Annual Report Electric 2019.pdf

THIS FILING IS
Item 1: An Initial (Original)
Submission
OR Resubmission No. ____X
FERC FINANCIAL REPORT
FERC FORM No. 1: Annual Report of
Major Electric Utilities, Licensees
and Others and Supplemental
Form 3-Q: Quarterly Financial Report
These reports are mandatory under the Federal Power Act, Sections 3, 4(a), 304 and 309, and
18 CFR 141.1 and 141.400. Failure to report may result in criminal fines, civil penalties and
other sanctions as provided by law. The Federal Energy Regulatory Commission does not
consider these reports to be of confidential nature
OMB No.1902-0021
OMB No.1902-0029
OMB No.1902-0205
(Expires 11/30/2022)
(Expires 11/30/2022)
(Expires 11/30/2022)
Form 1 Approved
Form 1-F Approved
Form 3-Q Approved
FERC FORM No.1/3-Q (REV. 02-04)
Exact Legal Name of Respondent (Company) Year/Period of Report
End of 2019/Q4Avista Corporation
AVU-E
RECEIVED
2020 April 29,PM4:26
IDAHO PUBLIC
UTILITIES COMMISSION
IDENTIFICATION
FERC FORM NO. 1/3-Q:
REPORT OF MAJOR ELECTRIC UTILITIES, LICENSEES AND OTHER
Ryan L. Krasselt
1411 East Mission Avenue, Spokane, WA 99207
2019/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 L. Krasselt VP, Controller, Prin. Acctg
[phone] 04/15/2020
Ryan L. Krasselt
VP, Controller, Prin. Acctg Officer 04/15/2020
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
04/15/2020
2019/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
04/15/2020
2019/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
04/15/2020
2019/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
04/15/2020 2019/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
04/15/2020
2019/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
Parent of Bay Area Mfg and 100 3 Pentzer Corporation 3
Penture Venture Holdings 4
Inactive Holding Co.100 5 Pentzer Venture Holdings II, Inc.4
Holding Company 100 6 Bay Area Manufacturing, Inc.5
An affiliated business trust 100 7 Avista Capital II 6
issued pref. Trust Securit. 8
Owns an interest in a venture 100 9 Avista Northwest Resources, LLC 7
fund investment 10
Comm office & retail leasg 100 11 Steam Plant Square, LLC 8
Comm office & retail leasg 100 12 Courtyard Office Center, LLC 9
Restaurant operations 100 13 Steam Plant Brew Pub, LLC 10
Liquified Natural Gas Opertns 100 14 Salix, Inc.11
Parent co of Alaska Operatns 100 15 Alaska Energy and Resources Company (AERC)12
Utility operations in Juneau 100 16 Alaska Electric Light and Power Company 13
Mining Co Holding Properties 100 17 AJT Mining Properties, Inc.14
Rights to Purchase Snettisham 100 18 Snettisham Electric Company 15
19
20
21
22
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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.: 5 Column: d
Subsidiary of Pentzer Corporation
Schedule Page: 103 Line No.: 6 Column: d
Subsidiary of Pentzer Coporation
Schedule Page: 103 Line No.: 7 Column: d
Affiliate of Avista Corporation
Schedule Page: 103 Line No.: 9 Column: d
Subsidiary of Avista Capital
Schedule Page: 103 Line No.: 11 Column: d
Subsidiary of Avista Development
Schedule Page: 103 Line No.: 12 Column: d
Subsidiary of Avista Development
Schedule Page: 103 Line No.: 13 Column: d
Subsidiary of Steam Plant Square, LLC
Schedule Page: 103 Line No.: 14 Column: d
Subsidiary of Avista Capital
Schedule Page: 103 Line No.: 15 Column: d
Subsidiary of Avista Corporation
Schedule Page: 103 Line No.: 16 Column: d
Subsidiary of AERC
Schedule Page: 103 Line No.: 17 Column: d
Subsidiary of AERC
Schedule Page: 103 Line No.: 18 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)
04/15/2020
Year/Period of Report
2019/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
04/15/2020
2019/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 D. P. Vermillion 1
(effective 10/1/19) 2
3
Chairman of the Board S. L. Morris 4
and Chief Executive Officer (resigned 10/1/19) 5
6
Executive Vice President, Chief Financial Officer, M. T. Thies 7
and Treasurer (effective 10/1/19) 8
9
Senior Vice President, External Affairs K. J. Christie 10
and Chief Customer Officer (effective 10/1/19) 11
12
Sr Vice President, General Counsel, Chief Compliance M. M. Durkin 13
Officer, and Corporate Secretary 14
15
Senior Vice President and Chief Human Resources Officer K. S. Feltes 16
(resigned effective 3/1/2020) 17
18
Senior Vice President, Energy Delivery H. L. Rosentrater 19
(effective 10/1/19) 20
21
Senior Vice President, Energy Resources J. R. Thackston 22
and Environmental Compliance Officer 23
24
Vice President, Safety & HR Shared Services B. A. Cox 25
26
Vice President, Chief Information Officer, and J. M. Kensok 27
Chief Security Officer 28
29
Vice President, Controller, and R. L. Krasselt 30
Principal Accounting Officer 31
32
Vice President and Chief Counsel for Regulatory D. J. Meyer 33
and Governmental Affairs 34
35
Vice President and Chief Strategy Officer E. D. Schlect 36
37
38
39
40
41
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
04/15/2020
2019/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
3720 Carillon Point, Kirkland, WA 98033Erik J. Anderson (resigned 5/9/19) 4
5
P. O. Box 3727, Spokane, WA 99220Kristianne Blake*** 6
7
16 Ivy Court, Langhorne, PA 19047Donald C. Burke 8
9
P.O. Box 2884, Spokane, WA 99220Heidi B. Stanley*** 10
11
111 Main Street, Lewiston, ID 83501R. John Taylor*** 12
13
28013 Swan Cove Dr., Big Fork, MT 59911Marc F. Racicot 14
15
611 S. Congress Ave., Suite 125, Austin, TX 78704Rebecca A. Klein 16
17
26 Sanford Ln., Lafayette, CA 94549Janet D. Widmann 18
19
115 NW 78th St., Seattle, WA 98117Scott H. Maw 20
21
1411 E. Mission Ave, Spokane, WADennis P. Vermillion *** 22
(President and CEO, effective 10/1/19) 23
24
P.O. Box 9000, Spokane, WA 99209Jeffry L. Philipps (effective 11/1/19) 25
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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
04/15/2020 2019/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
04/15/2020 2019/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
04/15/2020 2019/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 04/15/2020 2019/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. On July 19, 2017, Avista Corp. entered into a definitive merger agreement to become an indirect,
wholly-owned subsidiary of Hydro One Limited (Hydro One) in Ontario. On January 23, 2019, this transaction
was terminated by mutual agreement between Avista Corp. and Hydro One and certain subsidiaries thereof. As
a result, Hydro One paid Avista Corp. a $103 million termination fee. Reference is made to Note 18 of the
Notes to Financial Statements for further information.
4. None
5. None
6. Reference is made to Notes 11 and 12 of the Notes to Financial Statements.
7. None
8. Average annual wage increases were 2.9% for non-exempt employees effective March 4, 2019. Average
annual wage increases were 3.1% for exempt employees effective March 4, 2019. Officers received average
increases of 4.1% effective February 18, 2019. Certain bargaining unit employees received increases of 3.0%
effective March 26, 2019.
9. Reference is made to Note 16 of the Notes to Financial Statements.
10. None
11. Reserved
12. See page 123 of this report.
13. On March 22, 2019, Erik J. Anderson, member of the Board of Directors of Avista Corp., informed the
Company that he would not stand for reelection to the Board of Directors for 2019. Mr. Anderson remained
with the Board of Directors through the Annual Meeting of Shareholders held on May 9, 2019.
Mr. Anderson chose not to stand for reelection due to other professional commitments. There were no
disagreements with the Company that contributed to Mr. Anderson's decision.
On May 10, 2019, Scott L. Morris, Chairman of the Board and Chief Executive Officer of Avista Corp.,
announced to the Company’s board of directors, that he will retire from the Company effective March 1, 2020.
Following Mr. Morris’ announcement, the Company’s board of directors appointed Dennis P. Vermillion Chief
Executive Officer effective October 1, 2019. Mr. Morris continued to serve as the Executive Chairman of the
board of directors of the Company and then as the non-executive Chairman of the board of directors following
his retirement. Mr. Vermillion will continue to serve on the Company’s board of directors.
On June 14, 2019, the Board of Directors of Avista Corp. increased the number of board members from 10 to
11, effective November 1, 2019, and elected Jeff L. Philipps to fill the vacancy and serve as a director on the
board effective on that date. Mr. Philipps will stand for election to the Board at the next annual meeting of
shareholders on May 11, 2020. Mr. Philipps will serve on the Finance Committee and the Environmental,
Technology and Operations Committee of the Board.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.1
On August 8, 2019, the Board of Directors named Mark T. Thies, Executive Vice President Chief Financial
Officer and Treasurer of Avista Corp. effective October 1, 2019. Mr. Thies has served as the Company’s Senior
Vice President CFO and Treasurer since January 1, 2013 and previously served as the Company’s Senior Vice
President CFO since September 29, 2008.
In August 2019, Karen S. Feltes, Senior Vice President and Chief Human Resources Officer, informed the
Board of Directors that she plans to retire effective March 1, 2020.
Effective October 1, 2019, Heather L. Rosentrater has been promoted from Vice President, Energy Delivery to
Senior Vice President, Energy Delivery.
Effective October 1, 2019, Kevin J. Christie has been promoted from Vice President, External Affairs and Chief
Customer Officer to Senior Vice President, External Affairs and Chief Customer Officer.
Effective January 1, 2020, Marian Durkin moved from Chief Compliance Officer to Chief Legal Officer. She
retained her role as the Corporate Secretary. In addition, she informed the Board of Directors that she plans to
retire effective August 1, 2020.
Effective January 1, 2020, Greg Hesler has been promoted from Senior Counsel II to Vice President, General
Counsel Chief 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.
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)
04/15/2020
Year/Period of Report
2019/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
FERC FORM NO. 1 (ED. 12-96)Page 109.2

This Page Intentionally Left Blank
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 04/15/2020 2019/Q4
UTILITY PLANT 1
6,385,433,383 6,004,750,680200-201Utility Plant (101-106, 114) 2
157,909,990 156,563,570200-201Construction Work in Progress (107) 3
6,543,343,373 6,161,314,250TOTAL Utility Plant (Enter Total of lines 2 and 3) 4
2,121,893,905 1,991,240,383200-201(Less) Accum. Prov. for Depr. Amort. Depl. (108, 110, 111, 115) 5
4,421,449,468 4,170,073,867Net 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
4,421,449,468 4,170,073,867Net 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
4,340,610 4,474,923Nonutility Property (121) 18
176,234 140,360(Less) Accum. Prov. for Depr. and Amort. (122) 19
11,547,000 11,547,000Investments in Associated Companies (123) 20
207,105,954 153,523,686224-225Investment 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
77,973 1,711,072Other Investments (124) 24
0 0Sinking Funds (125) 25
0 0Depreciation Fund (126) 26
0 0Amortization Fund - Federal (127) 27
22,034,002 18,794,801Other Special Funds (128) 28
0 0Special Funds (Non Major Only) (129) 29
922,948 4,842,426Long-Term Portion of Derivative Assets (175) 30
0 0Long-Term Portion of Derivative Assets – Hedges (176) 31
245,852,253 194,753,548TOTAL 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
3,067,240 4,737,049Cash (131) 35
4,434,090 26,809,063Special Deposits (132-134) 36
730,965 709,204Working Fund (135) 37
155,890 136,712Temporary Cash Investments (136) 38
0 0Notes Receivable (141) 39
153,814,552 157,729,381Customer Accounts Receivable (142) 40
15,726,829 4,618,679Other Accounts Receivable (143) 41
2,373,469 5,188,090(Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 42
0 31,659,207Notes Receivable from Associated Companies (145) 43
222,671 154,548Accounts Receivable from Assoc. Companies (146) 44
4,148,891 3,982,104227Fuel Stock (151) 45
0 0227Fuel Stock Expenses Undistributed (152) 46
0 0227Residuals (Elec) and Extracted Products (153) 47
46,558,819 43,166,166227Plant 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 04/15/2020 2019/Q4
(Continued)
0 0(Less) Noncurrent Portion of Allowances 53
0 0227Stores Expense Undistributed (163) 54
14,305,397 11,609,184Gas Stored Underground - Current (164.1) 55
0 0Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 56
24,682,259 20,211,526Prepayments (165) 57
0 0Advances for Gas (166-167) 58
129,823 166,418Interest and Dividends Receivable (171) 59
3,609,147 2,516,807Rents Receivable (172) 60
0 0Accrued Utility Revenues (173) 61
193,803 398,132Miscellaneous Current and Accrued Assets (174) 62
1,780,327 10,394,941Derivative Instrument Assets (175) 63
922,948 4,842,426(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
270,264,286 308,968,605Total Current and Accrued Assets (Lines 34 through 66) 67
DEFERRED DEBITS 68
13,795,819 13,923,600Unamortized Debt Expenses (181) 69
0 0230aExtraordinary Property Losses (182.1) 70
0 0230bUnrecovered Plant and Regulatory Study Costs (182.2) 71
643,207,368 598,724,109232Other Regulatory Assets (182.3) 72
0 2,313Prelim. 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
131,978 28,530Clearing Accounts (184) 76
0 0Temporary Facilities (185) 77
18,484,386 30,900,539233Miscellaneous Deferred Debits (186) 78
0 0Def. Losses from Disposition of Utility Plt. (187) 79
0 0352-353Research, Devel. and Demonstration Expend. (188) 80
8,883,821 10,255,271Unamortized Loss on Reaquired Debt (189) 81
177,056,526 187,450,520234Accumulated Deferred Income Taxes (190) 82
-3,189,401 -40,713,156Unrecovered Purchased Gas Costs (191) 83
858,370,497 800,571,726Total Deferred Debits (lines 69 through 83) 84
5,802,928,580 5,481,359,822TOTAL 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 04/15/2020 2019/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
PROPRIETARY CAPITAL 1
1,110,871,7671,176,498,977Common 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
-36,316,031-44,938,398(Less) Capital Stock Expense (214) 10 254b
660,984,141747,158,701Retained Earnings (215, 215.1, 216) 11 118-119
-16,389,107-13,386,701Unappropriated Undistributed Subsidiary Earnings (216.1) 12 118-119
00(Less) Reaquired Capital Stock (217) 13 250-251
00 Noncorporate Proprietorship (Non-major only) (218) 14
-7,866,070-10,258,024Accumulated Other Comprehensive Income (219) 15 122(a)(b)
1,773,220,0511,934,254,640Total Proprietary Capital (lines 2 through 15) 16
LONG-TERM DEBT 17
1,814,200,0001,904,200,000Bonds (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
151,017142,133Unamortized Premium on Long-Term Debt (225) 22
1,032,761930,270(Less) Unamortized Discount on Long-Term Debt-Debit (226) 23
1,781,165,2561,871,258,863Total Long-Term Debt (lines 18 through 23) 24
OTHER NONCURRENT LIABILITIES 25
065,565,105Obligations Under Capital Leases - Noncurrent (227) 26
00Accumulated Provision for Property Insurance (228.1) 27
245,000245,000Accumulated Provision for Injuries and Damages (228.2) 28
222,536,776212,005,607Accumulated Provision for Pensions and Benefits (228.3) 29
00Accumulated Miscellaneous Operating Provisions (228.4) 30
10,178,64511,767,158Accumulated Provision for Rate Refunds (229) 31
10,300,04719,684,476Long-Term Portion of Derivative Instrument Liabilities 32
00Long-Term Portion of Derivative Instrument Liabilities - Hedges 33
18,265,98520,338,053Asset Retirement Obligations (230) 34
261,526,453329,605,399Total Other Noncurrent Liabilities (lines 26 through 34) 35
CURRENT AND ACCRUED LIABILITIES 36
190,000,000182,300,000Notes Payable (231) 37
103,484,597107,406,813Accounts Payable (232) 38
014,722,348Notes Payable to Associated Companies (233) 39
7,3290Accounts Payable to Associated Companies (234) 40
4,783,2544,745,573Customer Deposits (235) 41
39,835,46938,022,918Taxes Accrued (236) 42 262-263
15,509,06215,282,041Interest 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 04/15/2020 2019/Q4
(continued)COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS)
00Matured Interest (240) 46
79,542168,034Tax Collections Payable (241) 47
56,358,80750,808,479Miscellaneous Current and Accrued Liabilities (242) 48
04,127,561Obligations Under Capital Leases-Current (243) 49
14,252,91030,612,670Derivative Instrument Liabilities (244) 50
10,300,04719,684,476(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
414,010,923428,511,961Total Current and Accrued Liabilities (lines 37 through 53) 54
DEFERRED CREDITS 55
2,142,2052,083,490Customer Advances for Construction (252) 56
29,725,44330,443,961Accumulated Deferred Investment Tax Credits (255) 57 266-267
00Deferred Gains from Disposition of Utility Plant (256) 58
22,466,06629,659,558Other Deferred Credits (253) 59 269
527,440,814481,207,133Other Regulatory Liabilities (254) 60 278
1,577,8961,448,359Unamortized Gain on Reaquired Debt (257) 61
00Accum. Deferred Income Taxes-Accel. Amort.(281) 62 272-277
497,875,564514,870,007Accum. Deferred Income Taxes-Other Property (282) 63
170,209,151179,585,209Accum. Deferred Income Taxes-Other (283) 64
1,251,437,1391,239,297,717Total Deferred Credits (lines 56 through 64) 65
5,481,359,8225,802,928,580TOTAL 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
04/15/2020 2019/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
1,428,099,066 1,416,798,041300-301Operating Revenues (400) 2
Operating Expenses 3
818,533,678 804,773,049320-323Operation Expenses (401) 4
70,160,821 63,628,892320-323Maintenance Expenses (402) 5
163,503,287 146,501,216336-337Depreciation Expense (403) 6
268,929336-337Depreciation Expense for Asset Retirement Costs (403.1) 7
40,625,925 34,897,443336-337Amort. & 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
7,343,186 6,384,995Regulatory Debits (407.3) 12
24,373,462 11,255,061(Less) Regulatory Credits (407.4) 13
104,229,614 105,935,344262-263Taxes Other Than Income Taxes (408.1) 14
1,016,853 21,463,627262-263Income Taxes - Federal (409.1) 15
-512,990 536,050262-263 - Other (409.1) 16
16,095,155 9,917,224234, 272-277Provision for Deferred Income Taxes (410.1) 17
3,735,815 836,768234, 272-277(Less) Provision for Deferred Income Taxes-Cr. (411.1) 18
718,518 -540,168266Investment 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
850,233Accretion Expense (411.10) 24
1,193,703,817 1,182,624,052TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 25
234,395,249 234,173,989Net 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
04/15/2020 2019/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
983,483,744 430,392,719 444,615,322 986,405,322 2
3
515,395,521 288,074,151 303,138,157 516,698,898 4
54,542,409 13,893,589 15,618,412 49,735,303 5
126,679,057 33,889,018 36,824,230 112,612,198 6
268,929 7
30,546,857 8,582,105 10,079,068 26,315,338 8
99,047 99,047 9
10
11
5,890,125 1,354,735 1,453,061 5,030,260 12
20,930,818 1,566,161 3,442,644 9,688,900 13
79,246,048 25,145,281 24,983,566 80,790,063 14
7,445,054 2,752,311 -6,428,201 18,711,316 15
-504,880 102,362 -8,110 433,688 16
5,035,837 4,191,080 11,059,318 5,726,144 17
2,388,896 -116,242 1,346,919 953,010 18
546,262 -20,064 172,256 -520,104 19
20
21
22
23
850,233 24
801,601,623 376,514,649 392,102,194 806,109,403 25
181,882,121 53,878,070 52,513,128 180,295,919 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
04/15/2020 2019/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)
234,395,249 234,173,989Net 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
Revenues From Nonutility Operations (417) 33
14,612,589 6,931,684(Less) Expenses of Nonutility Operations (417.1) 34
-31,291 -31,262Nonoperating Rental Income (418) 35
13,582,269 2,392,004119Equity in Earnings of Subsidiary Companies (418.1) 36
4,401,265 3,808,319Interest and Dividend Income (419) 37
-104,311 4,281,829Allowance for Other Funds Used During Construction (419.1) 38
Miscellaneous Nonoperating Income (421) 39
109,159Gain on Disposition of Property (421.1) 40
3,344,502 3,519,206TOTAL Other Income (Enter Total of lines 31 thru 40) 41
Other Income Deductions 42
13,251Loss on Disposition of Property (421.2) 43
-33,721Miscellaneous Amortization (425) 44
11,332,979 3,563,420 Donations (426.1) 45
2,640,044 2,793,863 Life Insurance (426.2) 46
21,180 2,053 Penalties (426.3) 47
1,718,553 2,073,702 Exp. for Certain Civic, Political & Related Activities (426.4) 48
27,317,212 5,342,674 Other Deductions (426.5) 49
42,996,247 13,788,963TOTAL Other Income Deductions (Total of lines 43 thru 49) 50
Taxes Applic. to Other Income and Deductions 51
311,708 293,278262-263Taxes Other Than Income Taxes (408.2) 52
-8,257,303 -5,085,932262-263Income Taxes-Federal (409.2) 53
-350,985 -220,461262-263Income Taxes-Other (409.2) 54
-1,887,439 34,584234, 272-277Provision for Deferred Inc. Taxes (410.2) 55
196,940 231,946234, 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
-10,380,959 -5,210,477TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) 59
-29,270,786 -5,059,280Net Other Income and Deductions (Total of lines 41, 50, 59) 60
Interest Charges 61
86,591,405 87,093,842Interest on Long-Term Debt (427) 62
321,206 321,207Amort. of Debt Disc. and Expense (428) 63
2,266,506 2,582,801Amortization 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
489,554Interest on Debt to Assoc. Companies (430) 67
8,205,985 6,749,117Other Interest Expense (431) 68
4,169,530 4,052,495(Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 69
93,696,243 92,685,589Net Interest Charges (Total of lines 62 thru 69) 70
111,428,220 136,429,120Income 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
191,949,607 136,429,120Net 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
04/15/2020
2019/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)
572,281,364 623,531,170 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)
1,742,362 10 Income Tax Reclass
11 AERC Reclass
12
13
14
1,742,362 15 TOTAL Debits to Retained Earnings (Acct. 439)
134,037,116 178,367,338 16 Balance Transferred from Income (Account 433 less Account 418.1)
17 Appropriations of Retained Earnings (Acct. 436)
( 5,320,848) -3,725,554 18
19
20
21
( 5,320,848) -3,725,554 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)
( 98,046,075) -102,772,642 31
32
33
34
35
( 98,046,075) -102,772,642 36 TOTAL Dividends Declared-Common Stock (Acct. 438)
18,837,251 10,579,864 37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings
623,531,170 705,980,176 38 Balance - End of Period (Total 1,9,15,16,22,29,36,37)
APPROPRIATED RETAINED EARNINGS (Account 215)
37,452,971 41,178,525 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
04/15/2020
2019/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
37,452,971 41,178,525 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)
37,452,971 41,178,525 47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46)
660,984,141 747,158,701 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
56,140 -16,389,107 49 Balance-Beginning of Year (Debit or Credit)
2,392,004 13,582,269 50 Equity in Earnings for Year (Credit) (Account 418.1)
10,000,000 10,000,000 51 (Less) Dividends Received (Debit)
( 8,837,251) -579,863 52 Other Subsidiary Activity
( 16,389,107) -13,386,701 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
04/15/2020 2019/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:
136,429,120 191,949,607 2 Net Income (Line 78(c) on page 117)
3 Noncash Charges (Credits) to Income:
179,217,557 202,496,251 4 Depreciation and Depletion
12,345,655 -45,916,643 5 Amortization of Deferred Power and Natural Gas Costs
2,895,123 2,578,830 6 Amortization of Debt Expense
2,450,031 1,632,961 7 Amortization of Investment in Exchange Power
8,882,835 10,274,962 8 Deferred Income Taxes (Net)
-540,168 718,518 9 Investment Tax Credit Adjustment (Net)
17,548,393 -9,860,829 10 Net (Increase) Decrease in Receivables
-4,880,128 -6,255,653 11 Net (Increase) Decrease in Inventory
12 Net (Increase) Decrease in Allowances Inventory
1,753,920 1,823,471 13 Net Increase (Decrease) in Payables and Accrued Expenses
1,041,677 -6,065,721 14 Net (Increase) Decrease in Other Regulatory Assets
28,600,265 -5,135,361 15 Net Increase (Decrease) in Other Regulatory Liabilities
6,331,723 6,434,430 16 (Less) Allowance for Other Funds Used During Construction
2,392,004 13,582,269 17 (Less) Undistributed Earnings from Subsidiary Companies
9,488,941 74,394,412 18 Other (provide details in footnote):
3,900,000 400,000 19 Allowance for Doubtful Accounts
-4,783,663 10,396,693 20 Changes in Other Non-Current Assets and Liabilities
-32,174,169 -13,325,137 21 Cash Paid for Settlement of Interest Rate Swaps
353,451,662 390,089,662 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):
-420,377,970 -439,249,001 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
-420,377,970 -439,249,001 34 Cash Outflows for Plant (Total of lines 26 thru 33)
35
36 Acquisition of Other Noncurrent Assets (d)
559,980 882,641 37 Proceeds from Disposal of Noncurrent Assets (d)
38
-19,855,879 -3,693,898 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
04/15/2020 2019/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):
-2,002,301 -1,750,738 54 Other
10,000,000 10,000,000 55 Dividends Received from Subsidiaries
56 Net Cash Provided by (Used in) Investing Activities
-431,676,170 -433,810,996 57 Total of lines 34 thru 55)
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
374,621,250 180,000,000 61 Long-Term Debt (b)
62 Preferred Stock
1,206,734 64,572,145 63 Common Stock
64 Other (provide details in footnote):
65
85,000,000 66 Net Increase in Short-Term Debt (c)
67 Other (provide details in footnote):
68
69
460,827,984 244,572,145 70 Cash Provided by Outside Sources (Total 61 thru 69)
71
72 Payments for Retirement of:
-274,902,917 -90,000,000 73 Long-term Debt (b)
74 Preferred Stock
75 Common Stock
-3,928,728 -891,513 76 Other (provide details in footnote):
-4,255,295 -1,115,527 77 Debt Issuance Costs
-7,700,000 78 Net Decrease in Short-Term Debt (c)
79
80 Dividends on Preferred Stock
-98,046,075 -102,772,642 81 Dividends on Common Stock
82 Net Cash Provided by (Used in) Financing Activities
79,694,969 42,092,463 83 (Total of lines 70 thru 81)
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
1,470,461 -1,628,871 86 (Total of lines 22,57 and 83)
87
4,112,505 5,582,966 88 Cash and Cash Equivalents at Beginning of Period
89
5,582,966 3,954,095 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 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.: 18 Column: c
Power and natural gas deferrals 3,653,810
Change in special deposits (3,862,626)
Change in other current assets (1,546,634)
Non-cash stock compensation 5,366,952
Cash received from settlement of interest rate
swaps 5,594,067
Preliminary survey and investigation costs 193,554
Gain on sale of property and equipment 13,250
Other 76,568
Schedule Page: 120 Line No.: 76 Column: b
Payment of minimum tax withholdings for
share-based payment awards (891,513)
Schedule Page: 120 Line No.: 76 Column: c
Payment of minimum tax withholdings for
share-based payment awards (3,928,728)
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/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 04/15/2020 2019/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)
04/15/2020
Year/Period of Report
2019/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:
2019 2018
Avista Corp.
