rents
50 TOTAL Operation (Total of lines 44 through 49)
51 Maintenance
52 541 Maintenance Supervision and Engineering
53 542 Maintenance of Structures
54 543 Maintenance of Reservoirs, Dams, and Waterways
55 544 Maintenance of Electric Plant
56 545 Maintenance of Miscellaneous Hydraulic Plant
57 TOTAL Maintenance (Total of lines 53 through 57)
58 TOTAL Hydraulic Power Generation Expenses (Total of lines 50 & 58)
59
657,980 1,176,128
488,339 321,374
3,379,990 3,378,832
- -
11,530,858 12,966,933
2,364,686 2,841,680
231,640 392,282
1,073,976 1,216,322
119,753 632,319
740,399 254,176
198,918 346,581
9,166,172 10,125,253
2,265,857 2,221,232
381,517 386,393
1,992,489 2,641,294
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
17,726,058 16,787,139
4,370,820 3,213,913
408,801 432,104
780,037 236,673
2,686,633 2,094,794
267,718 263,702
227,631 186,640
13,355,238 13,573,226
-
- 5,181
1,597,685 1,098,074
256,206 365,797
-
-
1,211,051 1,347,668
10,168,030 10,600,529
122,266 155,977
2020 / Q4
04/15/2021
ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
(a)(b)(c)
Account Current Year Previous Year
Amount for Amount for
For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
If the amount for previous year is not derived from previously reported figures, explain in a footnote.
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.320
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
1.
2.
Line
No.
60 D. Other Power Generation
61 Operation
62 546 Operation Supervision and Engineering
63 547 Fuel
64 548 Generation Expenses
65 549 Miscellaneous Other Power Generation Expenses
66 550 Rents
67 TOTAL Operation (Total of lines 62 through 66)
68 Maintenance
69 551 Maintenance Supervision and Engineering
70 552 Maintenance of Structures
71 553 Maintenance of Generating and Electric Plant
72 554 Maintenance of Miscellaneous Other Power Generation Plant
73 TOTAL Maintenance (Total of lines 69 through 72)
74 TOTAL Other Power Generation Expenses
75 E. Other Power Supply Expenses
76 555 Purchased Power
77 556 System Control and Load Dispatching
78 557 Other Expenses
79 TOTAL Other Power Supply Expenses (Total of lines 76 through 78)
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74, & 79)
81 2. TRANSMISSION EXPENSES
82 Operation
83 560 Operation Supervision and Engineering
84 561 Load Dispatching
85 561.1 Load Dispatch-Reliability
86 561.2 Load Dispatch-Monitor and Operation Transmission System
87 561.3 Load Dispatch-Transmission Service and Scheduling
88 561.4 Scheduling, System Control and Dispatch Services
89 561.5 Reliability, Planning and Standards Development
90 561.6 Transmission Service Studies
91 561.7 Generation Interconnection Studies
92 561.8 Reliability, Planning and Standards Development Services
93 562 Station Expenses
94 563 Overhead Lines Expenses
95 564 Underground Lines Expenses
96 565 Transmission of Electricity by Others
97 566 Miscellaneous Transmission Expenses
98 567 Rents
99 TOTAL Operation (Total of lines 83 through 98)
100 Maintenance
101 568 Maintenance Supervision and Engineering
102 569 Maintenance of Structures
103 569.1 Maintenance of Computer Hardware
104 569.2 Maintenance of Computer Software
105 569.3 Maintenance of Communication Equipment
106 569.4 Maintenance of Miscellaneous Regional Transmission Plant
107 570 Maintenance of Station Equipment
108 571 Maintenance of Overhead Lines
109 572 Maintenance of Under round Lines
110 573 Maintenance of Miscellaneous Transmission Plant
111 TOTAL Maintenance (Total of lines 101 through 110)
112 TOTAL Transmission Expenses (Total of lines 99 and 111)9,633,200 10,774,388
1 -
12,414 26,985
1,048,337 1,188,554
-
262,433 339,863
474,027 357,120
-
-
-
148,557 224,815
150,905 239,771
815,226 1,102,308
63,936 61,081
8,584,863 9,585,834
145,975 132,400
-
5,699,353 5,928,069
-
-
164,685 198,400
-
-
-
-
-
-
756,603 864,248
939,085 1,299,328
65,491,230 67,877,283
116,283,484 126,555,310
53,807,902 55,230,889
244,132 264,267
11,439,196 12,382,127
1,855,865 2,967,729
21,535,338 28,923,955
61,546 46,230
1,418,724 2,484,593
140,875 163,115
19,679,473 25,956,226
234,720 273,791
814,286 814,456
140,461 462,470
29,051 16,164
18,562,138 24,567,728
Amount for Amount for
Account Current Year Previous Year
(a)(b)(c)
2020 / Q4
04/15/2021
ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
If the amount for previous year is not derived from previously reported figures, explain in a footnote.
133,537 95,408
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.321
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
1.
2.
Line
No.