Ratio of depreciation to average depreciable property 3.28% 3.17%
The average service lives for the following broad categories of utility plant in service are (in years):
Avista Corp.
Electric thermal/other production 35
Hydroelectric production 81
Electric transmission 50
Electric distribution 38
Natural gas distribution property 45
Other shorter-lived general plant 9
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 Statement 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. Beginning in 2018, 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.' 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 OPUC does not allow the Company to capitalize AFUDC that exceeds the FERC
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.2
calculated rate.
The effective AFUDC rate was the following for the years ended December 31:
2019 2018
Avista Corp.
Effective state AFUDC rate 7.39% 7.43%
Reclassification of AFUDC to Comply with Required FERC Regulatory Reporting
During the third quarter of 2019, the FERC completed an audit of Avista Corp. that covered the period January 1, 2015 through
December 31, 2018. The FERC indicated that Avista’s method of deferring taxes on AFUDC Equity should be changed from
normalization to flow-through. Avista has historically normalized the AFUDC Equity book/tax timing difference by recognizing
deferred tax expense with the result of spreading the benefit over the book life of the asset. Under the flow-through method, Avista
will no longer recognize deferred tax expense on the AFUDC Equity timing difference and instead recognize a regulatory asset to be
reversed over the book life of the asset. The flow-through method does not impact revenue requirement. A regulatory asset was
recorded in 2018 for $1.7M to account for this change to the flow-through method on a prospective basis.
Additionally, Avista Corp.’s AFUDC rate, which is prescribed by state regulatory authorities, is different than the FERC approved
method for calculating AFUDC. The FERC indicated that the difference in rates should be recorded as a regulatory asset rather than
in utility plant. At the conclusion of the audit, the FERC required Avista Corp. to reclassify the excess AFUDC from Net utility plant
to Non-current regulatory assets for the period January 1, 2010 (the effective date of the Company’s current fixed transmission rates)
to the present. As a result, Avista Corp. reclassified approximately $33 million (net of accumulated depreciation) from Net utility
plant to Non-current regulatory assets as of December 31, 2019, which represents the cumulative adjustment for 2010 through 2017.
The Company recorded the difference in AFUDC rates for 2018 and 2019 as a regulatory asset in the respective periods incurred. The
Company did not adjust prior period Consolidated Balances Sheets since the FERC required the adjustment to be reflected on a
cumulative basis at the end of the audit and required the AFUDC calculation to be modified on a prospective basis. The Company
concluded that the differences were insignificant during each prior period and on a cumulative basis. The adjustment recorded during
2019 had no effect on net income or earnings per share.
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.
See Note 9 for discussion of the Tax Cuts and Jobs Act (TCJA) and its impacts on the Company's financial statements, as well as a
tabular presentation of all the Company's deferred tax assets and liabilities.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.3
The Company did not incur any penalties on income tax positions in 2019 or 2018. The Company would recognize interest accrued
related to income tax positions as interest expense and any penalties incurred as other income deductions.
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):
2019 2018
Stock-based compensation expense $ 11,353 $ 5,367
Income tax benefits 2,384 1,127
Excess tax benefits (expenses) on settled share-based employee payments (612) 990
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
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:
2019 2018
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.4
Restricted Shares
Shares granted during the year 50,061 40,661
Shares vested during the year (48,228) (53,352)
Unvested shares at end of year 93,351 91,998
Unrecognized compensation expense at end of year (in thousands)$ 2,054 $ 1,964
TSR Awards
TSR shares granted during the year 99,214 80,724
TSR shares vested during the year (106,858) (107,342)
TSR shares earned based on market metrics — —
Unvested TSR shares at end of year 178,035 187,172
Unrecognized compensation expense (in thousands) $ 3,377 $ 3,706
CEPS Awards
CEPS shares granted during the year 49,609 40,329
CEPS shares vested during the year (53,454) (53,699)
CEPS shares earned based on market metrics 106,908 30,102
Unvested CEPS shares at end of year 88,990 93,579
Unrecognized compensation expense (in thousands) $ 2,401 $ 1,260
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, 2019 and 2018, the Company had recognized cumulative compensation expense and a liability of $0.9 million and $0.3
million, respectively, related to the dividend component on the outstanding and unvested share grants.
Cash and Cash Equivalents
For the purposes of the Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months
or less when purchased to be cash equivalents.
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The
Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual
accounts.
Utility Plant in Service
The cost of additions to utility plant in service, including 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)
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.5
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).
Goodwill
Goodwill arising from acquisitions represents the future economic benefit arising from other assets acquired in a business
combination that are not individually identified and separately recognized. The Company evaluates goodwill for impairment using a
fair value to carrying amount comparison (Step 1) for AEL&P. The Company completed its annual evaluation of goodwill for
potential impairment as of November 30, 2019 and determined that goodwill was not impaired at that time (carrying value was less
than the determined fair value). There were no events or circumstances that changed between November 30, 2019 and December 31,
2019 that would more likely than not reduce the fair values of the reporting units below their carrying amounts. While, the Company
does not have any goodwill amounts recorded on its FERC balance sheets, it does have goodwill at its subsidiaries and the amounts
for goodwill are reflected in the investment in subsidiary companies.
The following amounts were recorded as goodwill at the subsidiary companies and reflected through the investment in subsidiary
companies on the FERC balance sheets (dollars in thousands):
AEL&P Other
Accumulated
Impairment
Losses Total
Balance as of January 1, 2019 $52,426 $12,979 $(7,733)$57,672
Goodwill sold during the year — (12,979) 7,733 (5,246)
Balance as of December 31, 2019 $52,426 $—$—$52,426
Goodwill sold during the year relates to the sale of METALfx in April 2019. See Note 19 for further discussion. Accumulated
impairment losses were attributable to METALfx, which was a part of the other businesses.
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Balance Sheets measured at estimated fair value.
The 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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.6
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
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 14 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. 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/liability is established which will be surcharged or rebated to
customers in future periods. GAAP requires that for any alternative regulatory revenue program, like decoupling, the revenue must be
expected to be collected from customers within 24 months of the deferral to qualify for recognition in the current period Statement of
Income. Any amounts included in the Company's decoupling program that are not expected to be collected from customers within 24
months are not recorded in the financial statements until the period in which revenue recognition criteria are met. This could
ultimately result in decoupling revenue that arose during the current year being recognized in a future period.
If at some point in the future the Company determines that it no longer meets the criteria for continued application of regulatory
accounting practices for all or a portion of its regulated operations, the Company could be:
required to write off its regulatory assets, and
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.7
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 Gain/Loss on Reacquired Debt
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 costs
are 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):
2019 2018
Appropriated retained earnings $41,179 $37,453
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, 2019, the Company has not recorded any significant amounts related to unresolved
contingencies. See Note 16 for further discussion of the Company's commitments and contingencies.
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):

2019 2018
Avista Capital $6,404 $(5,660)
AERC 7,178 8,052
Total equity in earnings of subsidiary companies $13,582 $2,392
Subsequent Events
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.8
See footnote 21 - subsequent events for further details.
NOTE 2. NEW ACCOUNTING STANDARDS
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 Sheet through recognition of right-of-use (ROU) assets and lease liabilities
for the Company's operating leases. See Note 4 for further information on the Company's leases.
ASU No. 2018-02 “Income Statement-Reporting Comprehensive Income (Topic 220): Reclassification of Certain Tax Effects from
Accumulated Other Comprehensive Income”
In February 2018, the Financial Accounting Standards Board (FASB) issued ASU No. 2018-02, which amended the guidance for
reporting comprehensive income. This ASU allows a reclassification from accumulated other comprehensive income to retained
earnings for stranded tax effects resulting from the enactment of the TCJA in December 2017. This ASU is effective for periods
beginning after December 15, 2018 and early adoption is permitted. Upon adoption, the requirements of this ASU must be applied
either in the period of adoption or retrospectively to each period (or periods) in which the effect of the change in the U.S. federal
corporate income tax rate in the TCJA is recognized. The Company early adopted this standard effective January 1, 2018 and elected
to apply the guidance during the period of adoption rather than apply the standard retrospectively. As a result, the Company
reclassified $1.7 million in tax benefits from accumulated other comprehensive loss to retained earnings during the year ended
December 31, 2018.
For regulatory reporting, the reclassification to retained earnings is reflected in FERC account 439 – Adjustments to Retained
Earnings. Per FERC Guidelines, the usage of account 439 requires prior FERC approval. During 2018, the Company filed a request
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.9
with FERC for approval of the usage of account 439, which was approved by the FERC on December 21, 2018. The docket number
for Avista Corp.’s request was AC19-9-000.
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 is effective for periods beginning after
December 15, 2019 and early adoption is permitted. Entities have the option to early adopt the eliminated or modified disclosure
requirements and delay the adoption of all the new disclosure requirements until the effective date of the ASU. The Company is in the
process of evaluating this standard; however, it has determined that it will not early adopt any portion of this standard as of
December 31, 2019.
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 is effective for periods beginning after December 15, 2021 and early adoption is
permitted. The Company is in the process of evaluating this standard; however, it has determined that it will not early adopt this
standard as of December 31, 2019.
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.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.10
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.
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):
2019 2018
Unbilled accounts receivable $60,560 $ 64,463
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 retained existing GAAP associated with alternative revenue programs, which specified 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 Statement of Income. Any amounts included in the Company's decoupling program that
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.11
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 Statement 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
amortization of refunds to customers associated with the TCJA, 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):
2019 2018
Utility-related taxes $ 59,528 $ 58,730
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.12
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, 2019, the Company estimates it had unsatisfied
capacity performance obligations of $5.9 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):
2019 2018
Avista Corp.
Revenue from contracts with customers $ 1,160,853 $ 1,147,935
Derivative revenues 246,355 277,048
Alternative revenue programs 9,614 908
Deferrals and amortizations for rate refunds to customers 1,093 (16,549)
Other utility revenues 10,184 7,456
Total Avista Corp.1,428,099 1,416,798
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):
2019 2018
ELECTRIC OPERATIONS
Revenue from contracts with customers
Residential $ 369,102 $ 368,753
Commercial and governmental 317,589 314,532
Industrial 114,530 109,846
Public street and highway lighting 7,448 7,539
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.13
Total retail revenue 808,669 800,670
Transmission 18,180 17,864
Other revenue from contracts with customers 26,969 27,364
Total revenue from contracts with customers $853,818 $845,898
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):
2019 2018
NATURAL GAS OPERATIONS
Revenue from contracts with customers
Residential $ 196,430 $ 194,340
Commercial 92,168 89,341
Industrial and interruptible 5,263 4,753
Total retail revenue 293,861 288,434
Transportation 8,674 9,103
Other revenue from contracts with customers 4,500 4,500
Total revenue from contracts with customers $307,035 $302,037
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
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.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.14
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 74 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 Sheet. Total short-term lease costs for the year
ended December 31, 2019 are immaterial.
Leases that Have Not Yet Commenced
In March 2019, the Company signed a PPA with Clearway Energy Group (Clearway) to purchase all of the power generated from the
Rattlesnake Flat Wind project in Adams County, Washington. The facility has a nameplate capacity of 144 MW and is expected to
generate approximately 50 aMW annually. During negotiations with Clearway, Avista Corp. was involved in the selection of the
preferred generation facility type. The PPA is a 20-year agreement with deliveries expected to begin in 2020. The PPA
provides Avista Corp. with additional renewable energy, capacity and environmental attributes. Avista Corp. expects to recover the
cost of the power purchased through its retail rates. This PPA is considered a lease under ASC 842; however, all of the payments are
variable payments based on whether power is generated from the facility. Since all the payments are variable, the Company will not
record a lease liability for the agreement, but the expense will be included in resource costs when it becomes operational in 2020.
The components of lease expense were as follows for the year ended December 31, 2019 (dollars in thousands):
2019
Operating lease cost:
Fixed lease cost $ 4,425
Variable lease cost 988
Total operating lease cost $5,413
Supplemental cash flow information related to leases was as follows for the year ended December 31, 2019 (dollars in thousands):
2019
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.15
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash outflows:
Operating lease payments $ 4,375
Supplemental balance sheet information related to leases was as follows for December 31, 2019 (dollars in thousands):
December 31,
2019
Operating Leases
Operating lease ROU assets (Utility Plant)$69,746
Obligations under capital lease - current $ 4,128
Obligations under capital lease - noncurrent 65,565
Total operating lease liabilities $69,693
Weighted Average Remaining Lease Term
Operating leases 26.60 years
Weighted Average Discount Rate
Operating leases 3.82%
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
Total lease payments $113,594
Less: imputed interest (43,901)
Total $69,693
Future minimum lease payments (including principal and interest) under Topic 840 as of December 31, 2018 (dollars in thousands):
Operating Leases
2019 $4,995
2020 4,876
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.16
2021 4,859
2022 4,782
2023 4,780
Thereafter 102,389
Total lease payments $ 126,681
Less: imputed interest —
Total $126,681
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.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.17
The following table presents the underlying energy commodity derivative volumes as of December 31, 2019 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
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 are no expected deliveries of energy commodity derivatives after 2022.
The following table presents the underlying energy commodity derivative volumes as of December 31, 2018 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
2019 206 941 10,732 101,293 197 2,790 2,909 54,418
2020 — — 1,138 47,225 123 959 1,430 14,625
2021 — — — 9,670 — — 1,049 4,100
As of December 31, 2018, there were no expected deliveries of energy commodity derivatives after 2021.
(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):
2019 2018
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.18
Number of contracts 20 31
Notional amount (in United States dollars) $ 5,932 $ 4,018
Notional amount (in Canadian dollars) 7,828 5,386
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
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, 2019 7 70,000 2020
3 35,000 2021
10 110,000 2022
December 31, 2018 6 70,000 2019
6 60,000 2020
2 25,000 2021
7 80,000 2022
See Note 12 for discussion of the bond purchase agreement and the related settlement of interest rate swaps in connection with the
pricing of the bonds in September 2019.
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 Sheet as of December 31, 2019 and December 31, 2018 reflect the offsetting of derivative
assets and liabilities where a legal right of offset exists.
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2019 (in thousands):
Fair Value
Derivative and Balance Sheet Location
Gross Gross Collateral
Net Asset
(Liability)
on Balance
Sheet
Foreign currency exchange derivatives
Derivative instrument assets current $ 97 $ — $ — $ 97
Interest rate swap derivatives
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.19
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 current 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)
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2018 (in thousands):
Fair Value
Derivative and Balance Sheet Location
Gross Gross Collateral
Net Asset
(Liability)
on Balance
Sheet
Foreign currency exchange derivatives
Derivative instrument liabilities current $ — $ (45) $ — $ (45)
Interest rate swap derivatives
Derivative instrument assets current 5,283 — — 5,283
Long-term portion of derivative assets 5,283 (440) — 4,843
Long-term portion of derivative liabilities — (7,391) 530 (6,861)
Energy commodity derivatives
Derivative instrument assets current 400 (130) — 270
Derivative instrument liabilities current 31,457 (73,155) 37,790 (3,908)
Long-term portion of derivative liabilities 4,426 (21,292) 13,427 (3,439)
Total derivative instruments recorded on the balance sheet $46,849 $(102,453)$51,747 $(3,857)
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):
2019 2018
Energy commodity derivatives
Cash collateral posted $ 7,812 $ 78,025
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.20
Letters of credit outstanding 17,400 6,500
Balance sheet offsetting (cash collateral against net derivative positions) 3,378 51,217
Interest rate swap derivatives
Cash collateral posted 6,770 530
Balance sheet offsetting (cash collateral against net derivative positions) 6,770 530
There were no letters of credit outstanding related to interest rate swap derivatives as of December 31, 2019 and December 31, 2018.
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
in a liability position and the amount of additional collateral Avista Corp. could be required to post as of December 31 (in thousands):
2019 2018
Energy commodity derivatives
Liabilities with credit-risk-related contingent features $ 814 $ 2,193
Additional collateral to post 814 2,193
Interest rate swap derivatives
Liabilities with credit-risk-related contingent features 34,056 7,831
Additional collateral to post 26,912 6,579
NOTE 6. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, Colstrip, located in southeastern
Montana, and provides financing for its ownership interest in the project. The Company’s share of related fuel costs as well as
operating expenses for plant in service are included in the corresponding accounts in the Statements of Income. The Company’s share
of utility plant in service for Colstrip and accumulated depreciation (inclusive of the ARO assets and accumulated amortization) were
as follows as of December 31 (dollars in thousands):
2019 2018
Utility plant in service $ 387,860 $ 384,431
Accumulated depreciation (268,637) (261,997)
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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.21
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
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):
2019 2018
Asset retirement obligation at beginning of year $ 18,266 $ 17,482
Liabilities incurred 2,699 —
Liabilities settled (1,503) (66)
Accretion expense 876 850
Asset retirement obligation at end of year $20,338 $18,266
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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.22
average compensation as specified in the plan. Non-union employees hired on or after January 1, 2014 participate in a defined
contribution 401(k) plan in lieu of a defined benefit pension plan. The Company’s funding policy is to contribute at least the
minimum amounts that are required to be funded under the Employee Retirement Income Security Act, but not more than the
maximum amounts that are currently deductible for income tax purposes. The Company contributed $22.0 million in cash to the
pension plan in 2019 and 2018. The Company expects to contribute $22.0 million in cash to the pension plan in 2020.
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):
2020 2021 2022 2023 2024 Total 2025-2029
Expected benefit payments $ 39,647 $ 40,080 $ 40,652 $ 40,729 $ 41,767 $ 217,899
The expected long-term rate of return on plan assets is based on past performance and economic forecasts for the types of investments
held by the plan. In selecting a discount rate, the Company considers yield rates for highly rated corporate bond portfolios with
maturities similar to that of the expected term of pension benefits.
The Company provides certain health care and life insurance benefits for eligible retired employees that were hired prior to January 1,
2014. The Company accrues the estimated cost of postretirement benefit obligations during the years that employees provide services.
The liability and expense of this plan are included as other postretirement benefits. Non-union employees hired on or after January 1,
2014, will have access to the retiree medical plan upon retirement; however, Avista Corp. will no longer provide a contribution
toward their medical premium.
The Company has a Health Reimbursement Arrangement (HRA) to provide employees with tax-advantaged funds to pay for
allowable medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the
employee’s years of service and the ending salary. The liability and expense of the HRA are included as other postretirement benefits.
The Company provides death benefits to beneficiaries of executive officers who die during their term of office or after retirement.
Under the plan, an executive officer’s designated beneficiary will receive a payment equal to twice the executive officer’s annual base
salary at the time of death (or if death occurs after retirement, a payment equal to twice the executive officer’s total annual pension
benefit). The liability and expense for this plan are included as other postretirement benefits.
The Company expects that benefit payments under other postretirement benefit plans will total (dollars in thousands):
2020 2021 2022 2023 2024 Total 2025-2029
Expected benefit payments $ 6,442 $ 6,782 $ 6,965 $ 7,088 $ 7,244 $ 38,305
The Company expects to contribute $6.7 million to other postretirement benefit plans in 2020, 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, 2019 and 2018 and the
components of net periodic benefit costs for the years ended December 31, 2019 and 2018 (dollars in thousands):
Pension Benefits
Other Post-
retirement Benefits
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.23
2019 2018 2019 2018
Change in benefit obligation:
Benefit obligation as of beginning of year $ 671,629 $ 716,561 $ 134,053 $ 132,947
Service cost 19,755 21,614 3,006 3,188
Interest cost 28,417 26,096 5,598 4,831
Actuarial (gain)/loss 57,829 (48,641) 23,344 (610)
Benefits paid (35,248)(44,001)(6,705)(6,303)
Benefit obligation as of end of year $742,382 $671,629 $159,296 $134,053
Change in plan assets:
Fair value of plan assets as of beginning of year $ 544,051 $ 605,652 $ 36,852 $ 37,953
Actual return on plan assets 109,942 (40,954) 8,001 (1,101)
Employer contributions 22,000 22,000 — —
Benefits paid (33,930)(42,647)——
Fair value of plan assets as of end of year $642,063 $544,051 $44,853 $36,852
Funded status $ (100,319) $ (127,578) $ (114,443) $ (97,201)
Amounts recognized in the Balance Sheets:
Current liabilities $ (1,602) $ (1,477) $ (640) $ (580)
Non-current liabilities (98,717) (126,101) (113,803) (96,621)
Net amount recognized $(100,319)$(127,578)$(114,443)$(97,201)
Accumulated pension benefit obligation $644,004 $586,398 ——
Accumulated postretirement benefit obligation:
For retirees $ 72,816 $ 63,796
For fully eligible employees $ 34,545 $ 29,902
For other participants $ 51,935 $ 40,355
Included in accumulated other comprehensive loss (income) (net of tax):
Unrecognized prior service cost $ 2,105 $ 2,308 $ (4,400) $ (5,230)
Unrecognized net actuarial loss 114,368 138,516 63,101 52,441
Total 116,473 140,824 58,701 47,211
Less regulatory asset (107,395)(133,237)(57,520)(46,932)
Accumulated other comprehensive loss for unfunded benefit
obligation for pensions and other postretirement benefit
$ 9,078 $ 7,587 $ 1,181 $ 279
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.24
plans
Pension Benefits
Other Post-
retirement Benefits
2019 2018 2019 2018
Weighted-average assumptions as of December 31:
Discount rate for benefit obligation 3.85% 4.31% 3.89% 4.32%
Discount rate for annual expense 4.31% 3.71% 4.32% 3.72%
Expected long-term return on plan assets 5.90% 5.50% 5.70% 5.20%
Rate of compensation increase 4.66% 4.67%
Medical cost trend pre-age 65 – initial 5.75% 6.00%
Medical cost trend pre-age 65 – ultimate 5.00% 5.00%
Ultimate medical cost trend year pre-age 65 2023 2023
Medical cost trend post-age 65 – initial 6.50% 6.25%
Medical cost trend post-age 65 – ultimate 5.00% 5.00%
Ultimate medical cost trend year post-age 65 2026 2024
Pension Benefits Other Post-retirement Benefits
2019 2018 2019 2018
Components of net periodic benefit cost:
Service cost (a) $ 19,755 $ 21,614 $ 3,006 $ 3,188
Interest cost 28,417 26,096 5,598 4,831
Expected return on plan assets (31,763) (33,018) (2,101) (1,973)
Amortization of prior service cost 257 257 (981) (1,089)
Net loss recognition 10,216 7,879 4,013 4,232
Net periodic benefit cost $26,882 $22,828 $9,535 $9,189
(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.
Assumed health care cost trend rates have a significant effect on the amounts reported for the health care plans. A
one-percentage-point increase in the assumed health care cost trend rate for each year would increase the accumulated postretirement
benefit obligation as of December 31, 2019 by $13.9 million and the service and interest cost by $0.8 million. A one-percentage-point
decrease in the assumed health care cost trend rate for each year would decrease the accumulated postretirement benefit obligation as
of December 31, 2019 by $10.7 million and the service and interest cost by $0.6 million.
Plan Assets
The Finance Committee of the Company’s Board of Directors approves investment policies, objectives and strategies that seek an
appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and
funding policies.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.25
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,
absolute return and commodity funds. 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:
2019 2018
Equity securities 35% 37%
Debt securities 49% 45%
Real estate 7% 8%
Absolute return 9% 10%
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.
Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit value of the
fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund’s net assets by its units
outstanding at the valuation date. The Company's investments in common/collective trusts have redemption limitations that permit
quarterly redemptions following notice requirements of 45 to 60 days. The fair values of the closely held investments and partnership
interests are based upon the allocated share of the fair value of the underlying net assets as well as the allocated share of the
undistributed profits and losses, including realized and unrealized gains and losses. Most of the Company's investments in closely
held investments and partnership interests have redemption limitations that range from bi-monthly to semi-annually following
redemption notice requirements of 60 to 90 days. One investment in a partnership has a lock-up for redemption currently expiring in
2022 and is subject to extension.
The fair value of pension plan assets invested in real estate was determined by the investment manager based on three basic
approaches:
properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be
performed as warranted by specific asset or market conditions,
property valuations are reviewed quarterly and adjusted as necessary, and
loans are reflected at fair value.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.26
The fair value of pension plan assets was determined as of December 31, 2019 and 2018.
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of the
pension plan’s assets measured and reported as of December 31, 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
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of the
pension plan’s assets measured and reported as of December 31, 2018 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Cash equivalents $—$7,061 $—$7,061
Fixed income securities:
U.S. government issues — 37,078 — 37,078
Corporate issues — 175,908 — 175,908
International issues — 31,561 — 31,561
Municipal issues — 16,170 — 16,170
Mutual funds:
U.S. equity securities 101,720 — — 101,720
International equity securities 33,141 — — 33,141
Absolute return (1) 2,249 — — 2,249
Plan assets measured at NAV (not subject to hierarchy disclosure)
Common/collective trusts:
Real estate — — — 43,303
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.27
International equity securities — — — 30,944
Partnership/closely held investments:
Absolute return (1) — — — 60,612
Real estate ———4,304
Total $137,110 $267,778 $—$544,051
(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 2019 and 2018.
The fair value of other postretirement plan assets was determined as of December 31, 2019 and 2018.
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of
other postretirement plan assets measured and reported as of December 31, 2019 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Balanced index mutual funds (1) $ 44,853 $ — $ — $ 44,853
The following table discloses by level within the fair value hierarchy (see Note 14 for a description of the fair value hierarchy) of
other postretirement plan assets measured and reported as of December 31, 2018 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Balanced index mutual funds (1)$36,852 $—$—$36,852
(1) The balanced index fund for 2019 and 2018 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):
2019 2018
Employer 401(k) matching contributions $ 10,362 $ 10,044
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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.28
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):
2019 2018
Deferred compensation assets and liabilities $ 8,948 $ 8,400
NOTE 9. ACCOUNTING FOR INCOME TAXES
Federal Income Tax Law Changes
On December 22, 2017, the TCJA was signed into law. The legislation included substantial changes to the taxation of individuals as
well as U.S. businesses, multi-national enterprises, and other types of taxpayers. Highlights of provisions most relevant to Avista
Corp. included:
A permanent reduction in the statutory corporate tax rate from 35 percent to 21 percent, beginning with tax years after 2017;
Statutory provisions requiring that excess deferred taxes associated with public utility property be normalized using the
Average Rate Assumption Method (ARAM) or the Reverse South Georgia Method for determining the timing of the return
of excess deferred taxes to customers. Excess deferred taxes result from revaluing deferred tax assets and liabilities based on
the newly enacted tax rate instead of the previous tax rate, which, for most rate-regulated utilities like Avista Corp., results in
a net benefit to customers that will be deferred as a regulatory liability and passed through to customers over future periods;
Repeal of the corporate alternative minimum tax (AMT);
Bonus depreciation (expensing of capital investment on an accelerated basis) was removed as a deduction for property
predominantly used in certain rate-regulated businesses (like Avista Corp.), but is still allowed for the Company's
non-regulated businesses; and
NOL carryback deductions were eliminated, but carryforward deductions are allowed indefinitely with some annual
limitations versus the previous 20-year limitation.
As a result of the TCJA and its reduction of the corporate income tax rate from 35 percent to 21 percent (among many other changes
in the law), the Company recorded a regulatory liability associated with the revaluing of its deferred income tax assets and liabilities
to the new corporate tax rate. The total net amount of the regulatory liability for excess deferred income taxes associated with the
TCJA is $409.5 million as of December 31, 2019, compared to $429.3 million as of December 31, 2018, which reflects the amounts
to be refunded to customers through the regulatory process. The Avista Corp. amounts related to utility plant commenced being
returned to customers in 2018 and the Company expects they will be returned to customers over a period of approximately 36 years
using the ARAM. The return of the regulatory liability attributable to non-plant excess deferred taxes has begun through tariffs or
other regulatory mechanisms or proceedings.
Because most of the provisions of the TCJA were effective as of January 1, 2018 but customers' rates included a 35 percent corporate
tax rate built in from prior general rate cases, the Company began accruing for a refund to customers for the change in federal income
tax expense beginning January 1, 2018 forward. For Washington and Idaho, this accrual was recorded until all benefits prior to a
permanent rate change were properly captured through the deferral process. For Oregon, this accrual was recorded through 2019 with
new customer rates effective January 15, 2020. Refunds have begun to Washington, Idaho, and Oregon customers through tariffs or
other regulatory mechanisms or proceedings.
Excess accumulated deferred tax liabilities associated with the TCJA are classified as follows in the Balance Sheet as of December 31
(in thousands):
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.29
Protected Unprotected Total
Washington Idaho Oregon Washington Idaho Oregon Washington Idaho Oregon
As of December 31, 2019
Deferred tax assets 58,068 25,576 8,181 2,530 — 26 60,598 25,576 8,207
Regulatory liabilities 251,921 110,958 35,491 10,978 — 112 262,899 110,958 35,603
As of December 31, 2018
Deferred tax assets 59,201 26,657 8,820 2,725 1,465 71 61,926 28,122 8,891
Regulatory liabilities 256,837 115,647 38,265 11,824 6,409 306 268,661 122,056 38,571
The deferred tax assets in the table above represent the income tax gross-up of the excess deferred taxes (which, together with the
excess deferred tax amount, reflects the revenue amounts to be refunded to customers through the regulatory process).
Excess accumulated deferred income taxes were amortized in the Statement of Income as follows for the years ended December 31 (in
thousands):
Protected Unprotected Total
Washington Idaho Oregon Washington Idaho Oregon Washington Idaho Oregon
2019
Provision for deferred
income taxes (6,024) (2,653) (849) (651) (4,890) (149) (6,675) (7,543) (998)
2018
Provision for deferred
income taxes (5,334) (2,426) (496) (339) 290 — (5,673) (2,136) (496)
Positive amounts reflect increases to the provision for deferred income taxes and negative amounts reflect reductions to the provision
for deferred income taxes.
Deferred Income Taxes
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards.
The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company
evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that
deferred income tax assets will be realized.
As of December 31, 2019, the Company had $22.3 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 $6.0 million of the state tax credits. As such, the Company has
recorded a valuation allowance of $16.3 million against the state tax credit carryforwards and reflected the net amount of $6.0 million
as an asset as of December 31, 2019. State tax credits expire from 2020 to 2033.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.30
Status of Internal Revenue Service (IRS) and State Examinations
The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax
returns in certain jurisdictions, including Idaho, Oregon, and Montana. Subsidiaries are charged or credited with the tax effects of
their operations on a stand-alone basis. All tax years after 2016 are open for an IRS tax examination.
The Idaho State Tax Commission is currently reviewing tax years 2014 through 2017. The statute of limitations for Montana and
Oregon to review 2015 and earlier tax years has expired.
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):
2019 2018
Utility power resources $ 376,769 $ 357,656
The following table details Avista Corp.’ future contractual commitments for power resources (including transmission contracts) and
natural gas resources (including transportation contracts) (dollars in thousands):
2020 2021 2022 2023 2024 Thereafter Total
Power resources $ 178,546 $ 180,417 $ 179,020 $ 179,640 $ 157,620 $ 1,172,072 $ 2,047,315
Natural gas resources 68,232 50,062 43,577 39,493 36,640 274,302 512,306
Total $246,778 $230,479 $222,597 $219,133 $194,260 $1,446,374 $2,559,621
These energy purchase contracts were entered into as part of Avista Corp.’ 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.’ share of existing debt service cost and its proportionate share of the variable operating expenses of these projects. The
minimum amounts payable under these contracts are based in part on the proportionate share of the debt service requirements of the
PUD's revenue bonds for which the Company is indirectly responsible. The Company's total future debt service obligation associated
with the revenue bonds outstanding at December 31, 2019 (principal and interest) was $67.2 million.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.31
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):
2020 2021 2022 2023 2024 Thereafter Total
Contractual obligations $ 33,116 $ 34,081 $ 24,645 $ 25,190 $ 28,585 $ 191,873 $ 337,490
NOTE 11. NOTES PAYABLE
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million that expires in
April 2021. The committed line of credit is secured by non-transferable first mortgage bonds of Avista Corp. issued to the agent bank
that would only become due and payable in the event, and then only to the extent, that Avista Corp. 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, 2019, 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):
2019 2018
Balance outstanding at end of period $182,300 $190,000
Letters of credit outstanding at end of period $ 21,473 $ 10,503
Average interest rate at end of period 2.64% 3.18%
As of December 31, 2019 and 2018, the borrowings outstanding under Avista Corp.'s committed line of credit were classified as
short-term borrowings on the Balance Sheet.
NOTE 12. BONDS
The following details long-term debt outstanding as of December 31 (dollars in thousands):
Maturity
Year Description
Interest
Rate 2019 2018
Avista Corp. Secured Long-Term Debt
2019 First Mortgage Bonds 5.45% — 90,000
2020 First Mortgage Bonds 3.89% 52,000 52,000
2022 First Mortgage Bonds 5.13% 250,000 250,000
2023 Secured Medium-Term Notes 7.18%-7.54% 13,500 13,500
2028 Secured Medium-Term Notes 6.37% 25,000 25,000
2032 Secured Pollution Control Bonds (1) (1) 66,700 66,700
2034 Secured Pollution Control Bonds (1) (1) 17,000 17,000
2035 First Mortgage Bonds 6.25% 150,000 150,000
2037 First Mortgage Bonds 5.70% 150,000 150,000
2040 First Mortgage Bonds 5.55% 35,000 35,000
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.32
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 (2) 3.43% 180,000 —
2051 First Mortgage Bonds 3.54%175,000 175,000
Total Avista Corp. secured bonds 1,904,200 1,814,200
Secured Pollution Control Bonds held by Avista
Corporation (1)(83,700) (83,700)
Total long-term debt $1,820,500 $1,730,500
(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 November 2019, the Company issued and sold $180.0 million of 3.43 percent first mortgage bonds due in 2049 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 $90.0 million, repay a portion of the outstanding balance
under Avista Corp.'s $400.0 million committed line of credit and for other general corporate purposes. In connection with the
issuance and sale of the first mortgage bonds, the Company cash settled six interest rate swap derivatives (notional aggregate
amount of $70.0 million) and paid a net amount of $13.3 million. See note 5 for a discussion of interest rate swap
derivatives.
The following table details future long-term debt maturities including long-term debt to affiliated trusts (see Note 13) (dollars in
thousands):
2020 2021 2022 2023 2024 Thereafter Total
Debt maturities $ 52,000 $ — $ 250,000 $ 13,500 $ 15,000 $ 1,541,547 $ 1,872,047
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 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.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.33
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, 2019,
property additions and retired bonds would have allowed, and the net earnings test would not have prohibited, the issuance of $1.5
billion in an aggregate principal amount of additional first mortgage bonds at Avista Corp.
NOTE 13. ADVANCES FROM ASSOCIATED COMPANIES
In 1997, the Company issued Floating Rate Junior Subordinated Deferrable Interest Debentures, Series B, with a principal amount of
$51.5 million to Avista Capital II, an affiliated business trust formed by the Company. Avista Capital II issued $50.0 million of
Preferred Trust Securities with a floating distribution rate of LIBOR plus 0.875 percent, calculated and reset quarterly.
The distribution rates paid were as follows during the years ended December 31:
2019 2018
Low distribution rate 2.79% 2.36%
High distribution rate 3.61% 3.61%
Distribution rate at the end of the year 2.79% 3.61%
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 14. FAIR VALUE
The carrying values of cash and cash equivalents, special deposits, accounts and notes receivable, accounts payable and notes payable
are reasonable estimates of their fair values. Bonds and advances from associated companies are reported at carrying value on the
Balance Sheets.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted
prices in active markets for identical assets or liabilities (Level 1 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
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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.34
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):
2019 2018
Carrying
Value
Estimated
Fair Value
Carrying
Value
Estimated
Fair Value
Long-term debt (Level 2)$963,500 $1,124,649 $1,053,500 $1,142,292
Long-term debt (Level 3) 857,000 946,674 677,000 645,523
Long-term debt to affiliated trusts (Level 3) 51,547 41,238 51,547 38,145
These estimates of fair value of long-term debt and long-term debt to affiliated trusts were primarily based on available market
information, which generally consists of estimated market prices from third party brokers for debt with similar risk and terms. The
price ranges obtained from the third party brokers consisted of par values of 80.00 to 134.11, where a par value of 100.00 represents
the carrying value recorded on the Balance Sheets. Level 2 long-term debt represents publicly issued bonds with quoted market
prices; however, due to their limited trading activity, they are classified as Level 2 because brokers must generate quotes and make
estimates using comparable debt with similar risk and terms if there is no trading activity near a period end. Level 3 long-term debt
consists of private placement bonds and debt to affiliated trusts, which typically have no secondary trading activity. Fair values in
Level 3 are estimated based on market prices from third party brokers using secondary market quotes for debt with similar risk and
terms to generate quotes for Avista Corp. bonds.
The following table discloses by level within the fair value hierarchy the Company’s assets and liabilities measured and reported on
the Balance Sheets as of December 31, 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 agreements — — 27 (27) —
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.35
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
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, 2018 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, 2018
Assets:
Energy commodity derivatives $ — $ 36,252 $ — $ (35,982) $ 270
Level 3 energy commodity derivatives:
Natural gas exchange agreement — — 31 (31) —
Interest rate swap derivatives — 10,566 — (440) 10,126
Deferred compensation assets:
Mutual Funds:
Fixed income securities 1,745 — — — 1,745
Equity securities 6,157 ———6,157
Total $7,902 $46,818 $31 $(36,453)$18,298
Liabilities:
Energy commodity derivatives $ — $ 89,283 $ — $ (87,199) $ 2,084
Level 3 energy commodity derivatives:
Natural gas exchange agreement — — 2,805 (31) 2,774
Power exchange agreement — — 2,488 — 2,488
Power option agreement — — 1 — 1
Foreign currency exchange derivatives — 45 — — 45
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.36
Interest rate swap derivatives —7,831 —(970)6,861
Total $—$97,159 $5,294 $(88,200)$14,253
(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
5 for additional discussion of derivative netting.
To establish fair value for energy commodity derivatives, the Company uses quoted market prices and forward price curves to
estimate the fair value of 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 $0.4 million as of December 31, 2019 and $0.5 million as of December 31, 2018.
Level 3 Fair Value
Under the power exchange agreement, which expired on June 30, 2019, the Company purchased power at a price that was based on
the average operating and maintenance (O&M) charges from three surrogate nuclear power plants around the country. To estimate the
fair value of this agreement the Company estimated the difference between the purchase price based on the future O&M charges and
forward prices for energy. The Company compared the Level 2 brokered quotes and forward price curves described above to an
internally developed forward price which was based on the average O&M charges from the three surrogate nuclear power plants for
the current year. The Company estimated the volumes of the transactions that would take place in the future based on historical
average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in
isolation would result in a significantly higher or lower fair value measurement.
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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.37
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, 2019 (dollars in thousands):
Fair Value
(Net) at
December 31,
2019
Valuation
Technique Unobservable Input Range
Natural gas exchange (2,976) Internally derived Forward purchase prices $1.49 - $2.38/mmBTU
agreement weighted-average Forward sales prices $1.60 - $3.80/mmBTU
cost of gas Purchase volumes 50,000 - 310,000 mmBTUs
Sales volumes 60,000 - 310,000 mmBTUs
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, 2019:
Balance as of January 1, 2019 $ (2,774) $ (2,488) $ (5,262)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (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)
Year ended December 31, 2018:
Balance as of January 1, 2018 $ (3,164) $ (13,245) $ (16,409)
Total gains or (losses) (realized/unrealized):
Included in regulatory assets/liabilities (1) 326 5,027 5,353
Settlements 64 5,730 5,794
Ending balance as of December 31, 2018 (2)$(2,774)$(2,488)$(5,262)
(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.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.38
NOTE 15. 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, 2019 was limited to $293.9 million.
The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of
December 31, 2019 and 2018.
Equity Issuances
The Company issued equity in 2019 for total net proceeds of $64.6 million. Most of these issuances came through the Company's four
separate sales agency agreements under which the sales agents may offer and sell new shares of common stock from time to time.
These agreements provide for the offering of a maximum of 4.6 million shares, of which approximately 3.2 million remain unissued
as of December 31, 2019. In 2019, 1.4 million shares were issued under these agreements resulting in total net proceeds of $63.6
million. Subject to the satisfaction of customary conditions (including any required regulatory approvals), the Company has the right
to increase the maximum number of shares that may be offered under these agreements. These agreements expire on February 29,
2020. The Company expects to negotiate and enter into new sales agency agreements in the second quarter of 2020.
NOTE 16. COMMITMENTS AND CONTINGENCIES
In the course of its business, the Company becomes involved in various claims, controversies, disputes and other contingent matters,
including the items described in this Note. Some of these claims, controversies, disputes and other contingent matters involve
litigation or other contested proceedings. For all such matters, the Company intends to vigorously protect and defend its interests and
pursue its rights. However, no assurance can be given as to the ultimate outcome of any particular matter because litigation and other
contested proceedings are inherently subject to numerous uncertainties. For matters that affect Avista Corp.’s operations, the
Company intends to seek, to the extent appropriate, recovery of incurred costs through the ratemaking process.
Collective Bargaining Agreements
The Company’s collective bargaining agreements with the IBEW represent approximately 45 percent of all of Avista Corp.’
employees. A three-year agreement with the local union in Washington and Idaho representing the majority (approximately 90
percent) of the Avista Corp.' bargaining unit employees will expire in March 2021. A three-year agreement in Oregon, which covers
approximately 50 employees will also expire on April 1, 2020.
The Company is in the process of negotiating new agreements with each of these represented bargaining units. However, there is a
risk that if collective bargaining agreements expire and new agreements are not reached in each of our jurisdictions, employees could
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.39
strike. Given the magnitude of employees that are covered by collective bargaining agreements, this could result in disruptions to our
operations. However, the Company believes that the possibility of this occurring is remote.
Legal Proceedings Related to the Terminated Acquisition by Hydro One
See Note 18 for information regarding the termination of the proposed acquisition of the Company by Hydro One.
In connection with the now terminated acquisition, three lawsuits were filed in the United States District Court for the Eastern District
of Washington and were subsequently voluntarily dismissed by the plaintiffs.
One lawsuit was filed in the Superior Court for the State of Washington in and for Spokane County, captioned as follows:
Fink v. Morris, et al., No. 17203616-6 (filed September 15, 2017, amended complaint filed October 25, 2017).
The complaint generally alleged that the members of the Board of Directors of Avista Corp. breached their fiduciary duties by, among
other things, conducting an allegedly inadequate sale process and agreeing to the acquisition at a price that allegedly undervalued
Avista Corporation, and that Hydro One Limited, Olympus Holding Corp., and Olympus Corp. aided and abetted those purported
breaches of duty. The complaint sought various remedies, including monetary damages, attorneys’ fees and expenses. Subsequent to
the termination of the proposed acquisition in January 2019, the complaint was voluntarily dismissed by the plaintiffs.
Boyds Fire (State of Washington Department of Natural Resources v. Avista)
On August 19, 2019, the Company was served with a complaint filed by the State of Washington Department of Natural Resources,
seeking recovery of fire suppression 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 it before the tree 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. The case is in the early stages of discovery and the plaintiff has not yet
provided a statement specifying damages. Because the resolution of this claim remains uncertain, legal counsel cannot express an
opinion on the extent, if any, of the Company’s liability, nor is it possible for the Company to estimate the impact of any outcome at
this time. The Company intends to vigorously defend itself in the litigation.
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
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.’ 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.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.40
In addition, the Company holds additional non-hydro water rights. The State of Montana is examining the status of all water right
claims within state boundaries through a general adjudication. Claims within the Clark Fork River basin could adversely affect the
energy production of the Company’s Cabinet Gorge and Noxon Rapids hydroelectric facilities. The state of Idaho has initiated
adjudication in northern Idaho, which will ultimately include the lower Clark Fork River, the Spokane River and the Coeur d’Alene
basin. The Company is and will continue to be a participant in these and any other relevant adjudication processes. The complexity of
such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to
estimate the impact of any outcome at this time. The Company will continue to seek recovery, through the ratemaking process, of all
operating and capitalized costs related to this issue.
NOTE 17. REGULATORY MATTERS
Power Cost 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 2019, the Company
recognized a pre-tax benefit of $4.4 million under the ERM in Washington compared to a benefit of $6.1 million for 2018. Total net
deferred power costs under the ERM were a liability of $40.0 million as of December 31, 2019 and a liability of $34.4 million as of
December 31, 2018. 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. 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.