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 575.1 Operation Supervision
116 575.2 Day-Ahead and Real-Time Market Facilitation
117 575.3 Transmission Rights Market Facilitation
118 575.4 Capacity Market Facilitation
119 575.5 Ancillary Services Market Facilitation
120 575.6 Market Monitoring and Compliance
121 575.7 Market Facilitation, Monitoring, and Compliance Services
122 575.8 Rents
123 Total Operation (Total lines 115 through 122)
124 Maintenance
125 576.1 Maintenance of Structures and Improvements
126 576.2 Maintenance of Computer Hardware
127 576.3 Maintenance of Computer Software
128 576.4 Maintenance of Communication Equipment
129 576.5 Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance Total lines 125 throu h 129
131 TOTAL Regional Market Expenses (Total lines 123 & 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 580 Operation Supervision and Engineering
135 581 Load Dispatching
136 582 Station Expenses
137 583 Overhead Line Expenses
138 584 Underground Line Expenses
139 585 Street Lighting and Signal System Expenses
140 586 Meter Expenses
141 587 Customer Installations Expenses
142 588 Miscellaneous Expenses
143 589 Rents
144 TOTAL Operation (Total of lines 134 through 143)
145 Maintenance
146 590 Maintenance Supervision and Engineering
147 591 Maintenance of Structures
148 592 Maintenance of Station Equipment
149 593 Maintenance of Overhead Lines
150 594 Maintenance of Underground Lines
151 595 Maintenance of Line Transformers
152 596 Maintenance of Street Li htin and Si nal S stems
153 597 Maintenance of Meters
154 598 Maintenance of Miscellaneous Distribution Plant
155 TOTAL Maintenance (Total lines 146 through 154)
156 TOTAL Distribution Expenses (Total of lines 144 and 155)
157 5. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 901 Supervision
160 902 Meter Reading Expenses
161 903 Customer Records and Collection Expenses
162 904 Uncollectable Accounts
163 905 Miscellaneous Customer Accounts Expenses
164 TOTAL Customer Accounts Expenses (Total of line 159 through 163)
2,122,968 72,045
50,517 74,340
5,038,925 4,117,252
51,837 62,228
223,403 311,145
2,590,200 3,597,494
11,493,382 11,803,323
7,854 7,240
157,537 195,605
6,152,788 4,713,455
252,055 286,046
81,056 84,468
20,777 28,298
299,884 212,521
118,583 239,823
4,695,989 3,278,398
5,340,594 7,089,868
519,053 381,056
268,566 300,719
1,573,466 2,860,794
92,756 110,870
792,348 765,754
1,959 322
239,569 345,023
-
262,930 378,600
863,135 939,045
1,245,865 1,388,741
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
- -
Amount for Amount for
Account Current Year Previous Year
(a)(b)(c)
2020 / Q4
04/15/2021
ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
If the amount for previous year is not derived from previously reported figures, explain in a footnote.
- -
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.322
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
1.
2.
Line
No.
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 907 Supervision
168 908 Customer Assistance Expenses
169 909 Informational and Instructional Expenses
170 910 Miscellaneous Customer Service and Informational Expenses
171 TOTAL Customer Service and Informational Expenses (Total lines 167 through 170)
172 7. SALES EXPENSES
173 Operation
174 911 Supervision
175 912 Demonstratin and Sellin Expenses
176 913 Advertising Expenses
177 916 Miscellaneous Sales Expenses
178 TOTAL Sales Expenses (Total of lines 174 through 177)
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 920 Administrative and General Salaries
182 921 Office Supplies and Expenses
183 922 (Less) Administrative Expenses Transferred-Credit
184 923 Outside Services Employed
185 924 Property Insurance
186 925 Injuries and Damages
187 926 Employee Pensions and Benefits
188 927 Franchise Requirements
189 928 Regulatory Commission Expenses
190 929 (Less) Duplicate Charges-Cr.
191 930.1 General Advertising Expenses
192 930.2 Miscellaneous General Expenses
193 931 Rents
194 TOTAL Operation (Total of lines 181 through 193)
195 Maintenance
196 935 Maintenance of General Plant
197 TOTAL Administrative and General Expenses (Total of lines 194 and 196)
198 TOTAL Elec Op and Maint Expns (Total lines 80, 112, 131, 156, 164, 171, 178, 197)
3,888,905 4,047,561
33,355,402 25,117,615
186,647,430 189,338,932
182,855 99,635
29,466,497 21,070,054
- -
-
2,037,189 1,584,398
10,016,680 527,264
1,200 1,200
2,012,674 2,429,023
3,242,940 3,017,109
530,918 447,340
1,347,538 982,231
8,771,462 10,507,028
1,355,737 1,506,359
(32,696) (31,533)
- -
-
-
-
-
286,981 413,169
111,214 94,750
10,843,037 10,971,044
10,444,842 10,463,125
Amount for Amount for
Account Current Year Previous Year
(a)(b)(c)
2020 / Q4
04/15/2021
ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
If the amount for previous year is not derived from previously reported figures, explain in a footnote.