The cumulative rebate balance exceeds $30 million and as a result, the Company's 2019 filing contained a proposed rate refund,
effective July 1, 2019 over a three-year period. Subsequent to this filing, the WUTC approved the ERM rebate over a two-year
period.
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 $0.3 million as of December 31, 2019 and a liability of $7.6 million as of December 31, 2018. Deferred power cost assets represent
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.41
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 to be refunded to customers were a liability of $3.2 million
as of December 31, 2019 and a liability of $40.7 million as of December 31, 2018. These balances 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.' jurisdictions, Avista Corp.' 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 March 2020, th WUTC extended the electric and natural gas decoupling mechanisms through March
31, 2025. 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. During the first quarter of 2018,
the FCA in Idaho was extended for a one-year term through December 31, 2019. On December 13, 2019, the IPUC approved an
extension of the FCAs through March 31, 2025.
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. There will be an opportunity for
interested parties to review the mechanism and recommend changes, if any, by September 2019. 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.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.42
Cumulative Decoupling and Earnings Sharing Mechanism Balances
As of December 31, 2019 and December 31, 2018, 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,
2019 2018
Washington
Decoupling surcharge $ 22,440 $ 12,671
Provision for earnings sharing rebate — (693)
Idaho
Decoupling surcharge $ 2,549 $ 2,150
Provision for earnings sharing rebate (686) (774)
Oregon
Decoupling rebate $ (739) $ (898)
Provision for earnings sharing rebate — —
NOTE 18. TERMINATION OF PROPOSED ACQUISITION BY HYDRO ONE
On July 19, 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, on January 23, 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 on January 24, 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 totaled $19.7 million
pre-tax and included financial advisers' fees, legal fees, consulting fees and employee time.
Other Information Related to the Terminated Acquisition
Due to the termination of the acquisition, all the financial commitments that were included in the various settlement agreements with
the commissions for the proposed acquisition will not be required to be performed or observed.
The Company incurred significant transaction costs consisting primarily of consulting, banking fees, legal fees and employee time,
and these costs are not being passed through to customers. When the Company was assuming the transaction was going to be
completed, a significant portion of these costs were not deductible for income tax purposes. Now that the transaction has been
terminated, more of the previously incurred transaction costs are deductible so it has recorded additional tax benefits from these costs
in 2019.
See Note 16 for discussion of shareholder lawsuits filed against the Company, the Company’s directors, Hydro One, Olympus
Holding Corp., and Olympus Corp. in relation to the Merger Agreement and the proposed acquisition.
NOTE 19. SALE OF METALfx
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.43
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 on April 18, 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
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 20. SUPPLEMENTAL CASH FLOW INFORMATION
Supplemental cash flow information consisted of the following items for the years ended December 31 (dollars in thousands):
2019 2018
Cash paid for interest $ 92,681 $ 90,394
Cash paid for income taxes 26,164 16,576
Cash received for income tax refunds (589) (3,025)
NOTE 21. SUBSEQUENT EVENTS
The Company as evaluated its subsequent events as of April 14th, 2020.
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 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.
On August 7, 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
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.44
Avista Corp.’s rates without including an attrition allowance in the calculation of rate base.
On March 6, 2020, the Company received an order from the WUTC that will require 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. The Company
recorded a customer refund liability of $8.5 million in 2019.
Colstrip Units 3 & 4 Outage and Replacement Power Costs
In 2019, the Company filed a case with the WUTC to recover costs associated with an unplanned power outage at Colstrip Units 3
and 4. The primary issue is related to the cost of replacement power incurred in July and August 2018 due to a forced outage at
Colstrip Units 3 & 4. That outage occurred due to the plant exceeding certain air quality standards. In testimony filed by WUTC Staff
and Public Counsel on January 10, 2020, the parties recommend the WUTC disallow $3.3 million in replacement power costs. Avista
Corp. filed testimony on January 23, 2020, and provided support for no disallowance, but if the WUTC believes a disallowance is
appropriate, the level of disallowance would be $2.4 million.
On March 20, 2020, the Company received an order from the WUTC related to costs associated with a an unplanned outage of
Colstrip Units 3 and 4 in 2018. In its order, the WUTC disallowed approximately $3 million for the cost of replacement power during
the unplanned outage.
2019 Washington General Rate Cases
On March 25, 2020, the Company received an order from the WUTC that approved the partial multi-party settlement agreement that
was filed on November 21, 2019. The approved rates are designed to increase annual base electric revenues by $28.5 million, or 5.7
percent, and annual natural gas base revenues by $8.0 million, or 8.5 percent, effective April 1, 2020. The revenue increases are based
on a 9.4 percent return on equity with a common equity ratio of 48.5 percent and a rate of return on rate base of 7.21 percent.
As part of the WUTC order, the Company will return approximately $40 million from the ERM rebate to customers over a two-year
period. The ERM rebate includes approximately $3 million that was recently disallowed by the Commission for the cost of
replacement power during an unplanned outage at the Colstrip generating facility in 2018. The Commission directed the Company to
return a larger portion of the ERM money during the first year to achieve a net-zero billed impact to electric customers.
Included in the WUTC order is the acceleration of depreciation of Colstrip Units 3 & 4, to reflect a remaining useful life through
December 31, 2025. The order utilizes certain electric tax benefits associated with the 2018 tax reform to partially offset these
increased costs. The order also sets aside $3 million for community transition efforts to mitigate the impacts of the eventual closure of
Colstrip, half funded by customers and half funded by Company shareholders.
In addition, a recent order received from the WUTC on the 2015 remand cases requires the Company 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 over
a one year period, which will partially offset the increase in base rates.
Lastly, the order includes the extension of electric and natural gas decoupling mechanisms through March 31, 2025.
Credit Agreement
On April 6, 2020, the Company entered into a Credit Agreement with U.S. Bank National Association, as Lender and Administrative
Agent, and CoBank, ACB, as Lender in the amount of $100 million with a maturity date of April 5, 2021. Loans under this agreement
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.45
are unsecured and will have a variable annual interest rate determined by either the Eurodollar rate or the Alternative Base Rate
depending on the type of loan selected by Avista Corp.
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 has borrowed the entire $100 million available under this agreement, which is expected to be used to provide additional
liquidity and for general corporate purposes.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
FERC FORM NO. 1 (ED. 12-88)Page 123.46

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
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Avista Corporation X
04/15/2020 2019/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)
( 8,089,542)
Balance of Account 219 at Beginning of
Preceding Year
1
( 1,742,363)
Preceding Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
2
1,965,835
Preceding Quarter/Year to Date Changes in
Fair Value
3
223,472Total (lines 2 and 3) 4
( 7,866,070)
Balance of Account 219 at End of Preceding
Quarter/Year
5
( 7,866,070)
Balance of Account 219 at Beginning of
Current Year
6
Current Qtr/Yr to Date Reclassifications
from Acct 219 to Net Income
7
( 2,391,954)
Current Quarter/Year to Date Changes in
Fair Value
8
( 2,391,954)Total (lines 7 and 8) 9
( 10,258,024)
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
04/15/2020 2019/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)
( 8,089,542) 1
( 1,742,363) 2
1,965,835 3
136,429,120 136,652,592 223,472 4
( 7,866,070) 5
( 7,866,070) 6
7
( 2,391,954) 8
196,979,195 194,587,241( 2,391,954) 9
( 10,258,024) 10
FERC FORM NO. 1 (NEW 06-02)Page 122b
Schedule Page: 122(a)(b) Line No.: 2 Column: c
During the first quarter of 2018, Accounting Standards Update No. 2018-02 was adopted,
which resulted in a $1.7 million balance sheet only reclassification from Accumulated
Other Comprehensive Loss to account 439 - Adjustments to Retained Earnings. The
reclassification was the result of the change in federal income tax rates from 35 percent
to 21 percent. Usage of account 439 requires prior FERC approval. See Page 123 Note 2 for
further discussion of the adoption of ASU No. 2018-02 as well as the prior FERC approval.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/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
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
Avista Corporation X
04/15/2020 2019/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
4,320,051,737 6,302,457,210Plant in Service (Classified) 3
69,745,591Property Under Capital Leases 4
Plant Purchased or Sold 5
Completed Construction not Classified 6
Experimental Plant Unclassified 7
4,320,051,737 6,372,202,801Total (3 thru 7) 8
Leased to Others 9
12,045,797 12,951,318Held for Future Use 10
130,627,836 157,909,990Construction Work in Progress 11
279,264 279,264Acquisition Adjustments 12
4,463,004,634 6,543,343,373Total Utility Plant (8 thru 12) 13
1,528,306,319 2,121,893,905Accum Prov for Depr, Amort, & Depl 14
2,934,698,315 4,421,449,468Net Utility Plant (13 less 14) 15
Detail of Accum Prov for Depr, Amort & Depl 16
In Service: 17
1,503,624,342 1,995,071,690Depreciation 18
Amort & Depl of Producing Nat Gas Land/Land Right 19
Amort of Underground Storage Land/Land Rights 20
24,681,977 126,822,215Amort of Other Utility Plant 21
1,528,306,319 2,121,893,905Total 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
1,528,306,319 2,121,893,905Total 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
04/15/2020 2019/Q4
Line
No.
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas Other (Specify)
(d) (e) (f)
Other (Specify)Other (Specify)
1
2
1,330,407,424 651,998,049 3
69,745,591 4
5
6
7
1,330,407,424 721,743,640 8
9
190,585 714,936 10
2,416,941 24,865,213 11
12
1,333,014,950 747,323,789 13
395,724,780 197,862,806 14
937,290,170 549,460,983 15
16
17
394,754,186 96,693,162 18
19
20
970,594 101,169,644 21
395,724,780 197,862,806 22
23
24
25
26
27
28
29
30
31
32
395,724,780 197,862,806 33
FERC FORM NO. 1 (ED. 12-89) Page 201
Schedule Page: 200 Line No.: 4 Column: h
ROU Asset - $69,745,591
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/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
04/15/2020 2019/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
1. Report below the original cost of electric plant in service according to the prescribed accounts.
2. In addition to Account 101, Electric Plant in Service (Classified), this page and the next include Account 102, Electric Plant Purchased or Sold; Account
103, Experimental Electric Plant Unclassified; and Account 106, Completed Construction Not Classified-Electric.
3. Include in column (c) or (d), as appropriate, corrections of additions and retirements for the current or preceding year.
4. For revisions to the amount of initial asset retirement costs capitalized, included by primary plant account, increases in column (c) additions and
reductions in column (e) adjustments.
5. Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such accounts.
6. Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (c) are entries for reversals of tentative distributions of prior year reported in column (b). Likewise, if the respondent has a significant amount of
plant retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such
retirements, on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d)
1. INTANGIBLE PLANT 1
(301) Organization 2
(302) Franchises and Consents 44,651,922 3
(303) Miscellaneous Intangible Plant 24,879,157 4,564,389 4
TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) 69,531,079 4,564,389 5
2. PRODUCTION PLANT 6
A. Steam Production Plant 7
(310) Land and Land Rights 3,578,472 8
(311) Structures and Improvements 139,536,107 256,857 9
(312) Boiler Plant Equipment 180,990,226 5,564,604 10
(313) Engines and Engine-Driven Generators 6,770 1,409 11
(314) Turbogenerator Units 56,778,165 830,269 12
(315) Accessory Electric Equipment 29,585,199 114,675 13
(316) Misc. Power Plant Equipment 17,125,165 -499,400 14
(317) Asset Retirement Costs for Steam Production 14,327,505 2,699,146 15
TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 441,927,609 8,967,560 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 63,813,274 200,941 27
(331) Structures and Improvements 87,175,595 12,424,075 28
(332) Reservoirs, Dams, and Waterways 194,509,659 3,127,848 29
(333) Water Wheels, Turbines, and Generators 236,170,550 3,187,134 30
(334) Accessory Electric Equipment 67,054,223 4,768,783 31
(335) Misc. Power PLant Equipment 14,104,790 1,374,204 32
(336) Roads, Railroads, and Bridges 4,339,089 -677,646 33
(337) Asset Retirement Costs for Hydraulic Production 34
TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 667,167,180 24,405,339 35
D. Other Production Plant 36
(340) Land and Land Rights 905,167 37
(341) Structures and Improvements 17,135,420 40,508 38
(342) Fuel Holders, Products, and Accessories 21,388,222 8,759 39
(343) Prime Movers 23,508,061 40
(344) Generators 217,408,279 2,134,819 41
(345) Accessory Electric Equipment 22,102,499 370,246 42
(346) Misc. Power Plant Equipment 1,748,536 -40,440 43
(347) Asset Retirement Costs for Other Production 351,683 44
TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 304,547,867 2,513,892 45
TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 1,413,642,656 35,886,791 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
04/15/2020 2019/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
distributions of these tentative classifications in columns (c) and (d), including the reversals of the prior years tentative account distributions of these
amounts. Careful observance of the above instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of
respondent’s plant actually in service at end of year.
7. Show in column (f) reclassifications or transfers within utility plant accounts. Include also in column (f) the additions or reductions of primary account
classifications arising from distribution of amounts initially recorded in Account 102, include in column (e) the amounts with respect to accumulated
provision for depreciation, acquisition adjustments, etc., and show in column (f) only the offset to the debits or credits distributed in column (f) to primary
account classifications.
8. For Account 399, state the nature and use of plant included in this account and if substantial in amount submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9. For each amount comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase,
and date of transaction. If proposed journal entries have been filed with the Commission as required by the Uniform System of Accounts, give also date
1
2
44,373,854 -278,068 3
25,423,701 -871,522 3,148,323 4
69,797,555 -1,149,590 3,148,323 5
6
7
3,578,472 8
139,674,955 -84,856 33,153 9
192,656,435 -91,514 -6,193,119 10
8,179 11
57,238,023 -61,693 308,718 12
29,561,074 -95,044 43,756 13
16,624,409 -1,356 14
17,026,651 15
456,368,198 -334,463 -5,807,492 16
17
18
19
20
21
22
23
24
25
26
64,014,211 -4 27
97,019,506 -2,057,278 522,886 28
192,430,218 -4,100,469 1,106,820 29
234,559,681 -4,733,313 64,690 30
69,727,335 -1,822,560 273,111 31
15,179,096 -278,222 21,676 32
3,649,100 -12,343 33
34
676,579,147 -13,004,189 1,989,183 35
36
905,167 37
17,169,217 -6,711 38
21,390,353 -6,628 39
23,507,372 -689 40
219,321,048 -77,281 144,769 41
22,350,892 -34,863 86,990 42
1,702,679 -5,417 43
351,683 44
306,698,411 -131,589 231,759 45
1,439,645,756 -13,470,241 -3,586,550 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
04/15/2020 2019/Q4
Line
No.
Account Balance Additions
(c)(b)(a)
Beginning of Year
3. TRANSMISSION PLANT 47
(350) Land and Land Rights 28,481,411 1,304,214 48
(352) Structures and Improvements 26,235,360 -377,374 49
(353) Station Equipment 267,576,680 23,063,717 50
(354) Towers and Fixtures 17,291,148 -130,449 51
(355) Poles and Fixtures 262,539,672 18,566,462 52
(356) Overhead Conductors and Devices 147,291,972 12,158,671 53
(357) Underground Conduit 3,188,360 64,880 54
(358) Underground Conductors and Devices 2,536,276 66,166 55
(359) Roads and Trails 2,053,899 59,152 56
(359.1) Asset Retirement Costs for Transmission Plant 57
TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 757,194,778 54,775,439 58
4. DISTRIBUTION PLANT 59
(360) Land and Land Rights 10,537,353 1,293,834 60
(361) Structures and Improvements 34,091,794 110,533 61
(362) Station Equipment 138,327,119 10,327,916 62
(363) Storage Battery Equipment 2,559,615 63
(364) Poles, Towers, and Fixtures 406,089,343 31,925,943 64
(365) Overhead Conductors and Devices 268,683,588 12,516,684 65
(366) Underground Conduit 118,880,627 4,858,990 66
(367) Underground Conductors and Devices 209,466,532 10,841,097 67
(368) Line Transformers 269,654,993 11,298,322 68
(369) Services 173,790,109 6,683,792 69
(370) Meters 56,545,353 31,952,939 70
(371) Installations on Customer Premises 1,490,826 629,903 71
(372) Leased Property on Customer Premises 72
(373) Street Lighting and Signal Systems 63,205,408 3,467,876 73
(374) Asset Retirement Costs for Distribution Plant 74
TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 1,753,322,660 125,907,829 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 498,670 8,696 86
(390) Structures and Improvements 8,242,162 255,671 87
(391) Office Furniture and Equipment 2,735,533 532,831 88
(392) Transportation Equipment 46,691,376 4,243,064 89
(393) Stores Equipment 399,249 35,487 90
(394) Tools, Shop and Garage Equipment 5,633,451 726,477 91
(395) Laboratory Equipment 1,552,769 302,155 92
(396) Power Operated Equipment 32,154,229 354,121 93
(397) Communication Equipment 66,092,232 2,019,197 94
(398) Miscellaneous Equipment 152,016 47,643 95
SUBTOTAL (Enter Total of lines 86 thru 95) 164,151,687 8,525,342 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) 164,151,687 8,525,342 99
TOTAL (Accounts 101 and 106) 4,157,842,860 229,659,790 100
(102) Electric Plant Purchased (See Instr. 8) 286,320 101
(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) 4,158,129,180 229,659,790 104
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
04/15/2020 2019/Q4
Line
No.(g)
Adjustments
(e)
Retirements
(d)
ELECTRIC PLANT IN SERVICE (Account 101, 102, 103 and 106) (Continued)
47
29,647,248 -68,505 69,872 48
25,358,219 -482,549 17,218 49
287,013,636 -2,988,304 638,457 50
17,160,699 51
278,634,026 -1,584,528 887,580 52
158,589,765 -545,477 315,401 53
3,253,240 54
2,602,442 55
2,107,559 -5,492 56
57
804,366,834 -5,674,855 1,928,528 58
59
11,814,980 -15,916 291 60
33,532,067 -557,275 112,985 61
146,876,585 -1,087,819 690,631 62
2,428,752 -130,863 63
436,264,125 -328,373 1,422,788 64
280,528,350 -555,756 116,166 65
123,584,467 -138,002 17,148 66
219,816,148 -288,463 203,018 67
280,684,915 -78,221 190,179 68
180,415,605 -17,029 41,267 69
72,884,062 -47,143 15,567,087 70
2,114,606 -6,123 71
72
65,814,671 -1,258 857,355 73
74
1,856,759,333 -3,252,241 19,218,915 75
76
77
78
79
80
81
82
83
84
85
507,277 -89 86
8,475,394 66,457 88,896 87
1,438,878 -449,277 1,380,209 88
49,928,658 32,429 1,038,211 89
391,830 -66 42,840 90
6,162,650 -2,572 194,706 91
1,801,512 -9,608 43,804 92
31,797,569 -557 710,224 93
48,785,141 -1,189,279 18,137,009 94
193,350 -241 6,068 95
149,482,259 -1,552,803 21,641,967 96
97
98
149,482,259 -1,552,803 21,641,967 99
4,320,051,737 -25,099,730 42,351,183 100
-286,320 101
102
103
4,320,051,737 -25,386,050 42,351,183 104
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
04/15/2020 2019/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 2,869,1042022-2026 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
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 12,045,797
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
04/15/2020 2019/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.
29,312,177Cabinet Gorge Fish Passage 1
17,824,894Saddle Mountain Integration 2
8,740,483Rattlesnake Flat 115kV Wind Farm Project 3
5,737,854Irvin Sub - New Construction 4
5,462,653Substation Rebuilds 5
5,261,666Westside 230 kV Substation - Rebuild 6
5,101,013Benton-Othello 115 Recond 7
3,687,834New Substations 8
3,214,648CG HED Automation Replacement 9
2,798,513Substation Asset Mgmt Capital Maintenance 10
2,518,408KF Fuel Yard Equipment Replacement 11
2,239,114WSDOT Highway Franchise Consolidation 12
2,153,077Low Priority Ratings Mitigation 13
1,967,782Long Lake Plant Upgrades 14
1,889,717Protection System Upgrades for PRC-002 15
1,826,331Distribution Line Relocations 16
1,667,533Downtown Network - Performance & Capacity 17
1,566,149FAS 143 ARO 18
1,467,572Noxon Hydro-Noxon Switchyard 230kV Trans Line Rbld 19
1,426,915Electric Revenue Blanket 20
1,298,232LL HED Stability Enhancement 21
1,238,074Energy Imbalance Market 22
1,154,840CG HED Station Service Replacement 23
1,117,742Metro-Post St 115kV Underground Tx Line Rebuild 24
1,096,680Saddle Mountain Integration Phase 2 25
12,996,475Minor Projects <$1M 26
27
5,861,460R&D/Strategic Initiatives 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 130,627,836
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
04/15/2020 2019/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 1,426,663,880 1,426,663,880
Depreciation Provisions for Year, Charged to 2
(403) Depreciation Expense 3 108,490,436 108,490,436
(403.1) Depreciation Expense for Asset
Retirement Costs
4
(413) Exp. of Elec. Plt. Leas. to Others 5
Transportation Expenses-Clearing 6
Other Clearing Accounts 7 4,815,190 4,815,190
Other Accounts (Specify, details in footnote): 8 16,120,838 16,120,838
9 -168,072 -168,072
TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
10 129,258,392 129,258,392
Net Charges for Plant Retired: 11
Book Cost of Plant Retired 12 46,443,932 46,443,932
Cost of Removal 13 5,155,029 5,155,029
Salvage (Credit) 14 452,583 452,583
TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
15 51,146,378 51,146,378
Other Debit or Cr. Items (Describe, details in
footnote):
16 -1,151,552 -1,151,552
17
Book Cost or Asset Retirement Costs Retired 18
Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
19 1,503,624,342 1,503,624,342
Steam Production 20
Section B. Balances at End of Year According to Functional Classification
321,428,595 321,428,595
Nuclear Production 21
Hydraulic Production-Conventional 22 144,618,326 144,618,326
Hydraulic Production-Pumped Storage 23
Other Production 24 136,957,489 136,957,489
Transmission 25 229,897,098 229,897,098
Distribution 26 602,862,062 602,862,062
Regional Transmission and Market Operation 27
General 28 67,860,772 67,860,772
TOTAL (Enter Total of lines 20 thru 28) 29 1,503,624,342 1,503,624,342
Page 219FERC FORM NO. 1 (REV. 12-05)

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
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
Avista Corporation X
04/15/2020 2019/Q4
Line
No.
Description of Investment Date Acquired
(c)(b)(a)
Amount of Investment atBeginning of YearDate Of Maturity (d)
1. Report below investments in Accounts 123.1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a) Investment in Securities - List and describe each security owned. For bonds give also principal amount, date of issue, maturity and interest rate.
(b) Investment Advances - Report separately the amounts of loans or investment advances which are subject to repayment, but which are not subject to
current settlement. With respect to each advance show whether the advance is a note or open account. List each note giving date of issuance, maturity
date, and specifying whether note is a renewal.
3. Report separately the equity in undistributed subsidiary earnings since acquisition. The TOTAL in column (e) should equal the amount entered for
Account 418.1.
1
206,138,9711997Investment in Avista Capital 2
-159,248,496Avista Capital - Equity in Earnings 3
89,816,3802014Investment in AERC 4
16,816,831AERC - 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 153,523,686 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
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
Avista Corporation X
04/15/2020 2019/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 -50,000,000 2
-152,844,453 6,404,043 3
89,816,380 4
13,995,056 10,000,000 7,178,226 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 13,582,269 -40,000,000 207,105,954
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
04/15/2020 2019/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.