- -
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.323
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
1.
2.
3.
4.
5.
6.
Line Type of Number
No.Supporting of
Structure Circuits
(e)(h)
1
2
3
4 Steel Pole 2
5 H Type 1
6
7 H Type 1
8 Steel Pole 1
9 H Type 1
10 H Type 1
11 Cabinet Gorge Plant Noxon H Type 1
12
13 Benewah Sw. Station Pine Creek Sub H Type 1
14 Beacon Sub Lolo Sub Steel Pole 2
15 Beacon Sub Lolo Sub H Type 1
16 Beacon Sub Lolo Sub H Type 1
17 North Lewiston Walla Walla H Type 1
18 North Lewiston Shawnee H Type 1
19 H Type 1
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
Report information concerning transmission lines physically located in the state of Idaho, 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.
2020 / Q4
04/15/2021
TRANSMISSION LINE STATISTICS - IDAHO
Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
pole miles of line on leased or partly-owned structures in column (g). In a footnote in the available space at the bottom of this page or in a separate
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
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
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.
Report data by individual lines for all voltages if so required by the State commission.
(d)
DESIGNATION
From
(a)
To
Indicate whether the type of supporting structure reported in column (e) is: (1) single pole wood or steel; (2) H-frame wood, or steel poles; (3) tower; or
(4) underground construction. If a transmission line has more than one type of supporting structure, indicate the mileage of each type of construction
remainder of the line.
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
Beacon
Beacon
Divide Creek
Noxon Plant
Noxon Plant
For underground lines, report circuit miles
LENGTH (Pole Miles)
Group Sum - 115kV
On Structure
of Line Designated
(f)
On Structures
of Another Line
(g)(b)
Indicate where other than
VOLTAGE (KV)
60 cycle, 3 phase
Operating
(c)
Designed
Hatwai
Noxon Plant
Cabinet Gorge Plant
Cabinet Gorge Plant
Lolo Sub
115.00
230.00
230.00
230.00
230.00
N. Lewiston Sub
Pine Creek Sub
Pine Creek Sub
Pine Creek Sub
230.00
230.00
230.00
230.00
230.00
230.00
230.00
115.00
230.00
230.00
230.00
230.00
230.00
230.00
230.00
230.00
230.00
230.00
230.00
230.00
230.00
593.00
20.00
53.00
43.00
35.00
8.00
8.00
1.00
15.00
7.00
1.00
14.00
2.00
43.00
37.00
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.422-423
Name of Respondent This Report is:Date of Report Year / Period of Report
Avista Corporation X An Original mm/dd/yyyy End of
A Resubmission
Instructions
7.
8.
9.
10.
Line
No.
1
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
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.
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
2020 / Q4
04/15/2021
TRANSMISSION LINE STATISTICS - IDAHO
do not have include lower-voltage lines with higher-voltage lines. If two or more transmission line structures support lines of the same voltage, report the
(k)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
TotalMaintenance
5,205,472 110,641,734 115,847,206 149,720
1272 ACSS 363,604 20,607,585
OperationConstruction
Size of
Conductor
and Material
(i)
COST OF LINE
Include in column (j) land, land rights, and clearing right-of-way
Land
(j)
and Other Costs
(m)(l)
-
362,736
- -
-
213,016
-
1590 ACSR 1,042,786 26,150,464 9,002 8,800 17,802 27,193,250
- 1590 ACSS
-
1272 AAC 165,333 7,091,503 2,099 46,745 48,844 7,256,836
-
-
954 AAC 692,847 11,293,114 224,985 224,985
-
1590 ACSS
11,985,961
-
- 1272 ACSR
27,745
-
954 AAC 138,010 451,945 22,932 4,813
-
589,955
17,441
1590 ACSS -
954 AAC 387,459 5,222,681 17,441
-
5,610,140
-
1272 AAC
20,971,189
-
1272 ACSR 10,015 319,300 -
1272 AAC 25,818 1,132,628 -
329,315
1,158,446
-
1590 ACSR 155,244 2,616,153 2,713 159
-
2,771,397
- -
-
- -
-
- -
-
- -
-
- -
-
- -
-
- -
-
- -
-
Expenses
(p)
Total Cost Expenses Expenses
(n)
Rents
(o)
-
-
-
-
-
-
-
-
2,872
-
-
pole miles of the primary structure in column (f) and the pole miles of the other line(s) in column (g).
Designate any transmission line or portion thereof for which the respondent is not the sole owner. If such property is leased from another company, give
name of lessor, date and terms of lease, and amount of rent for year. For any transmission line other than a leased line, or portion thereof, for which the
respondent is not the sole owner but which the respondent operates or shares in the operation of, furnish a succinct statement explaining the arrangement
and giving 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.
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.
Base the plant cost figures called for in columns (j) through (l) on the book cost at end of year associated with the physical lines reported.
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405)E.ID.422-423