3,982,104 (1) 4,148,891 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)
30,587,855 29,944,453 5 Assigned to - Construction (Estimated)
6 Assigned to - Operations and Maintenance
3,406,236 (1) 3,443,631 7 Production Plant (Estimated)
69,743 (1) -4,267 8 Transmission Plant (Estimated)
464,542 (1) 585,679 9 Distribution Plant (Estimated)
10 Regional Transmission and Market Operation Plant
(Estimated)
8,637,790 (1),(2) 12,589,323 11 Assigned to - Other (provide details in footnote)
43,166,166 46,558,819 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
47,148,270 50,707,710 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)
04/15/2020
Year/Period of Report
2019/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
04/15/2020 2019/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
6,724Clearwater Wind Interconnect 186200 22
2,818Gordon Butte Project #50 186200 23
5,439Broadview Solar II Project #51 186200 24
68,945Aurora Solar Project #59 186200 25
110,267Clarkston Hts Solar Project #60 186200 26
32,102Rattlesnake II Wind Proj #62 186200 27
12,198Post Falls HED Project #63 186200 28
677Kettle Falls Upgrade Proj #66 186200 29
4,928Old Milwaukee Solar Proj #67 186200 30
597Clearwater Wind II Proj #68 186200 31
936Clearwater Wind III Proj #69 186200 32
6,611EnerNOC Batt. Storage Proj #70 186200 33
11,389Geronimo Solar Project #71 186200 34
4,622Geronimo Solar Project #72 186200 35
5,577Sprague Solar Project #73 186200 36
4,239Royal City Solar Project #76 186200 37
12,033Bafus Solar Project #77 186200 38
5,502Elf II Solar Project #79 186200 39
5,389Elf I Solar Project #80 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
04/15/2020 2019/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
3,767Ralston Solar Project #81 186200 22
1,526Haymaker Wind Proj #82 186200 23
1,221Martinsdale Wind Proj #83 186200 24
840Rainier Solar Project #85 186200 25
882Acadia Solar Project #84 186200 26
1,096Little Falls Solar Project #86 186200 27
205Geronimo6 Solar Project #94 186200 28
205Geronimo2 Solar Project #90 186200 29
739Jane Wind 2 Proj #96 186200 30
500Jane Wind Proj #95 186200 31
2,416Lolo Solar Project #97 186200 32
20,341Rattlesnake Optional Study 186200 33
2,685Stratford Solar Project #98 186200 34
3,136Wahatis Solar Project #99 186200 35
2,869Stringtown Solar #100 186200 36
1,237North Cheyenne #101 186200 37
6,419Kulm Solar Farm Project #57 186200 6,419 186210 38
12,685Rosenoff Solar Project #58 186200 12,685 186210 39
59,712Tokio Solar Project #54 186200 59,712 186210 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
04/15/2020 2019/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
3,239Plum River Solar Project #75 186200 3,239 186210 22
9,712Harrington Solar Project #61 186200 9,712 186210 23
1,420Purcell Batt. Storage Proj #74 186200 1,420 186210 24
1,273Malden Solar Project #78 186200 1,273 186210 25
57,899Taunton Solar Project #52 186200 57,899 186210 26
50Geronimo5 Solar Project #93 186200 50 186210 27
50Geronimo4 Solar Project #92 186200 50 186210 28
50Geronimo3 Solar Project #91 186200 50 186210 29
50Geronimo1 Solar Project #89 186200 50 186210 30
50Geronimo Solar Project #88 186200 50 186210 31
285Jantz Solar Project #87 186200 285 186210 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)
04/15/2020
Year/Period of Report
2019/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.: 38 Column: d
Total Life to Date Reimbursements. Project completed Q1
Schedule Page: 231.1 Line No.: 39 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 39 Column: d
Total Life to Date Reimbursements. Project completed Q1
Schedule Page: 231.1 Line No.: 40 Column: b
Total Life to Date Costs
Schedule Page: 231.1 Line No.: 40 Column: d
Total Life to Date Reimbursements. Project completed Q2
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 Q2
Schedule Page: 231.2 Line No.: 23 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 23 Column: d
Total Life to Date Reimbursements. Project completed Q3
Schedule Page: 231.2 Line No.: 24 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 24 Column: d
Total Life to Date Reimbursements. Project completed Q3
Schedule Page: 231.2 Line No.: 25 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 25 Column: d
Total Life to Date Reimbursements. Project completed Q3
Schedule Page: 231.2 Line No.: 26 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 26 Column: d
Total Life to Date Reimbursements. Project completed Q4
Schedule Page: 231.2 Line No.: 27 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 27 Column: d
Total Life to Date Reimbursements. Project completed Q4
Schedule Page: 231.2 Line No.: 28 Column: b
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 28 Column: d
Total Life to Date Reimbursements. Project completed Q4
Schedule Page: 231.2 Line No.: 29 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 29 Column: d
Total Life to Date Reimbursements. Project completed Q4
Schedule Page: 231.2 Line No.: 30 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 30 Column: d
Total Life to Date Reimbursements. Project completed Q4
Schedule Page: 231.2 Line No.: 31 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 31 Column: d
Total Life to Date Reimbursements. Project completed Q4
Schedule Page: 231.2 Line No.: 32 Column: b
Total Life to Date Costs
Schedule Page: 231.2 Line No.: 32 Column: d
Total Life to Date Reimbursements. Project completed Q4
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3
Name of Respondent This Report Is:(1) An Original
(2) A Resubmission
Date of Report(Mo, Da, Yr)Year/Period of Report
End of
OTHER REGULATORY ASSETS (Account 182.3)
Avista Corporation X
04/15/2020
2019/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)
9,687,444 10,344,716 606,842407 1,264,114WA Excess Nat Gas Line Extension Allowance 1
230,641,437 210,801,207 23,244,061228, 283 3,403,831Reg Asset Post Ret Liab 2
81,340,941 83,355,934 1,192,953283 3,207,946Regulatory Asset FAS109 Utility Plant 3
1,420,897 3,023,201 79,787283 1,682,091Regulatory Asset FAS109 DSIT Non Plant 4
107,699 107,699283Regulatory Asset FAS109 WNP3 5
403,183 133,911 269,272407, 537Regulatory Asset- Spokane River Relicense 6
42,589,145 41,309,157 1,279,988407Regulatory Asset- Lake CDA Settlement - Varies 7
1,776,570 19,326,621 6,000,822182 23,550,873Reg Assets- Decouplings Surcharge - 2 years 8
4,945,687 4,945,687Reg Asset - Colstrip 9
58,294,063 6,573,588 51,720,475244, 175Commodity MTM ST & LT Regulatory Asset 10
4,690,533 1,800,206 3,543,528182 653,201Regulatory Asset FAS143 Asset Retirement Obligation 11
634,064 1,126,296 119,941242 612,173Regulatory Asset Workers Comp 12
133,853,505 168,594,071 362,530,376244, 175 397,270,942Interest Rate Swap Asset 13
19,674,074 12,170,199 56,717,534242 49,213,659DSM Asset 14
4,052,923 3,981,955 70,968283, 410Deferred ITC 15
4,030,155 13,394,821 31,356431 9,396,022Regulatory Asset MDM System 16
90,430 1,326,885 185,080254, 407 1,421,535Regulatory Asset BPA Residential Exchange 17
1,930,519 3,594,035 75,672805 1,739,188Regulatory Asset FISERV - 3 years 18
3,506,418 44,093,659 1,492,712108, 282 42,079,953Regulatory Asset - AFUDC (PIS,WIP) & Equity DFIT 19
256,594 256,594Regulatory Asset ID PCA Deferral - 1 year 20
13,052,304 13,052,304Existing Meters/ERTS Retirement Def 21
109 2,321 2,212Other Regulatory Assets 22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
598,724,109TOTAL :44 643,207,368 509,269,066 553,752,325
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
Amortized over remaining book life of pre-1986 vintage assets. Amortization amount varies
yearly.
Schedule Page: 232 Line No.: 6 Column: a
Amortization for TDG Idaho ended on December 2019. Spokane River relicensing amortization
costs will end on 11/30/2020.
Schedule Page: 232 Line No.: 7 Column: a
WA Docket UE-080416 & ID Order AVU-E-08-01. Amortization thru 2059.
Schedule Page: 232 Line No.: 8 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.: 9 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.: 10 Column: a
Washington Docket# UE-002066 and Idaho Order# 28648
Schedule Page: 232 Line No.: 11 Column: a
Reclass of Regulatory Assets related to Colstrip to state jurisdictions.
Schedule Page: 232 Line No.: 12 Column: a
Quarterly adjustments to workers comp reserve for current unpaid claims.
Schedule Page: 232 Line No.: 13 Column: a
Settled swaps are amortized over the life of the associated debt.
Schedule Page: 232 Line No.: 14 Column: a
Amortization period varies depending on timing of transactions.
Schedule Page: 232 Line No.: 15 Column: a
Amortization period varies depending on underlying transactions.
Schedule Page: 232 Line No.: 16 Column: a
Washington Docket#s UE-180418, UG-180419
Schedule Page: 232 Line No.: 17 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.: 18 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.: 19 Column: a
Deferring the difference between FERC formula and State approved AFUDC rates primarily
from 2010-2017.
Schedule Page: 232 Line No.: 21 Column: a
Washington Docket#s UE-180418 and UG-180419. Amortization period to be determined.
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/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 DEFFERED DEBITS (Account 186)
Avista Corporation X
04/15/2020 2019/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
3,696,701 4,815,987 1,119,286Plant Alloc of Clearing Journal 4
8,132 8,132Intercompany Clearing 5
470,493 496,981 26,488Misc. Deferred Debits (AN) 6
540,265 540,265Misc. Deferred Debits (WA) 7
21,001,564 8,551,769 12,449,795VARReg Asset - Decoupling Deferred 8
836,724 836,724407Deferred Proj Compass - ID 4 yr 9
54,206 23,231 30,975506Reg Asset ID-Lake CDA 10 yr amt 10
46,298 46,298Conservation Project Programs 11
129,501 124,313 5,188557Nez Perce Settlement 12
522,220 22,587 499,633VARSubsidiary Billings 13
757,584 310,777 446,807VARMisc. Work Orders <$40,000 14
67,956 68,945 989Aurora Solar Project #59 15
60,951 54,795 6,156VARBuild Farm Taps 16
84,080 110,267 26,187Clarkston Hts Solar Project#60 17
96,382 59,743 36,639VARCredit Union Labor & Expenses 18
-83,782 -66,045 17,737Optional Wind Power 19
76,518 76,518Smart Hoist Suspense 20
-260,682 -226,818 33,864Timber Harvest Revenue 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)
30,900,539 18,484,386
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
04/15/2020 2019/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
20,510,338 14,294,336 2
3
4
5
6
Other 7
20,510,338 14,294,336TOTAL Electric (Enter Total of lines 2 thru 7) 8
Gas 9
3,791,114 3,071,820 10
11
12
13
14
Other 15
3,791,114 3,071,820TOTAL Gas (Enter Total of lines 10 thru 15 16
152,755,074 170,084,364Other 17
177,056,526 187,450,520TOTAL (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
04/15/2020 2019/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
04/15/2020 2019/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
1,176,498,977 67,176,996 2
3,824,590 93,351 3
3,824,590 93,351 1,176,498,977 67,176,996 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. In addition to the service condition, the Company must meet a return on equity target
in order for the CEO’s restricted shares to vest. Restricted stock is valued at the close of market of the Company’s common stock on
the grant date.

Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/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
04/15/2020 2019/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
04/15/2020 2019/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.
-44,938,398Common 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 -44,938,398

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
04/15/2020 2019/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
1,192,681 90,000,000FMBS - 5.45% SERIES 6
239,400 Discount- FMBS - 5.45% SERIES 7
1,812,935 150,000,000FMBS - 6.25% SERIES 8
367,500 Discount- FMBS - 6.25% SERIES 9
4,702,304 150,000,000FMBS - 5.70% SERIES 10
222,000 Discount- FMBS - 5.70% SERIES 11
2,284,788 250,000,000FMBS - 5.125% SERIES 12
575,000 Discount- FMBS - 5.125% SERIES 13
66,700,000COLSTRIP 2010A PCRBs DUE 2032 14
17,000,000COLSTRIP 2010B PCRBs DUE 2034 15
385,129 52,000,000FMBS - 3.89% SERIES 16
258,834 35,000,000FMBS - 5.55% SERIES 17
692,833 85,000,0004.45% SERIES DUE 12-14-2041 18
730,833 80,000,0004.23% SERIES DUE 11-29-2047 19
428,205 60,000,000FMBS- 4.11% SERIES 20
590,761 100,000,000FMBS- 4.37% SERIES 21
1,042,569 175,000,000FMBS- 3.54% SERIES 22
552,539 90,000,000FMBS 3.91% SERIES 23
4,246,448 375,000,000FMBS 4.35% SERIES 24
378,750 Discount- FMBS - 4.350% SERIES 25
1,111,577 180,000,000FMBS 3.43% SERIES 26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 256
33 TOTAL 2,045,747,000 23,374,318
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
04/15/2020 2019/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 1,342,49206-01-203706-03-199706-01-203706-03-1997 4
25,000,000 1,592,50006-19-202806-19-199806-19-202806-19-1998 5
4,496,25012-01-201911-18-200412-01-201911-18-2004 6
7
150,000,000 9,375,00012-01-203511-17-200512-01-203511-17-2005 8
9
150,000,000 8,550,00007-01-203712-15-200607-01-203712-15-2006 10
11
250,000,000 12,812,50004-01-202209-22-200904-01-202209-22-2009 12
13
66,700,00010-1-203212-15-201010-1-203212-15-2010 14
17,000,0003-1-203412-15-20103-1-203412-15-2010 15
52,000,000 2,022,80012-20-202012-20-201012-20-202012-20-2010 16
35,000,000 1,942,50012-20-204012-20-201012-20-204012-20-2010 17
85,000,000 3,782,50012-14-204112-14-201112-14-204112-14-2011 18
80,000,000 3,384,00011-29-204711-30-201211-29-204711-30-2012 19
60,000,000 2,466,00012-1-204412-18-201412-1-204412-18-2014 20
100,000,000 4,370,00012-1-204512-16-201512-1-204512-16-2015 21
175,000,000 6,195,00012-1-205112-15-201612-1-205112-15-2016 22
90,000,000 3,519,00012-1/204712-14-201712-1-204712-14-2017 23
375,000,000 16,312,50006-1-204806-1-201806-01-204805-22-2018 24
25
180,000,000 600,25012-01-204912-01-201912-01-204911-26-2019 26
27
28
29
30
31
32
FERC FORM NO. 1 (ED. 12-96)Page 257
33 1,955,747,000 83,755,442
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.: 6 Column: a
Matured in 2019 and fully amortized.
Schedule Page: 256 Line No.: 14 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.: 14 Column: c
The Company reacquired these bonds in 2010.
Schedule Page: 256 Line No.: 15 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.: 15 Column: c
The Company reacquired these bonds in 2010.
Schedule Page: 256 Line No.: 26 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.U-171210 entered
January 11, 2018;
2. Order of the Idaho Public Utilities Commission ,Order No. 33978 entered January 30, 2018;
3. Order of the Public Utility Commission of Oregon, Order No. 19-249, entered July 30, 2019
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)
04/15/2020
Year/Period of Report
2019/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
04/15/2020 2019/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.
191,949,607Net Income for the Year (Page 117) 1
2
3
Taxable Income Not Reported on Books 4
8,218,407 5
6
7
8
Deductions Recorded on Books Not Deducted for Return 9
264,780,968 10
23,748,485Federal Income Tax Expense 11
671,886State Income Tax Expense Adj 12
13
Income Recorded on Books Not Included in Return 14
-16,761,381 15
16
17
18
Deductions on Return Not Charged Against Book Income 19
-392,739,644 20
21
22
23
-13,582,269Equity in Subs Earnings 24
734,005Corporate Overhead Unallocated Subs 25
26
67,020,064Federal Tax Net Income 27
Show Computation of Tax: 28
29
14,074,213Federal Tax at 21% 30
31
89,757Prior Year True Ups 32
33
14,163,970Total Federal Tax Expense 34
35
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
04/15/2020 2019/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
247,648Income Tax 2014 2
-520,411Income Tax 2016 3
-104,399Income Tax 2017 4
3,721,124 -668,591 3,137,410Income Tax 2018 5
20,801,640 14,258,252Income Tax (Current) 6
Retained Earnings (Current) 7
Prior Retained Earnings 8
24,522,764 13,485,262 2,864,647 Total Federal 9
10
STATE OF WASHINGTON: 11
16,386,052 -2,265,643 18,657,279Property Tax (2018) 12
18,740,467Property Tax (2019) 13
892,951Excise Tax (2016) 14
2,658,281 42,618 2,615,663Excise Tax (2018) 15
24,251,919 27,166,921Excise Tax (2019) 16
3,216 3,211 496Natural Gas Use Tax 17
23,887,401 24,214,721 2,802,731Municipal Occupation Tax 18
-598,266 -607,289 -22,706Community Solar 19
89,476 92,145Sales & Use Tax (2018) 20
1,130,161 1,416,689Sales & Use Tax (2019) 21
67,808,240 68,711,695 25,038,559 Total Washington 22
23
STATE OF IDAHO: 24
147,821 14,064 133,757Income Tax (2018) 25
330,000 10,384Income Tax (2019) 26
3,983,547 50 25,096 3,983,497Property Tax (2018) 27
3,867,706 7,685,062Property Tax (2019) 28
4,093 4,093Sales & Use Tax (2018) 29
125,660 135,001Sales & Use Tax (2019) 30
KWH Tax (2017) 31
27,952 -3,875 31,826KWH Tax (2018) 32
345,991 372,268KWH Tax (2019) 33
1,019,264 1,019,285Franchise Tax (2018) 34
3,559,640 4,662,921Franchise Tax (2019) 35
13,411,674 12,875,875 25,096 5,172,458 Total Idaho 36
37
STATE OF MONTANA: 38
5,815 2,175 3,640Income Tax (2018) 39
360,000 235,666Income Tax (2019) 40
3,977,509
FERC FORM NO. 1 (ED. 12-96)Page 262
TOTAL41 117,673,438 127,911,617 39,835,469
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
04/15/2020 2019/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
247,648 2
-520,411 3
-104,399 -104,399 4
-674,164 5,573 -1,252,305 5
-14,534,936 21,404,419 7,388,769 -6,543,388 6
7
8
-15,313,499 21,404,419 7,394,342 -8,172,855 9
10
11
-401,799 -1,863,845 5,584 12
3,932,005 14,808,462 18,740,467 13
892,951 14
9,509 33,109 15
5,741,959 21,424,963 2,915,002 16
3,211 490 17
5,334,720 18,880,001 3,130,051 18
-607,289 -31,729 19
2,669 20
1,416,689 286,528 21
15,425,794 53,285,901 25,942,013 22
23
24
2,110 11,954 25
-216,652 710,714 -483,678 -319,616 26
50 27
1,667,482 6,017,580 3,817,356 28
29
135,001 9,341 30
31
-3,875 32
-1,315 373,583 26,277 33
21 34
1,119,304 3,543,617 1,103,281 35
2,705,930 710,714 9,459,231 -319,616 4,956,276 36
37
38
2,175 39
-67,147 363,470 -60,656 -124,334 40
FERC FORM NO. 1 (ED. 12-96)Page 263
41 -12,378,042 86,135,184 22,478,603 9,059,651 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
Avista Corporation X
04/15/2020 2019/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.
5,567,637 5,567,637Property Tax (2018) 1
5,784,643 11,552,453Property Tax (2019) 2
2,863 2,863Colstrip Generation Tax 3
247,559 247,559KWH Tax (2018) 4
854,170 1,080,780KWH Tax (2019) 5
27 -18 60Consumer Council Fee 6
86 118 19Public Commission Fee 7
12,822,800 12,874,037 5,818,915 Total Montana 8
9
STATE OF OREGON: 10
100,000 100,000Income Tax (2019) 11
3,952,413 3,952,413Property Tax (2018) 12
7,519,140 3,759,492Property Tax (2019) 13
911,958 955,373Franchise Tax (2018) 14
2,590,653 3,637,043Franchise Tax (2019) 15
11,121,751 11,448,948 3,952,413 955,373 Total Oregon 16
17
STATE OF CALIFORNIA: 18
1,600 1,600Income Tax (2019) 19
1,600 1,600 Total California 20
21
MISCELLANEOUS STATES: 22
2,050 460Income Tax (Current) 23
2,050 460 Total Misc States 24
25
MISCELLANEOUS OTHER 26
-1,553 -1,553CTR Credit (2018) 27
Timber Excise Tax (2017) 28
-1,841,624 25,047 -1,824,133 -42,537WA Renewable Energy 29
-1,839 -25,047 31,320 25,047Misc Distribution 30
65,754 69,927 3,007Thermal Fuel Tax 31
-1,779,262 -1,724,439 -14,483Total Other 32
33
34
35
36
37
38
39
40
3,977,509
FERC FORM NO. 1 (ED. 12-96)Page 262.1
TOTAL41 117,673,438 127,911,617 39,835,469
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
04/15/2020 2019/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
11,552,453 5,767,811 2
2,863 3
4
1,080,780 226,610 5
-18 15 6
118 51 7
-67,147 363,470 12,577,715 -124,334 5,994,487 8
9
10
75,000 25,000 11
12
4,318,910 3,392,995 -3,759,647 13
43,414 14
3,637,042 1,046,390 15
8,030,952 3,417,995 -3,759,647 1,089,804 16
17
18
1,600 19
1,600 20
21
22
460 -1,590 23
460 -1,590 24
25
26
-1,553 27
28
-1,824,133 29
31,320 33,158 30
69,927 7,180 31
-1,724,439 40,338 32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96)Page 263.1
41 -12,378,042 86,135,184 22,478,603 9,059,651 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
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Avista Corporation X
04/15/2020 2019/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 29,702,127 411 520,104 6
Idaho ITC 411 1,159,014 411 92,648 7
TOTAL 29,702,127 1,159,014 612,752 8
Other (List separately
and show 3%, 4%, 7%,
10% and TOTAL)
9
Gas Property (100% 23,316 411 16,200 10
Idaho ITC 411 204,829 411 16,373 11
TOTAL PROPERTY 23,316 204,829 32,573 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
04/15/2020 2019/Q4
Line
No.ADJUSTMENT EXPLANATIONAverage Periodof Allocationto Income
1
2
3
4
5
29,182,023 6
1,066,366 7
30,248,389 8
9
7,116 10
188,456 11
195,572 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
04/15/2020 2019/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 year 1,125,000 1
112,441Kettle Falls Diesel Leak 297,078 504,472 319,835514, 545 2
184,035Bills Pole Rentals 193,105 600,725 591,655172 3
8,400,357Defer Comp Active Execs 8,947,679 1,610,808 1,063,486128 4
140,000Executive Incent Plan 140,000 5
1,580,426Unbilled Revenue 1,243,970 336,456908 6
9,696,264WA Energy Recovery Mechanism 14,154,482 4,458,218Various 7
130,806Misc Deferred Credits 31,366 23,418 122,858186, 550 8
244,984Decoupling Deferred Credits 3,526,878 15,073,734 11,791,840182 9
851,753WA REC 851,753186 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 22,271,375 15,077,883 29,659,558 22,466,066
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 15, 2021.
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.: 9 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.: 10 Column: a
Washington Docket# UE-170485, 2 year plan
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/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
04/15/2020 2019/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 327,565,981 6,320,794 2
Gas 79,958,638 2,688,056 3
Other 90,350,945 -2,489,467 4
TOTAL (Enter Total of lines 2 thru 4) 497,875,564 6,519,383 5
6
7
8
TOTAL Account 282 (Enter Total of lines 5 thru 8) 497,875,564 6,519,383 9
Classification of TOTAL 10
Federal Income Tax 497,875,564 6,519,383 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
04/15/2020 2019/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
339,209,550 5,322,775 2
86,849,511 4,202,817 3
88,810,946 949,468 4
514,870,007 10,475,060 5
6
7
8
514,870,007 10,475,060 9
10
514,870,007 10,475,060 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
04/15/2020 2019/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
1,259,112 7,685,588 3,996,661 Electric 3
4
5
6
7
8
1,259,112 7,685,588 3,996,661TOTAL Electric (Total of lines 3 thru 8) 9
Gas 10
9,126,454 -6,680,910 Gas 11
12
13
14
15
16
9,126,454 -6,680,910TOTAL Gas (Total of lines 11 thru 16) 17
831,706 172,893,400Other 18
1,259,112 17,643,748 170,209,151TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 19
Classification of TOTAL 20
1,259,112 17,643,748 170,209,151Federal 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
04/15/2020 2019/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
13,393,102 3,010,503 -40,538 3
4
5
6
7
8
13,393,102 3,010,503 -40,538 9
10
2,385,096 -55,684 4,764 11
12
13
14
15
16
2,385,096 -55,684 4,764 17
163,807,011 74,125 9,992,220 18
179,585,209 3,010,503 -22,097 9,996,984 19
20
179,585,209 3,010,503 -22,097 9,996,984 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
04/15/2020 2019/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)
6,245,251 1,396,668 5,191,030 342,447Idaho Investment Tax Credit 190 1
1,111,427 1,111,427Oregon BETC Credit 2
28,078,514 10,990,229 17,088,285Interest Rate Swaps 427, 175 3
550,316 22,008 528,308Nez Perce 557 4
773,984 87,014 686,970Idaho Earnings Test 191 5
8,609,963 9,136,730 101,371 628,138Decoupling Rebate 182 6
24,748,354 25,802,794 1,054,440WA ERM 7
7,559,909 7,833,916 274,007ID PCA - 1 year 182, 557 8
8,105,848 141,936 7,963,912Deferred Federal ITC - Varies 190 9
410,749,394 12,378,938 398,370,456Plant Excess Deferred 410 10
18,538,128 7,448,495 11,089,633Non Plant Excess Deferred 410 11
305,126 589,729 284,603Reg Liability MDM System 12
1,692,177 2,263,637 571,460AFUDC Equity Tax Deferral 13
188,620 952,403 763,783Exist Meters/ERTS Excess Depr Deferred 14
284,139 294,533 10,394DSM Tariff Rider 15
1,343,384 9,249,947 2,401,864 10,308,427Low Income Energy Assistance 242, 908 16
658,833 261,474 397,359Deferred CS2 & Colstrip O&M 182 17
6,449,651 11,930,324 4,348,735 9,829,408Reg Liability - Tax Reform Amortization - 1 year 407 18
1,532,183 1,532,183Reg Liability - Energy Efficiency Assistance 19
1,447,796 955,292 492,504Other Regulatory Liabilities - Varies 190 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/3-Q (REV 02-04) Page 278
41 TOTAL 25,599,290 71,832,971 481,207,133 527,440,814
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
Avista defers 90 percent of the difference between actual net power supply expenses and
the amount included in base retail rates for Idaho customers. Rate adjustments for rebate
or surcharge are effective October 1.
Schedule Page: 278 Line No.: 9 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.: 10 Column: a
Amortized over remaining book life of plant, estimated 36 years.
Schedule Page: 278 Line No.: 11 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.: 13 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.: 14 Column: a
Washington Docket#s UE-180418 and UG-180419
Schedule Page: 278 Line No.: 16 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.: 18 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.: 19 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.: 20 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)
04/15/2020
Year/Period of Report
2019/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
ELECTRIC OPERATING REVENUES (Account 400)
Avista Corporation X
04/15/2020 2019/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
368,752,670(440) Residential Sales 369,101,530 2
(442) Commercial and Industrial Sales 3
314,532,129Small (or Comm.) (See Instr. 4) 317,589,170 4
109,846,315Large (or Ind.) (See Instr. 4) 114,530,530 5
7,538,909(444) Public Street and Highway Lighting 7,447,635 6
(445) Other Sales to Public Authorities 7
(446) Sales to Railroads and Railways 8
1,385,654(448) Interdepartmental Sales 1,502,287 9
802,055,677TOTAL Sales to Ultimate Consumers 810,171,152 10
91,775,470(447) Sales for Resale 81,398,279 11
893,831,147TOTAL Sales of Electricity 891,569,431 12
10,290,335(Less) (449.1) Provision for Rate Refunds -2,908,847 13
883,540,812TOTAL Revenues Net of Prov. for Refunds 894,478,278 14
Other Operating Revenues 15
(450) Forfeited Discounts 16
299,355(451) Miscellaneous Service Revenues 342,546 17
506,000(453) Sales of Water and Water Power 344,332 18
2,982,930(454) Rent from Electric Property 2,797,207 19
(455) Interdepartmental Rents 20
83,116,369(456) Other Electric Revenues 69,178,898 21
15,959,856(456.1) Revenues from Transmission of Electricity of Others 16,342,483 22
(457.1) Regional Control Service Revenues 23
(457.2) Miscellaneous Revenues 24
25
102,864,510TOTAL Other Operating Revenues 89,005,466 26
986,405,322TOTAL Electric Operating Revenues 983,483,744 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
04/15/2020 2019/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
3,626,870 340,308 345,064 3,766,048 2
3
3,156,248 42,618 42,930 3,170,031 4
1,772,281 1,318 1,305 2,047,228 5
18,423 594 612 17,973 6
7
8
13,717 138 148 14,708 9
8,587,539 384,976 390,059 9,015,988 10
3,777,497 2,942,248 11
12,365,036 384,976 390,059 11,958,236 12
13
12,365,036 384,976 390,059 11,958,236 14
Page 301
Line 12, column (b) includes $ of unbilled revenues.
Line 12, column (d) includes MWH relating to unbilled revenues
-363,995
22,368
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
04/15/2020 2019/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)
3,628,426 327,516 11,079 0.0937 340,019,212 2 1 Residential Service
4,502 348 12,937 0.0619 278,564 3 2 Residential Service
4 3 Residential Service
89,352 15,390 5,806 0.1462 13,067,088 5 12 Res. & Farm Gen. Service
6 15 MOPS II Residential
40,322 65 620,338 0.0919 3,705,526 7 22 Res. & Farm Lg. Gen. Service
11 3 3,667 0.1497 1,647 8 30 Pumping-Special
9,002 1,742 5,168 0.1302 1,171,896 9 32 Res. & Farm Pumping Service
3,526 0.3354 1,182,765 10 48 Res. & Farm Area Lighting
-110 11 49 Area Lighting-High-Press.
12 56 Centralia Refund
149,073 13 95 Wind Power
14 72 Residential Service
15 73 Residential Service
16 74 Residential Service
17 76 Residential Service
18 77 Residential Service
-30,671 19 58A Tax Adjustment
10,088,369 20 58 Tax Adjustment
3,775,141 345,064 10,940 0.0979 369,633,359 21 SubTotal
-9,093 0.0585 -531,830 22 Residential-Unbilled
3,766,048 345,064 10,914 0.0980 369,101,529 23 Total Residential Sales
24
25 COMMERCIAL SALES (442)
26 2 General Service
27 3 General Service
912,672 38,925 23,447 0.1160 105,894,002 28 11 General Service
29 12 Res. & Farm Gen. Service
30 16 MOPS II Commercial
31 19 Contract-General Service
1,798,057 2,753 653,126 0.0922 165,813,643 32 21 Large General Service
355,813 13 27,370,231 0.0656 23,347,419 33 25 Extra Lg. Gen. Service
34 28 Contract-Extra Large Serv
103,943 1,239 83,893 0.0887 9,219,861 35 31 Pumping Service
4,958 0.2978 1,476,500 36 47 Area Lighting-Sod. Vap
2,276 0.2914 663,245 37 49 Area Lighting-High-Press.
38 56 Centralia Refune
62,161 39 95 Wind Power
40 74 Large General Service
11,958,237 891,569,430 390,059 30,658 0.0746
22,370 363,995 0 0 0.0163
11,935,867 891,205,435 390,059 30,600 0.0747
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
04/15/2020 2019/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
-42,146 4 58A Tax Adjustment
11,246,682 5 58 Tax Adjustment
3,177,719 42,930 74,021 0.1000 317,681,367 6 SubTotal
-7,688 0.0120 -92,198 7 Commercial-Unbilled
3,170,031 42,930 73,842 0.1002 317,589,169 8 Total Commercial
9
10 INDUSTRIAL SALES (442)
11 2 General Service
12 3 General Service
13 8 Lg Gen Time of Use
11,445 246 46,524 0.1160 1,327,097 14 11 General Service
15 12 Res. & Farm Gen. Service
157,201 133 1,181,962 0.0916 14,397,198 16 21 Large General Service
1,753,119 21 83,481,857 0.0510 89,491,163 17 25 Extra Lg. Gen. Service
18 28 Contract - Extra Large Service
19 29 Contract Lg. Gen. Service
29,640 49 604,898 0.0746 2,209,918 20 30 Pumping Service - Special
52,432 728 72,022 0.0915 4,798,785 21 31 Pumping Service
4,043 128 31,586 0.0933 377,184 22 32 Pumping Svc Res & Firm
140 0.2552 35,734 23 47 Area Lighting-Sod. Vap.
57 0.2803 15,975 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
-1,404 32 58A Tax Adjustment
890,017 33 58 Tax Adjustment
2,008,077 1,305 1,538,756 0.0565 113,542,507 34 SubTotal
39,151 0.0252 988,023 35 Industrial-Unbilled
2,047,228 1,305 1,568,757 0.0559 114,530,530 36 Total Industrial
37
38 STREET AND HWY LIGHTING (444)
39 6 Mercury Vapor St. Ltg.
40 7 HP Sodium Vap. St. Ltg
11,958,237 891,569,430 390,059 30,658 0.0746
22,370 363,995 0 0 0.0163
11,935,867 891,205,435 390,059 30,600 0.0747
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
04/15/2020 2019/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
50 6 8,333 0.2305 11,523 2 41 Co-Owned St. Lt. Service
14,769 505 29,246 0.4631 6,839,291 3 42 Co-Owned St. Lt. Service
4 High-Press. Sod. Vap.
5 43 Cust-Owned St. Lt. Energy
6 and Maint. Service
384 25 15,360 0.1667 64,030 7 44 Cust-Owned St. Lt. Energy
8 and Maint. Svce - High-Pres
9 Sodium Vapor
778 14 55,571 0.0826 64,245 10 45 Cust. Owned St. Lt. Energy Svc
1,992 62 32,129 0.1053 209,797 11 46 Cust. Owned St. Lt. Energy Svc
-718 12 58A Tax Adjustment
259,468 13 58 Tax Adjustment
17,973 612 29,368 0.4144 7,447,636 14 SubTotal
15 Street & Hwy Lighting-Unbilled
17,973 612 29,368 0.4144 7,447,636 16 Total Street & Hwy Lighting
17
18 OTHER SALES TO PUBLIC
19 (445)
20 None
21
14,708 148 99,378 0.1021 1,501,430 22 INTERDEPARTMENTAL SALES
857 23 58 Tax Adjustment
14,708 148 99,378 0.1021 1,502,287 24 Total Interdepartmental
25
26 SALES FOR RESALE (447)
2,942,248 0.0277 81,398,279 27 61 Sales to Other Utilities (NDA)
28
29
2,942,248 0.0277 81,398,279 30 Total Sales for Resale
31
32
33
34
35
36
37
38
39
40
11,958,237 891,569,430 390,059 30,658 0.0746
22,370 363,995 0 0 0.0163
11,935,867 891,205,435 390,059 30,600 0.0747
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 04/15/2020 2019/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 9SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
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 04/15/2020 2019/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.
8,676,272 8,676,272 243,539 1
694,290 694,290 2
1,187 1,187 41 3
276,400 276,400 4,000 4
28,083 28,083 1,565 5
986,706 986,706 24,213 6
97,288 97,288 2,596 7
3,425,000 3,425,000 80,740 8
1,979 1,979 56 9
178 178 5 10
624,514 624,514 20,030 11
10,524,687 10,524,687 272,928 12
1,370,132 1,370,132 46,700 13
70,000 70,000 400 14
FERC FORM NO. 1 (ED. 12-90) Page 311
0
90,106,545
90,106,545
0
2,942,248
2,942,248
0 0
-11,550,289
-11,550,289
81,398,279
81,398,279
0
2,842,023
2,842,023
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 04/15/2020 2019/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.
Chelan County PUD No. 1 Tariff 12LF 1
Citigroup Energy, Inc. Tariff 9SF 2
Clatskanie Peoples PUD Tariff 9SF 3
ConocoPhillips Tariff 9SF 4
Direct Energy Business Marketing, LLC Tariff 9LF 5
Douglas County PUD No. 1 Tariff 9SF 6
Douglas County PUD No. 1 Tariff 12LF 7
EDF Trading North America, LLC Tariff 9SF 8
Energy Keepers, Inc. Tariff 9SF 9
Eugene Water & Electric Board Tariff 9SF 10
Evergy Kansas Central, Inc Tariff 9SF 11
Exelon Generation Company, LLC Tariff 9SF 12
Grant County PUD No. 2 Tariff 12LF 13
Gridforce Energy Management, LLC 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 04/15/2020 2019/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.
132 132 5 1
1,679,401 1,679,401 19,552 2
66,639 66,639 2,051 3
1,996,682 1,996,682 67,740 4
7,076,862 7,076,862 183,998 5
1,225,885 1,225,885 26,790 6
12 12 4 7
4,227,794 4,227,794 137,664 8
662,950 662,950 27,554 9
792,463 792,463 17,110 10
55,450 55,450 2,200 11
1,378,170 1,378,170 26,105 12
21 21 2 13
12,455 12,455 364 14
FERC FORM NO. 1 (ED. 12-90) Page 311.1
0
90,106,545
90,106,545
0
2,942,248
2,942,248
0 0
-11,550,289
-11,550,289
81,398,279
81,398,279
0
2,842,023
2,842,023
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 04/15/2020 2019/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 Tariff 9SF 1
Idaho Power Company Tariff 12LF 2
Idaho Power Company Balancing Tariff 9SF 3
Idaho Power Company Balancing Tariff 9IF 4
Kootenai Electric Cooperative Tariff 8LF 5
Macquarie Energy, LLC Tariff 9SF 6
Macquarie Energy, LLC Tariff 9IF 7
Mizuho Securities USA, Inc. NAOS 8
Morgan Stanley Capital Group, Inc. Tariff 9SF 9
Morgan Stanley Capital Group, Inc. Tariff 9IF 10
Morgan Stanley Capital Group, Inc. Tariff 9IF 11
Morgan Stanley Capital Group, Inc. Tariff 9SF 12
Morgan Stanley Capital Group, Inc. Tariff 9SF 13
Morgan Stanley Capital Group, Inc. 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 04/15/2020 2019/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.
11,950 11,950 600 1
497 497 18 2
174,535 174,535 7,317 3
97,079 97,079 3,171 4
60,881 60,881 1,266 5
3,254,199 3,254,199 111,063 6
1,745 1,745 56 7
-13,487,622 -13,487,622 8
2,239,421 2,239,421 71,087 9
447,735 447,735 4,551 10
9,305,371 9,305,371 342,443 11
275,940 275,940 12
633,481 633,481 13
364,896 364,896 14
FERC FORM NO. 1 (ED. 12-90) Page 311.2
0
90,106,545
90,106,545
0
2,942,248
2,942,248
0 0
-11,550,289
-11,550,289
81,398,279
81,398,279
0
2,842,023
2,842,023
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 04/15/2020 2019/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.
NaturEner Power Watch, LLC Tariff 9LF 1
NaturEner Power Watch, LLC Tariff 9LF 2
NaturEner Power Watch, LLC Tariff 12LF 3
NaturEner Power Watch, LLC Tariff 9SF 4
Nevada Power Company Tariff 9SF 5
NorthWestern Energy LLC Tariff 9SF 6
Northwestern Energy LLC Tariff 9IF 7
NorthWestern Energy LLC Tariff 12LF 8
NorthWestern Energy LLC Tariff 9SF 9
NorthWestern Energy LLC Tariff 9LF 10
Okanogan County PUD Tariff 9SF 11
PacifiCorp Tariff 9SF 12
PacifiCorp Tariff 12LF 13
PacifiCorp Tariff 9LF 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 04/15/2020 2019/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.
373 373 5 1
8,111 8,111 173 2
3,148 3,148 121 3
45,602 45,602 4
214,120 214,120 2,085 5
3,022,208 3,022,208 88,646 6
16,140 16,140 353 7
1,194 1,194 40 8
2,360 2,360 9
252,854 252,854 7,067 10
482,300 482,300 12,045 11
5,284,535 5,284,535 138,095 12
6,724 6,724 199 13
160,907 160,907 4,500 14
FERC FORM NO. 1 (ED. 12-90) Page 311.3
0
90,106,545
90,106,545
0
2,942,248
2,942,248
0 0
-11,550,289
-11,550,289
81,398,279
81,398,279
0
2,842,023
2,842,023
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 04/15/2020 2019/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.
Pend Oreille Public Utility District Tariff 9IF 1
Pend Oreille Public Utility District Tariff 9IF 2
Pend Oreille Public Utility District Tariff 9IF 3
Pend Oreille Public Utility District Tariff 9SF 4
Portland General Electric Company Tariff 9SF 5
Portland General Electric Company Tariff 12LF 6
Powerex Tariff 9SF 7
Powerex Tariff 9IF 8
Puget Sound Energy Tariff 9LF 9
Puget Sound Energy Tariff 9SF 10
Puget Sound Energy Tariff 12LF 11
Rainbow Energy Marketing Tariff 9SF 12
Rainbow Energy Marketing Tariff 9IF 13
Sacramento Municipal Utility District Tariff 12LF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.4
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
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 04/15/2020 2019/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.
665,451 665,451 1
9,561 9,561 229 2
587,710 587,710 17,975 3
2,505,153 2,505,153 64,469 4
3,461,422 3,461,422 98,505 5
3,112 3,112 91 6
3,636,844 3,636,844 100,365 7
1,871 1,871 166 8
735,574 735,574 20,562 9
6,311,973 6,311,973 146,470 10
694 694 16 11
19,600 19,600 200 12
37,514 37,514 189 13
463 463 15 14
FERC FORM NO. 1 (ED. 12-90) Page 311.4
0
90,106,545
90,106,545
0
2,942,248
2,942,248
0 0
-11,550,289
-11,550,289
81,398,279
81,398,279
0
2,842,023
2,842,023
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 04/15/2020 2019/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.
Seattle City Light Tariff 9SF 1
Seattle City Light Tariff 9LF 2
Seattle City Light Tariff 12LF 3
Shell Energy N.A. Tariff 9SF 4
Shell Energy N.A. Tariff 9SF 5
Sierra Pacific Power Company Tariff 12LF 6
Snohomish County PUD Tariff 9SF 7
Sovereign Power Tariff 9LF 8
Sovereign Power Tariff 9LF 9
Tacoma Power Tariff 9SF 10
Tacoma Power Tariff 9LF 11
Tacoma Power Tariff 12LF 12
Talen Energy Montana, LLC Tariff 9LF 13
Tenaska Power Services Co. Tariff 9SF 14
FERC FORM NO. 1 (ED. 12-90) Page 310.5
0
0
0
Subtotal RQ
Subtotal non-RQ
Total
0 0
0
0
0
0
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 04/15/2020 2019/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.
408,165 408,165 12,020 1
9,302 9,302 445 2
54 54 3 3
3,443,327 3,443,327 122,961 4
10,935 10,935 5
117 117 5 6
2,674,320 2,674,320 36,063 7
149,068 149,068 8
438,066 438,066 13,629 9
286,293 286,293 10,998 10
29,440 29,440 1,287 11
153 153 4 12
574,667 574,667 16,063 13
10,275 10,275 228 14
FERC FORM NO. 1 (ED. 12-90) Page 311.5
0
90,106,545
90,106,545
0
2,942,248
2,942,248
0 0
-11,550,289
-11,550,289
81,398,279
81,398,279
0
2,842,023
2,842,023
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 04/15/2020 2019/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.
The Energy Authority Tariff 9SF 1
The Energy Authority Tariff 9IF 2
TransAlta Energy Marketing Tariff 9SF 3
TransAlta Energy Marketing Tariff 9IF 4
Turlock Irrigation Dist Tariff 9SF 5
Vitol, Inc. Tariff 9SF 6
Wells Fargo securities, LLC NAOS 7
Western Area Power Admin Tariff 12LF 8
IntraCompany Wheeling LF 9
IntraCompany Generation LF 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 04/15/2020 2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g)(j)
Demand Charges Energy Charges Other Charges
(k)
Sold (h+i+j)Total ($)REVENUE
($)($)($)
OS - for other service. use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature of
the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ" in
column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter "Total''
in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5. In Column (c), identify the FERC Rate Schedule or Tariff Number. On separate Lines, List all FERC rate schedules or tariffs under
which service, as identified in column (b), is provided.
6. For requirements RQ sales and any type of-service involving demand charges imposed on a monthly (or Longer) basis, enter the
average monthly billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP)
demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP demand is the maximum
metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during the hour (60-minute
integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must be in megawatts.
Footnote any demand not stated on a megawatt basis and explain.
7. Report in column (g) the megawatt hours shown on bills rendered to the purchaser.
8. Report demand charges in column (h), energy charges in column (i), and the total of any other types of charges, including
out-of-period adjustments, in column (j). Explain in a footnote all components of the amount shown in column (j). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9. The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on the
Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page 401,
line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page 401,iine 24.
10. Footnote entries as required and provide explanations following all required data.
1,619,283 1,619,283 35,152 1
1,270 1,270 32 2
7,740,556 7,740,556 233,284 3
6,405 6,405 122 4
885 885 45 5
289,550 289,550 7,800 6
-15,619,811 -15,619,811 7
44 44 2 8
-15,040,487 15,040,487 9
2,516,657 2,516,657 10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 311.6
0
90,106,545
90,106,545
0
2,942,248
2,942,248
0 0
-11,550,289
-11,550,289
81,398,279
81,398,279
0
2,842,023
2,842,023
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: 310.1 Line No.: 1 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 5 Column: b
Contract terminates December 31, 2019.
Schedule Page: 310.1 Line No.: 7 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 11 Column: a
Formerly Westar Energy, Inc. Name changed to Evergy Kansas Central, Inc. on 10/09/2019.
Schedule Page: 310.1 Line No.: 13 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.1 Line No.: 14 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.2 Line No.: 2 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.2 Line No.: 4 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.2 Line No.: 5 Column: b
Kootenai Contract Terminates March 31,2024
Schedule Page: 310.2 Line No.: 7 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.2 Line No.: 8 Column: b
Financial SWAP
Schedule Page: 310.2 Line No.: 10 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.2 Line No.: 11 Column: b
Resource Contingent Bundled REC - Energy and Green Attributes 03/01/2019-12/31/2023.
Schedule Page: 310.2 Line No.: 12 Column: b
Capacity
Schedule Page: 310.2 Line No.: 13 Column: b
Capacity
Schedule Page: 310.2 Line No.: 14 Column: b
Reserves
Schedule Page: 310.3 Line No.: 1 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.3 Line No.: 2 Column: b
Energy Associated with Dynamic Capacity and Energy Service Agreement
Schedule Page: 310.3 Line No.: 3 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.3 Line No.: 4 Column: b
Capacity
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 310.3 Line No.: 7 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.3 Line No.: 8 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.3 Line No.: 9 Column: b
Reserves
Schedule Page: 310.3 Line No.: 10 Column: b
NorthWestern Energy LLC sale expires October 31, 2023.
Schedule Page: 310.3 Line No.: 13 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.3 Line No.: 14 Column: b
PacifiCorp sale terminates October 31, 2023.
Schedule Page: 310.4 Line No.: 1 Column: b
Contract expires 9/30/2021.
Schedule Page: 310.4 Line No.: 2 Column: b
Contract expires 9/30/2021.
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.: 9 Column: b
Puget Sound Energy sale terminates October 31, 2023.
Schedule Page: 310.4 Line No.: 11 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.4 Line No.: 13 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.4 Line No.: 14 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 2 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.5 Line No.: 3 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 5 Column: b
Reserves
Schedule Page: 310.5 Line No.: 6 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 8 Column: b
Sovereign Power contract terminates 9-30-2021
Schedule Page: 310.5 Line No.: 9 Column: b
Sovereign Power Contract terminates 9-30-2021
Schedule Page: 310.5 Line No.: 11 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.5 Line No.: 12 Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 13 Column: b
Talen Energy sale terminates October 31,2023.
Schedule Page: 310.6 Line No.: 2 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.6 Line No.: 4 Column: b
Financially Settled Transmission Losses
Schedule Page: 310.6 Line No.: 7 Column: b
Financial SWAP
Schedule Page: 310.6 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)
04/15/2020
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.2
Schedule Page: 310.6 Line No.: 9 Column: b
IntraCompany Wheeling terminates 09/30/2023.
Schedule Page: 310.6 Line No.: 10 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)
04/15/2020
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.3

This Page Intentionally Left Blank
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
04/15/2020 2019/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 4 345,980 355,496
(501) Fuel 5 27,775,865 30,554,741
(502) Steam Expenses 6 4,055,476 3,760,759
(503) Steam from Other Sources 7
(Less) (504) Steam Transferred-Cr. 8
(505) Electric Expenses 9 934,119 888,160
(506) Miscellaneous Steam Power Expenses 10 3,306,135 3,107,546
(507) Rents 11 34,621 15,079
(509) Allowances 12
TOTAL Operation (Enter Total of Lines 4 thru 12) 13 36,452,196 38,681,781
Maintenance 14
(510) Maintenance Supervision and Engineering 15 479,496 506,378
(511) Maintenance of Structures 16 529,070 759,694
(512) Maintenance of Boiler Plant 17 5,335,916 5,794,165
(513) Maintenance of Electric Plant 18 1,458,737 638,851
(514) Maintenance of Miscellaneous Steam Plant 19 466,688 1,222,605
TOTAL Maintenance (Enter Total of Lines 15 thru 19) 20 8,269,907 8,921,693
TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 21 44,722,103 47,603,474
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 2,619,276 2,754,616
(536) Water for Power 45 1,156,275 930,038
(537) Hydraulic Expenses 46 8,434,948 9,607,953
(538) Electric Expenses 47 5,741,274 5,884,654
(539) Miscellaneous Hydraulic Power Generation Expenses 48 1,148,251 1,070,877
(540) Rents 49 6,344,885 6,428,232
TOTAL Operation (Enter Total of Lines 44 thru 49) 50 25,444,909 26,676,370
C. Hydraulic Power Generation (Continued) 51
Maintenance 52
(541) Mainentance Supervision and Engineering 53 1,152,932 792,626
(542) Maintenance of Structures 54 406,234 657,326
(543) Maintenance of Reservoirs, Dams, and Waterways 55 2,130,811 1,636,470
(544) Maintenance of Electric Plant 56 3,020,296 2,824,428
(545) Maintenance of Miscellaneous Hydraulic Plant 57 1,154,554 947,013
TOTAL Maintenance (Enter Total of lines 53 thru 57) 58 7,864,827 6,857,863
TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 59 33,309,736 33,534,233
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
04/15/2020 2019/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 62 344,393 228,562
(547) Fuel 63 63,237,753 71,500,955
(548) Generation Expenses 64 2,286,764 2,231,850
(549) Miscellaneous Other Power Generation Expenses 65 350,643 1,254,645
(550) Rents 66 -33,822 47,044
TOTAL Operation (Enter Total of lines 62 thru 66) 67 66,185,731 75,263,056
Maintenance 68
(551) Maintenance Supervision and Engineering 69 585,982 651,663
(552) Maintenance of Structures 70 68,190 133,426
(553) Maintenance of Generating and Electric Plant 71 3,927,388 7,094,951
(554) Maintenance of Miscellaneous Other Power Generation Plant 72 358,281 426,816
TOTAL Maintenance (Enter Total of lines 69 thru 72) 73 4,939,841 8,306,856
TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 74 71,125,572 83,569,912
E. Other Power Supply Expenses 75
(555) Purchased Power 76 136,263,902 144,313,775
(556) System Control and Load Dispatching 77 598,799 660,144
(557) Other Expenses 78 75,953,261 48,105,794
TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 79 212,815,962 193,079,713
TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 80 361,973,373 357,787,332
2. TRANSMISSION EXPENSES 81
Operation 82
(560) Operation Supervision and Engineering 83 1,868,255 1,931,225
84
(561.1) Load Dispatch-Reliability 85 39,842 60,658
(561.2) Load Dispatch-Monitor and Operate Transmission System 86 1,045,793 1,227,913
(561.3) Load Dispatch-Transmission Service and Scheduling 87 1,017,880 1,002,020
(561.4) Scheduling, System Control and Dispatch Services 88
(561.5) Reliability, Planning and Standards Development 89 506,799 663,145
(561.6) Transmission Service Studies 90
(561.7) Generation Interconnection Studies 91
(561.8) Reliability, Planning and Standards Development Services 92
(562) Station Expenses 93 460,703 499,947
(563) Overhead Lines Expenses 94 438,645 370,882
(564) Underground Lines Expenses 95
(565) Transmission of Electricity by Others 96 17,529,488 17,252,820
(566) Miscellaneous Transmission Expenses 97 2,414,323 2,805,371
(567) Rents 98 189,784 170,983
TOTAL Operation (Enter Total of lines 83 thru 98) 99 25,511,512 25,984,964
Maintenance 100
(568) Maintenance Supervision and Engineering 101 538,347 499,807
(569) Maintenance of Structures 102 632,439 570,168
(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 107 697,405 823,646
(571) Maintenance of Overhead Lines 108 1,346,716 1,002,431
(572) Maintenance of Underground Lines 109 188 47
(573) Maintenance of Miscellaneous Transmission Plant 110 91,275 73,382
TOTAL Maintenance (Total of lines 101 thru 110) 111 3,306,370 2,969,481
TOTAL Transmission Expenses (Total of lines 99 and 111) 112 28,817,882 28,954,445
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
04/15/2020 2019/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 2,922,781 3,341,232
(581) Load Dispatching 135
(582) Station Expenses 136 688,490 768,839
(583) Overhead Line Expenses 137 2,245,066 2,206,002
(584) Underground Line Expenses 138 1,470,722 1,618,684
(585) Street Lighting and Signal System Expenses 139 4,104 5,265
(586) Meter Expenses 140 1,559,238 1,744,750
(587) Customer Installations Expenses 141 709,280 829,754
(588) Miscellaneous Expenses 142 6,977,162 7,149,060
(589) Rents 143 364,153 353,727
TOTAL Operation (Enter Total of lines 134 thru 143) 144 16,940,996 18,017,313
Maintenance 145
(590) Maintenance Supervision and Engineering 146 1,099,667 1,230,289
(591) Maintenance of Structures 147 384,683 532,672
(592) Maintenance of Station Equipment 148 721,467 769,884
(593) Maintenance of Overhead Lines 149 9,778,342 10,873,805
(594) Maintenance of Underground Lines 150 802,329 804,137
(595) Maintenance of Line Transformers 151 333,165 359,548
(596) Maintenance of Street Lighting and Signal Systems 152 181,548 158,130
(597) Maintenance of Meters 153 25,312 39,048
(598) Maintenance of Miscellaneous Distribution Plant 154 185,260 536,940
TOTAL Maintenance (Total of lines 146 thru 154) 155 13,511,773 15,304,453
TOTAL Distribution Expenses (Total of lines 144 and 155) 156 30,452,769 33,321,766
5. CUSTOMER ACCOUNTS EXPENSES 157
Operation 158
(901) Supervision 159 119,601 114,406
(902) Meter Reading Expenses 160 2,228,677 2,042,787
(903) Customer Records and Collection Expenses 161 7,653,010 7,885,571
(904) Uncollectible Accounts 162 2,043,405 208,808
(905) Miscellaneous Customer Accounts Expenses 163 225,469 159,633
TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 164 12,270,162 10,411,205
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
04/15/2020 2019/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 36,541,837 37,686,359
(909) Informational and Instructional Expenses 169 898,729 1,153,181
(910) Miscellaneous Customer Service and Informational Expenses 170 340,964 250,163
TOTAL Customer Service and Information Expenses (Total 167 thru 170) 171 37,781,530 39,089,703
7. SALES EXPENSES 172
Operation 173
(911) Supervision 174
(912) Demonstrating and Selling Expenses 175 58,715
(913) Advertising Expenses 176
(916) Miscellaneous Sales Expenses 177
TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 178 58,715
8. ADMINISTRATIVE AND GENERAL EXPENSES 179
Operation 180
(920) Administrative and General Salaries 181 25,654,940 25,372,504
(921) Office Supplies and Expenses 182 4,547,185 4,732,387
(Less) (922) Administrative Expenses Transferred-Credit 183 121,108 102,345
(923) Outside Services Employed 184 9,023,010 10,107,690
(924) Property Insurance 185 1,281,469 1,451,884
(925) Injuries and Damages 186 4,285,035 4,177,429
(926) Employee Pensions and Benefits 187 28,396,015 30,761,884
(927) Franchise Requirements 188 1,200 1,200
(928) Regulatory Commission Expenses 189 5,724,225 6,380,843
(929) (Less) Duplicate Charges-Cr. 190
(930.1) General Advertising Expenses 191
(930.2) Miscellaneous General Expenses 192 4,027,640 4,995,151
(931) Rents 193 417,575 312,788
TOTAL Operation (Enter Total of lines 181 thru 193) 194 83,237,186 88,191,415
Maintenance 195
(935) Maintenance of General Plant 196 11,842,584 12,182,064
TOTAL Administrative & General Expenses (Total of lines 194 and 196) 197 95,079,770 100,373,479
TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 198 566,434,201 569,937,930
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 04/15/2020 2019/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
Bonneville Power Administration WNP#3 Agr.LF 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
CP Energy Marketing (US) Inc. Tariff 9SF 13
California Independent System Operator 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 04/15/2020 2019/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.
1,644,997 1,644,997 1 42,346
2,102,503 2,102,503 2 107,344
50 50 3 2
7,500 7,500 4
36,000 36,000 5 48
7,910,918 7,910,918 6 173,447
3,426,240 3,426,240 7 159,197
3,750 3,750 8 131
938,351 938,351 9 24,264
35,417 35,417 10 1,657
36,322 36,322 11
158,324 158,324 12 2,776
27,515 27,515 13 366
960,967 960,967 14 21,707
FERC FORM NO. 1 (ED. 12-90) Page 327
5,344,702 9,046 429,475 27,343,304 126,812,614 -9,842,143 144,313,775
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 04/15/2020 2019/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.
Calpine Energy Services LP Tariff 9SF 1
City of Spokane PURPALU 2
City of Spokane PURPAIU 3
Chelan County PUD Rocky ReachIU 4
Chelan County PUD Rocky ReachIU 5
Chelan County PUD Tariff 9SF 6
Chelan County PUD NWPPLF 7
Chelan County PUD Chelan SysIU 8
Clark Fork Hydro PURPALU 9
Clatskanie PUD Tariff 9SF 10
Clearwater Paper Company PURPAIU 11
Clearwater Power Company NARQ 12
Community Solar PURPALU 13
ConocoPhillips Company Tariff 9SF 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 04/15/2020 2019/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.
448,093 448,093 1 13,452
2,141,849 2,141,849 2 37,550
5,574,934 5,574,934 3 121,032
4 2,603
5 -23,972
686,900 686,900 6 24,216
50 50 7 2
15,276,675 15,276,675 8 380,706
50,030 50,030 9 868
8,796 8,796 10 704
8,728,076 8,728,076 11 356,248
13,888 13,888 12 147
27,282 27,282 13 561
506,200 506,200 14 15,600
FERC FORM NO. 1 (ED. 12-90) Page 327.1
5,344,702 9,046 429,475 27,343,304 126,812,614 -9,842,143 144,313,775
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 04/15/2020 2019/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.
Deep Creek Energy, LLC PURPAIU 1
Direct Energy Business Marketing, LLC Tariff 9SF 2
Douglas County PUD No. 1 WellsLU 3
Douglas County PUD No. 1 Tariff 9SF 4
Douglas County PUD No. 1 Tariff9SF 5
Douglas County PUD No. 1 NWPPLF 6
Douglas County PUD No. 1 Tariff 9EX 7
EDF Trading No America Tariff 9SF 8
Enel X North America, Inc. PURPALU 9
Energy Keepers, Inc. Tariff 9SF 10
Eugene Water & Electric Board Tariff 9SF 11
Exelon Generation Company, LLC Tariff 9SF 12
Exelon Generation Company, LLC Tariff 9OS 13
Ford Hydro Limited Partnership PURPALU 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 04/15/2020 2019/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.
5,579 5,579 1 163
168,000 168,000 2 960
2,629,006 2,629,006 3 366,833
1,202,991 1,202,991 4 44,293
38,166 38,166 5
50 50 6 2
420,480 281,629 281,629 7
453,006 453,006 8 12,565
9 1
1,980 1,980 10 90
24,427 24,427 11 1,217
576,155 576,155 12 26,826
125 125 13
222,047 222,047 14 3,805
FERC FORM NO. 1 (ED. 12-90) Page 327.2
5,344,702 9,046 429,475 27,343,304 126,812,614 -9,842,143 144,313,775
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 04/15/2020 2019/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.
Grant County PUD No. 2 Priest RapidsLU 1
Grant County PUD No. 2 NWPPLF 2
Grant County PUD No. 2 FERC #104EX 3
Gridforce Energy Management, LLC NWPPLF 4
Hydro Technology Systems PURPAIU 5
Idaho County Power & Light PURPALU 6
Idaho Power Company Tariff 9SF 7
Idaho Power Company Tariff 9IF 8
Idaho Power Company Balancing Tariff 9SF 9
Inland Power & Light Company 208RQ 10
Kootenai Electric Cooperative Tariff 8LF 11
Macquarie Energy LLC Tariff 9SF 12
Mizuho Securities USA, Inc. NAOS 13
Morgan Stanley Capital Group Tariff 9SF 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 04/15/2020 2019/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.
9,437,623 9,437,623 1 279,934
177 177 2 7
-27,255 -27,255 3
154 154 4 5
484,804 484,804 5 8,903
141,730 141,730 6 2,752
10,099,644 10,099,644 7 170,895
10,496 10,496 8 85
70,122 70,122 9 5,862
10,153 10,153 10 139
46,732 46,732 11 1,235
1,701,134 1,701,134 12 39,822
-4,240,268 -4,240,268 13
1,430,945 1,430,945 14 37,315
FERC FORM NO. 1 (ED. 12-90) Page 327.3
5,344,702 9,046 429,475 27,343,304 126,812,614 -9,842,143 144,313,775
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 04/15/2020 2019/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.
Nevada Power Company Tariff 9SF 1
Nevada Power Company Tariff 9IF 2
NextEra Energy Power Marketing LLC Tariff 9SF 3
NorthWestern Energy LLC Tariff 9SF 4
NorthWestern Energy LLC NWPPLF 5
NorthWestern Energy LLC Tariff 9IF 6
Okanogan County PUD No. 1 Tariff 9SF 7
PacifiCorp Tariff 9SF 8
PacifiCorp NWPPLF 9
PacifiCorp Tariff 9IF 10
Palouse Wind LLC PPALU 11
Pend Oreille County PUD No. 1 Pend O'SF 12
Pend Oreille County PUD No. 1 Pend O'IF 13
Pend Oreille County PUD No. 1 Pend O'IF 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 04/15/2020 2019/Q4
Line
No.
MegaWatt Hours
(i)(h)(g) (j)
Demand Charges Energy Charges Other Charges
(k)
Purchased (j+k+l)Total
COST/SETTLEMENT OF POWER
($) ($) ($)
(Including power exchanges)
POWER EXCHANGES
MegaWatt Hours
Received
MegaWatt Hours
Delivered (l) (m)of Settlement ($)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4. In column (c), identify the FERC Rate Schedule Number or Tariff, or, for non-FERC jurisdictional sellers, include an appropriate
designation for the contract. On separate lines, list all FERC rate schedules, tariffs or contract designations under which service, as
identified in column (b), is provided.
5. For requirements RQ purchases and any type of service involving demand charges imposed on a monnthly (or longer) basis, enter the
monthly average billing demand in column (d), the average monthly non-coincident peak (NCP) demand in column (e), and the average
monthly coincident peak (CP) demand in column (f). For all other types of service, enter NA in columns (d), (e) and (f). Monthly NCP
demand is the maximum metered hourly (60-minute integration) demand in a month. Monthly CP demand is the metered demand during
the hour (60-minute integration) in which the supplier's system reaches its monthly peak. Demand reported in columns (e) and (f) must
be in megawatts. Footnote any demand not stated on a megawatt basis and explain.
6. Report in column (g) the megawatthours shown on bills rendered to the respondent. Report in columns (h) and (i) the megawatthours
of power exchanges received and delivered, used as the basis for settlement. Do not report net exchange.
7. Report demand charges in column (j), energy charges in column (k), and the total of any other types of charges, including
out-of-period adjustments, in column (l). Explain in a footnote all components of the amount shown in column (l). Report in column (m)
the total charge shown on bills received as settlement by the respondent. For power exchanges, report in column (m) the settlement
amount for the net receipt of energy. If more energy was delivered than received, enter a negative amount. If the settlement amount (l)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be reported
as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401, line 12. The
total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
2,012 2,012 1
58 58 2 1
77,200 77,200 3 2,600
638,867 638,867 4 19,769
488 488 5 18
13,765 13,765 6 433
227,687 227,687 7 9,170
1,670,097 1,670,097 8 48,980
990 990 9 35
28,839 28,839 10 947
18,596,471 18,596,471 11 302,136
3,404,731 3,404,731 12 116,842
441,253 441,253 13 16,380
204,627 204,627 14 6,712
FERC FORM NO. 1 (ED. 12-90) Page 327.4
5,344,702 9,046 429,475 27,343,304 126,812,614 -9,842,143 144,313,775
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 04/15/2020 2019/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.
Phillips Ranch PURPALU 1
Portland General Electric Company Tariff 9EX 2
Portland General Electric Company Tariff 9SF 3
Portland General Electric Company NWPPLF 4
Portland General Electric Company Tariff 9IF 5
Powerex Corp Tariff 9SF 6
Puget Sound Energy Tariff 9SF 7
Puget Sound Energy NWPPLF 8
Puget Sound Energy Tariff 9IF 9
Rathdrum Power LLC LancasterLU 10
Seattle City Light Tariff 9SF 11
Seattle City Light NWPPLF 12
Sheep Creek Hydro PURPALU 13
Shell Energy 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 04/15/2020 2019/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.
689 689 1 25
8,995 8,996 2
2,798,915 2,798,915 3 56,060
818 818 4 30
272,044 272,044 5 9,016
4,919,827 4,919,827 6 101,729
3,064,624 3,064,624 7 72,572
839 839 8 31
2,013 2,013 9 56
28,176,399 28,176,399 10 1,798,402
309,515 309,515 11 13,435
358 358 12 13
284,579 284,579 13 6,436
2,661,302 2,661,302 14 97,508
FERC FORM NO. 1 (ED. 12-90) Page 327.5
5,344,702 9,046 429,475 27,343,304 126,812,614 -9,842,143 144,313,775
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 04/15/2020 2019/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.
Snohomish County PUD No. 1 Tariff 9SF 1
Sovereign Power SovereignLF 2
Spokane County PURPALU 3
Stimson Lumber PURPAIU 4
Tacoma Power Tariff 9SF 5
Tacoma Power NWPPLF 6
Talen Energy Marketing Tariff 9SF 7
Temp Diesel PURPAIU 8
The City of Cove PURPALU 9
The Energy Authority Tariff 9SF 10
TransAlta Energy Marketing Tariff 9SF 11
Turlock Irrigation District Tariff 9SF 12
Vitol Inc. Tariff 9SF 13
Wells Fargo Securities, LLC NAOS 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 04/15/2020 2019/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.
397,755 397,755 1 18,540
204,372 204,372 2 7,539
57,203 57,203 3 1,283
1,940,817 1,940,817 4 37,288
227,820 227,820 5 8,255
80 80 6 3
-3,200 -3,200 7 -80
8 103
115,739 115,739 9 2,716
382,209 382,209 10 14,585
3,220,607 3,220,607 11 94,122
40,933 40,933 12 4,901
253,650 253,650 13 8,600
-8,416,853 -8,416,853 14
FERC FORM NO. 1 (ED. 12-90) Page 327.6
5,344,702 9,046 429,475 27,343,304 126,812,614 -9,842,143 144,313,775
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 04/15/2020 2019/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.
Western Area Power Admin-Sierra Nev Re Tariff 9SF 1
IntraCompany Generation Services OATTOS 2
Other - Inadvertent Interchange EX 3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 326.7
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 04/15/2020 2019/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.
56,000 56,000 1 800
2,516,657 2,516,657 2
50 3
4
5
6
7
8
9
10
11
12
13
14
FERC FORM NO. 1 (ED. 12-90) Page 327.7
5,344,702 9,046 429,475 27,343,304 126,812,614 -9,842,143 144,313,775
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.: 6 Column: a
BPA Contract Terminates June 30, 2019
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.: 7 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.1 Line No.: 12 Column: a
Service to Ahsahka, Idaho from Clearwater Power Company. No demand charges associated
with the agreement.
Schedule Page: 326.2 Line No.: 5 Column: a
Dutch Henry Energy Imbalance
Schedule Page: 326.2 Line No.: 6 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.2 Line No.: 7 Column: a
Exchange
Schedule Page: 326.2 Line No.: 13 Column: a
Pondage
Schedule Page: 326.3 Line No.: 2 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.3 Line No.: 4 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.3 Line No.: 8 Column: a
Financially Settled Transmission Losses
Schedule Page: 326.3 Line No.: 10 Column: a
Service to Deer Lake from Inland Power and Light. No demand charges associated with the
agreement.
Schedule Page: 326.3 Line No.: 11 Column: a
Kootenai Contract Terminates March 31, 2024
Schedule Page: 326.3 Line No.: 13 Column: a
Financial SWAP
Schedule Page: 326.4 Line No.: 1 Column: a
Energy Imbalance Charges
Schedule Page: 326.4 Line No.: 2 Column: a
Financially Settled Transmission Losses
Schedule Page: 326.4 Line No.: 5 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.4 Line No.: 6 Column: a
Financially Settled Transmission Losses
Schedule Page: 326.4 Line No.: 9 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.4 Line No.: 10 Column: a
Financially Settled Transmission Losses
Name of Respondent
Avista Corporation
This Report is:
(1) X An Original
(2) A Resubmission
Date of Report
(Mo, Da, Yr)
04/15/2020
Year/Period of Report
2019/Q4
FOOTNOTE DATA
FERC FORM NO. 1 (ED. 12-87)Page 450.1
Schedule Page: 326.4 Line No.: 13 Column: a
Pend Oreille County PUD contract expires 09/30/2021. Deviation Energy.
Schedule Page: 326.5 Line No.: 4 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.5 Line No.: 5 Column: a
Financially Settled Transmission Losses
Schedule Page: 326.5 Line No.: 8 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.5 Line No.: 9 Column: a
Financially Settled Transmission Losses
Schedule Page: 326.5 Line No.: 12 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.6 Line No.: 2 Column: a
Sovereign Contract Terminates September 30, 2021. Deviation Energy.
Schedule Page: 326.6 Line No.: 6 Column: a
Reserve Sharing under the NorthWest Power Pool Reserve Sharing Agreement.
Schedule Page: 326.6 Line No.: 14 Column: a
Financial SWAP
Schedule Page: 326.7 Line No.: 2 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)
04/15/2020
Year/Period of Report
2019/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 04/15/2020 2019/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
EDF Trading N.A. LLC Avista Corporation NorthWestern Energy NF 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
EDF Trading N.A. LLC NorthWestern Energy Idaho Power Company NF 17
Morgan Stanley Capital Group Avista Corporation NorthWestern Energy SFP 18
Morgan Stanley Capital Group Bonneville Power Administration Idaho Power Company 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 Chelan County PUD Idaho Power Company SFP 26
Morgan Stanley Capital Group Chelan County PUD NorthWestern Energy SFP 27
Idaho Power Company Chelan County PUD Idaho Power Company NF 28
PacifiCorp PacifiCorp PacifiCorp SFP 29
Idaho Power Company Avista Corporation Idaho Power Company SFP 30
Idaho Power Company Avista Corporation Idaho Power Company NF 31
Idaho Power Company Bonneville Power Administration Idaho Power Company SFP 32
Macquarie Energy LLC Grant County PUD Idaho Power Company NF 33
Idaho Power Company PacifiCorp Idaho Power Comany 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 04/15/2020 2019/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 GulchFERC No. 182 Dry Gulch 58,319 58,319 1
Chelan-StratfordFERC Trf No. 8 Stratford 205,669 205,669 2
Chelan-StratfordFERC Trf No. 8 Stratford 205,654 205,654 3
StratfordFERC No. 104 Coulee City/Wilson 90,110 90,110 4
AVA.BPATFERC Trf No. 8 AVA.SYS 3 2,809 2,809 5
AVA.BPATFERC Trf No. 8 AVA.SYS 3 3,702 3,702 6
AVA.BPATFERC Trf No. 8 AVA.SYS 4 6,370 6,370 7
AVA.BPATFERC Trf No. 8 AVA.SYS 2,029,368 2,029,368 8
9
10
11
FERC Trf No. 8 15 15 12
13
FERC Trf No. 8 563 563 14
FERC Trf No. 8 12,209 12,209 15
FERC Trf No. 8 25 25 16
FERC Trf No. 8 1,421 1,421 17
FERC Trf No. 8 12 12 18
FERC Trf No. 8 9,456 9,456 19
FERC Trf No. 8 258 258 20
FERC Trf No. 8 28,590 28,590 21
FERC Trf No. 8 38,171 38,171 22
FERC Trf No. 8 880 880 23
FERC Trf No. 8 8,421 8,421 24
FERC Trf No. 8 24 24 25
FERC Trf No. 8 5,291 5,291 26
FERC Trf No. 8 35 35 27
FERC Trf No. 8 200 200 28
FERC Trf No. 8 3,090 3,090 29
FERC Trf No. 8 1,060 1,060 30
FERC Trf No. 8 1,088 1,088 31
FERC Trf No. 8 69,420 69,420 32
FERC Trf No. 8 15 15 33
FERC Trf No. 8 800 800 34
FERC FORM NO. 1 (ED. 12-90) Page 329
13 3,689,993 3,689,993
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 04/15/2020 2019/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.
277,574 277,574 1
142,906 233,134 90,228 2
223,038 298,228 75,190 3
27,567 27,567 4
28,800 35,210 6,410 5
10,800 16,547 5,747 6
32,160 41,459 9,299 7
6,414,865 8,885,101 2,470,236 8
27,973 27,973 9
9,480 9,480 10
6,120 6,120 11
144 144 12
604 604 13
2,425 2,425 14
51,518 51,518 15
128 128 16
8,218 8,218 17
81 81 18
41,838 41,838 19
1,322 1,322 20
143,303 143,303 21
243,557 243,557 22
6,741 6,741 23
42,289 42,289 24
123 123 25
27,209 27,209 26
179 179 27
1,155 1,155 28
24,367 24,367 29
2,923 2,923 30
8,303 8,303 31
231,315 231,315 32
130 130 33
3,084 3,084 34
FERC FORM NO. 1 (ED. 12-90) Page 330
12,692,240 16,342,482 3,650,242 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 04/15/2020 2019/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
Douglas County PUD Bonneville Power Administration Avista Corporation NF 2
EDF Trading N.A. LLC Bonneville Power Administration NorthWestern Energy NF 3
EDF Trading N.A. LLC Avista Corporation Bonneville Power Administration NF 4
Bonneville Power Administration Bonneville Power Administration Avista Corporation 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 NorthWestern Energy Grant County PUD SFP 13
Shell Energy North America (US) LP NorthWestern Energy Bonneville Power Administration 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
Morgan Stanley Capital Group NorthWestern Energy Chelan County PUD NF 18
Morgan Stanley Capital Group NorthWestern Energy Idaho Power Company NF 19
Morgan Stanley Capital Group NorthWestern Energy Grant County PUD NF 20
Morgan Stanley Capital Group Idaho Power Company Chelan County PUD NF 21
Morgan Stanley Capital Group Idaho Power Company NorthWestern Energy 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
Energy Keepers Inc. NorthWestern Energy Idaho Power Company 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 04/15/2020 2019/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 6,213 6,213 1
FERC Trf No. 8 2,242 2,242 2
FERC Trf No. 8 2,661 2,661 3
FERC Trf No. 8 31 31 4
FERC Trf No. 8 6,512 6,512 5
FERC Trf No. 8 24,064 24,064 6
FERC Trf No. 8 25 25 7
FERC Trf No. 8 55 55 8
FERC Trf No. 8 670 670 9
FERC Trf No. 8 7,617 7,617 10
AVA.SYSFERC Trf No. 8 LOLO 3 14,682 14,682 11
FERC Trf No. 8 249 249 12
FERC Trf No. 8 7,960 7,960 13
FERC Trf No. 8 505 505 14
FERC Trf No. 8 11,811 11,811 15
FERC Trf No. 8 3,064 3,064 16
FERC Trf No. 8 15,330 15,330 17
FERC Trf No. 8 1,268 1,268 18
FERC Trf No. 8 13,329 13,329 19
FERC Trf No. 8 785 785 20
FERC Trf No. 8 77 77 21
FERC Trf No. 8 491 491 22
FERC Trf No. 8 2 2 23
FERC Trf No. 8 6,005 6,005 24
FERC Trf No. 8 1,581 1,581 25
FERC Trf No. 8 4,015 4,015 26
FERC Trf No. 8 1,386 1,386 27
FERC Trf No. 8 30 30 28
FERC Trf No. 8 20,923 20,923 29
FERC Trf No. 8 4,947 4,947 30
FERC Trf No. 8 496 496 31
FERC Trf No. 8 31,545 31,545 32
FERC Trf No. 8 3,355 3,355 33
FERC Trf No. 8 4,343 4,343 34
FERC FORM NO. 1 (ED. 12-90) Page 329.1
13 3,689,993 3,689,993
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 04/15/2020 2019/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.
23,542 23,542 1
13,017 15,423 2,406 2
16,552 16,552 3
209 209 4
40,237 40,237 5
157,385 157,385 6
146 146 7
317 317 8
5,092 5,092 9
53,345 53,345 10
72,000 94,549 22,549 11
1,683 1,683 12
30,967 30,967 13
1,928 1,928 14
73,592 73,592 15
18,916 18,916 16
107,534 107,534 17
8,652 8,652 18
84,954 84,954 19
5,702 5,702 20
526 526 21
3,353 3,353 22
12 12 23
37,707 37,707 24
9,821 9,821 25
24,754 24,754 26
8,855 8,855 27
180 180 28
106,791 106,791 29
28,562 28,562 30
2,861 2,861 31
268,753 268,753 32
36,588 36,588 33
37,527 37,527 34
FERC FORM NO. 1 (ED. 12-90) Page 330.1
12,692,240 16,342,482 3,650,242 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 04/15/2020 2019/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
Morgan Stanley Capital Group Idaho Power Company Bonneville Power Administration NF 3
Shell Energy North America (US) LP Idaho Power Company Grant County PUD 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
Avangrid Renewables NorthWestern Energy Bonneville Power Administration 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
EDF Trading N.A. LLC NorthWestern Energy Bonneville Power Administration NF 13
Macquarie Energy LLC Bonneville Power Administration NorthWestern Energy NF 14
Idaho Power Company PacifiCorp Idaho Power Company NF 15
Macquarie Energy LLC Northwestern Energy Bonneville Power Administration NF 16
Morgan Stanley Capital Group Grant County PUD Bonneville Power Administration NF 17
NorthWestern Energy NorthWestern Energy Bonneville Power Administration NF 18
Transalta Energy Marketing Idaho Power Company PacifiCorp NF 19
PacifiCorp PacifiCorp Bonneville Power Company SFP 20
PacifiCorp NorthWestern Energy PacifiCorp NF 21
PacifiCorp PacifiCorp PacifiCorp NF 22
Portland General Electric NorthWestern Energy Portland General Electric NF 23
PacifiCorp Idaho Power Company Bonneville Power Administration SFP 24
Puget Sound Energy NorthWestern Energy Bonneville Power Administration NF 25
Powerex Bonneville Power Administration NorthWestern Energy NF 26
Powerex NorthWestern Energy Bonneville Power Administration NF 27
Powerex NorthWestern Energy Chelan County PUD NF 28
Rainbow Energy Marketing Corp NorthWestern Energy Bonneville Power Administration NF 29
Rainbow Energy Marketing Corp NorthWestern Energy Bonneville Power Administration SFP 30
Rainbow Energy Marketing Corp NorthWestern Energy Chelan County PUD SFP 31
The Energy Authority Bonneville Power Administration NorthWestern Energy NF 32
The Energy Authority NorthWestern Energy Bonneville Power Administration NF 33
Rainbow Energy Marketing Corp NorthWestern Energy Puget Sound 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 04/15/2020 2019/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 8,555 8,555 1
T1110 2
FERC Trf No. 8 461 461 3
FERC Trf No. 8 10,613 10,613 4
FERC Trf No. 8 30,471 30,471 5
FERC Trf No. 8 775 775 6
FERC Trf No. 8 7,123 7,123 7
FERC Trf No. 8 2,465 2,465 8
FERC Trf No. 8 423 423 9
FERC Trf No. 8 10
FERC Trf No. 8 475 475 11
FERC Trf No, 8 2,210 2,210 12
FERC Trf No. 8 258 258 13
FERC Trf No. 8 400 400 14
FERC Trf No. 8 3,256 3,256 15
FERC Trf No. 8 1,426 1,426 16
FERC Trf No. 8 392 392 17
FERC Trf No. 8 4,646 4,646 18
FERC Trf No. 8 50 50 19
FERC Trf No. 8 3,561 3,561 20
FERC Trf No. 8 1,600 1,600 21
FERC Trf No. 8 10,939 10,939 22
FERC Trf No. 8 1,846 1,846 23
FERC Trf No. 8 14,685 14,685 24
FERC Trf No. 8 4,087 4,087 25
FERC Trf No. 8 12 12 26
FERC Trf No. 8 399 399 27
FERC Trf No. 8 68 68 28
FERC Trf No. 8 1,443 1,443 29
FERC Trf No. 8 837 837 30
FERC Trf No. 8 446 446 31
FERC Trf No. 8 32
FERC Trf No. 8 122 122 33
FERC Trf No. 8 394 394 34
FERC FORM NO. 1 (ED. 12-90) Page 329.2
13 3,689,993 3,689,993
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 04/15/2020 2019/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.
62,597 62,597 1
924,000 924,000 2
4,416 4,416 3
61,609 61,609 4
181,668 181,668 5
4,472 4,472 6
44,559 44,559 7
14,253 14,253 8
3,000 3,000 9
231 231 10
3,464 3,464 11
12,779 12,779 12
1,506 1,506 13
2,308 2,308 14
22,882 22,882 15
5,919 5,919 16
2,677 2,677 17
40,681 40,681 18
289 289 19
27,690 27,690 20
9,232 9,232 21
104,645 104,645 22
10,667 10,667 23
54,658 54,658 24
20,898 20,898 25
69 69 26
2,629 2,629 27
457 457 28
19,501 19,501 29
3,225 3,225 30
1,718 1,718 31
58 58 32
704 704 33
1,518 1,518 34
FERC FORM NO. 1 (ED. 12-90) Page 330.2
12,692,240 16,342,482 3,650,242 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 04/15/2020 2019/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
Shell Energy North America (US) LP Idaho Power Company Bonneville Power Administration SFP 3
Shell Energy North America (US) LP Idaho Power Company 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
Macquarie Energy LLC Avista Corporation Bonneville Power Administration NF 7
NorthWestern Energy Avista Corporation NorthWestern Energy NF 8
PacifiCorp Idaho Power Company Bonneville Power Administration NF 9
PacifiCorp Avista Corporation Bonneville Power Administration NF 10
Morgan Stanley Capital Group Chelan County PUD Bonneville Power Administration NF 11
PacifiCorp Avista Corporation Idaho Power Company NF 12
The Energy Authority Idaho Power Company Bonneville Power Company NF 13
Morgan Stanley Capital Group NorthWestern Energy Avista Corporation SFP 14
Morgan Stanley Capital Group Idaho Power Company Bonneville Power Administration SFP 15
The Energy Authority Bonneville Power Administration Idaho Power Company NF 16
PacifiCorp NorthWestern Energy PacifiCorp SFP 17
PacifiCorp Idaho Power Company PacifiCorp SFP 18
Powerex Idaho Power Company Bonneville Power Administration NF 19
Powerex Idaho Power Company Chelan County PUD NF 20
Powerex Chelan County PUD NorthWestern Energy NF 21
The Energy Authority Bonneville Power Administration Avista Corporation SFP 22
The Energy Authority Idaho Power Company Grant County PUD SFP 23
The Energy Authority Idaho Power Company PacifiCorp SFP 24
The Energy Authority Idaho Power Company Puget Sound Energy SFP 25
The Energy Authority Idaho Power Company Douglas County PUD SFP 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 04/15/2020 2019/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. 8 595 595 1
FERC Trf No. 8 2,620 2,620 2
FERC Trf No. 8 39,860 39,860 3
FERC Trf No. 8 137,751 137,751 4
FERC Trf No. 8 7,904 7,904 5
FERC Trf No. 8 6,352 6,352 6
FERC Trf No. 8 27 27 7
FERC Trf No. 8 8
FERC Trf No. 8 915 915 9
FERC Trf No. 8 25 25 10
FERC Trf No. 8 216 216 11
FERC Trf No. 8 350 350 12
FERC Trf No. 8 559 559 13
FERC Trf No. 8 487 487 14
FERC Trf No. 8 2 2 15
FERC Trf No. 8 376 376 16
FERC Trf No. 8 24,170 24,170 17
FERC Trf No. 8 367,732 367,732 18
FERC Trf No. 8 700 700 19
FERC Trf No. 8 19 19 20
FERC Trf No. 8 298 298 21
FERC Trf No. 8 102 102 22
FERC Trf No. 8 200 200 23
FERC Trf No. 8 1,200 1,200 24
FERC Trf No. 8 1,581 1,581 25
FERC Trf No. 8 200 200 26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 329.3
13 3,689,993 3,689,993
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 04/15/2020 2019/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.
3,433 3,433 1
16,496 16,496 2
164,294 164,294 3
540,511 540,511 4
26,324 26,324 5
23,572 23,572 6
234 234 7
1,327 1,327 8
8,078 8,078 9
221 221 10
1,475 1,475 11
2,020 2,020 12
3,240 3,240 13
3,270 3,270 14
13 13 15
3,035 3,035 16
81,058 81,058 17
1,783,656 1,783,656 18
4,138 4,138 19
128 128 20
2,002 2,002 21
461 461 22
1,016 1,016 23
6,093 6,093 24
8,028 8,028 25
1,016 1,016 26
27
28
29
30
31
32
33
34
FERC FORM NO. 1 (ED. 12-90) Page 330.3
12,692,240 16,342,482 3,650,242 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.: 2 Column: m
Ancillary Services
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)
04/15/2020
Year/Period of Report
2019/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
04/15/2020 2019/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 1,499,551 1,499,551Bonneville Power Admin 1
LFP 12,322,220 2,186,232 10,135,988Bonneville Power Admin 2
LFP 471,701 471,701Bonneville Power Admin 3
OS 54,432 54,432Bonneville Power Admin 4
FNS 1,411,707 239,990 1,171,717Bonneville Power Admin 5
NF 236,983 236,983 45,868 45,868Bonneville Power Admin 6
NF 25,297 25,297 3,965 3,965Idaho Power Company 7
NF 339 339 50 50Nevada Power Company 8
LFP 47,538 47,538Kootenai Electric Coop 9
LFP 139,315 139,315Northern Lights 10
SFP 116,785 13,267 103,518NorthWestern Energy 11
NF 200,063 200,063 39,047 39,047NorthWestern Energy 12
LFP 642,989 14,989 628,000Portland General Elec 13
NF 6,433 6,433 5,487 5,487Portland General Elec 14
NF 33,594 33,594 24,417 24,417Snohomish County PUD 15
NF 9,837 352 9,485 4,317 4,317Puget Sound Energy 16
FERC FORM NO. 1/3-Q (REV. 02-04) Page 332
135,887 135,887 14,197,328 546,230 2,509,262 17,252,820TOTAL
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
04/15/2020 2019/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 8 8 1 1Arizona Public Service 1
NF 12,517 12,517 9,915 9,915Seattle City Light 2
NF 21,511 21,511 2,820 2,820PacifiCorp 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
135,887 135,887 14,197,328 546,230 2,509,262 17,252,820TOTAL
Schedule Page: 332 Line No.: 2 Column: g
Ancillary Services
Schedule Page: 332 Line No.: 4 Column: g
Use of Facilities
Schedule Page: 332 Line No.: 5 Column: g
Ancillary Services
Schedule Page: 332 Line No.: 11 Column: g
Ancillary Services and Regulation & Frequency Response
Schedule Page: 332 Line No.: 13 Column: g
Ancillary Services
Schedule Page: 332 Line No.: 16 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)
04/15/2020
Year/Period of Report
2019/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 04/15/2020 2019/Q4
Line Description Amount
(b)(a)No.
828,888Industry Association Dues 1
Nuclear Power Research Expenses 2
Other Experimental and General Research Expenses 3
360,042Pub & Dist Info to Stkhldrs...expn servicing outstanding Securities 4
Oth Expn >=5,000 show purpose, recipient, amount. Group if < $5,000 5
328,283Community Relations 6
422,468Director Expenses 7
25,843Education & Information 8
149,978Rating Agency Fees 9
514,340Aircraft Operation and fees 10
1,672,262Misc Vendors >5000 11
693,047Misc Vendors < 5000 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
4,995,151
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
04/15/2020 2019/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)
4,164,422 4,164,422 1 Intangible Plant
16,630,523 16,630,523 2 Steam Production Plant
3 Nuclear Production Plant
13,583,713 13,583,713 4 Hydraulic Production Plant-Conventional
5 Hydraulic Production Plant-Pumped Storage
12,268,933 10,635,972 1,632,961 6 Other Production Plant
15,658,811 15,658,811 7 Transmission Plant
48,023,375 48,023,375 8 Distribution Plant
9 Regional Transmission and Market Operation
4,005,649 3,958,042 47,607 10 General Plant
42,890,488 18,188,621 24,701,867 11 Common Plant-Electric
157,225,914 126,679,057 28,913,896 1,632,961 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
04/15/2020 2019/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 57,470 14
60.00 -6.00 2.67 7.50R1312 86,181 15
-6.00 9.22 7.50R2.5313 4 16
40.00 -6.00 8.34 7.50R0.5314 23,624 17
50.00 -6.00 2.97 7.50R3315 10,116 18
53.00 -6.00 3.96 7.50R2316 9,599 19
Subtotal 186,994 20
21
Colstrip No. 4 22
70.00 -7.00 2.95 7.50S1.5311 53,633 23
60.00 -7.00 4.79 7.50R1312 59,933 24
-7.00 9.34 7.50R2.5313 4 25
40.00 -7.00 7.59 7.50R0.5314 15,050 26
50.00 -7.00 3.72 7.50R3315 7,218 27
53.00 -7.00 4.74 7.50R2316 4,521 28
Subtotal 140,359 29
30
0Kettle Falls 31
1.32 12.00SQ310 148 32
70.00 -4.00 2.49 11.70S1.5311 28,657 33
55.00 -4.00 3.18 11.30R1312 46,669 34
35.00 -4.00 2.25 10.20R0.5314 18,626 35
50.00 -4.00 4.06 11.40R3315 12,323 36
55.00 -4.00 2.97 11.30R2316 2,506 37
Subtotal 108,929 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 25,349 43
60.00 -16.00 2.03 45.53R1332 44,406 44
65.00 -16.00 2.59 40.80R1.5333 47,050 45
40.00 -16.00 2.10 29.40S1334 8,245 46
50.00 -16.00 1.89 41.38R1335 5,600 47
55.00 -16.00 2.00 29.30S2.5336 1,671 48
Subtotal 141,704 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
04/15/2020 2019/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 23,592 14
60.00 -24.00 2.22 47.23R1332 37,009 15
65.00 -24.00 2.41 44.90R1.5333 88,683 16
40.00 -24.00 4.09 27.40S1334 17,278 17
50.00 -24.00 2.04 41.68R1335 4,275 18
55.00 -24.00 2.96 26.20S2.5336 260 19
Subtotal 201,574 20
21
Post Falls 22
80.00 1.91 24.25R4330 2,908 23
55.00 -4.00 1.53 38.10R2331 4,171 24
60.00 -4.00 2.48 36.90R1332 25,503 25
65.00 -4.00 0.79 33.60R1.5333 2,234 26
40.00 -4.00 1.20 23.20S1334 1,760 27
60.00 -4.00 2.39 36.90R1335 787 28
55.00 -4.00 2.62 26.20S2.5336 578 29
Subtotal 37,941 30
31
Long Lake 32
80.00 1.91 25.70R4330 418 33
55.00 -7.00 1.64 33.70R2331 9,789 34
60.00 -7.00 1.85 34.00R1332 36,755 35
65.00 -7.00 0.45 33.70R1.5333 8,738 36
40.00 -7.00 0.85 29.20S1334 3,347 37
60.00 -7.00 1.69 32.60R1335 850 38
55.00 -7.00 2.62 26.20S2.5336 39
Subtotal 59,897 40
41
Little Falls 42
80.00 1.28 19.60R4330 4,217 43
110.00 -7.00 1.87 41.60R2331 3,958 44
100.00 -7.00 1.17 39.80R1332 6,717 45
65.00 -7.00 1.40 39.10R1.5333 38,925 46
40.00 -7.00 2.72 32.30S1334 13,813 47
60.00 -7.00 1.67 36.30R1335 549 48
Subtotal 68,179 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
04/15/2020 2019/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 975 14
110.00 -7.00 1.82 40.70R1332 7,789 15
65.00 -7.00 0.22 38.00R1.5333 1,166 16
40.00 -7.00 3.11 29.90S1334 4,269 17
60.00 -7.00 2.14 34.70R1335 104 18
55.00 -7.00 2.53 26.20S2.5336 508 19
Subtotal 14,875 20
21
Nine Mile 22
100.00 1.50 25.25R4330 11 23
110.00 -4.00 2.41 40.10R2331 19,277 24
110.00 -4.00 2.10 37.30R1332 28,683 25
65.00 -4.00 2.58 39.40R1.5333 41,703 26
40.00 -4.00 2.92 33.40S1334 19,171 27
60.00 -4.00 2.68 38.00R1335 3,276 28
55.00 -4.00 2.70 26.20S2.5336 595 29
Subtotal 112,716 30
31
Monroe Street 32
55.00 -7.00 2.39 40.80R2331 12,122 33
110.00 -7.00 1.91 49.80R1332 9,972 34
65.00 -7.00 2.22 40.80R1.5333 11,001 35
40.00 -7.00 3.66 25.60S1334 3,809 36
60.00 -7.00 2.30 40.50R1335 34 37
55.00 -7.00 2.89 31.10R2.5336 50 38
Subtotal 36,988 39
40
OTHER PRODUCTION 41
Northeast Turbine 42
55.00 -5.00 30.78 2.00S4341 751 43
55.00 -5.00 R3342 39 44
60.00 -5.00 2.51 2.00S2.5343 9,059 45
45.00 -5.00 2.56 2.00R1344 2,610 46
20.00 -5.00 16.94 2.00S1345 1,243 47
35.00 -5.00 23.28 1.90R2.5346 399 48
Subtotal 14,101 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
04/15/2020 2019/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 3,580 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 49,716 16
20.00 -4.00 8.22 11.90S1345 3,462 17
35.00 -4.00 5.69 17.40R2.5346 249 18
Subtotal 64,425 19
20
Kettle Falls CT 21
55.00 -1.00 1.36 11.00S4341 9 22
55.00 -1.00 3.33 11.80R3342 89 23
60.00 -1.00 3.45 11.90S2.5343 8,671 24
45.00 -1.00 4.11 11.30R1344 759 25
20.00 -1.00 8.00 11.00S1345 13 26
Subtotal 9,541 27
28
Boulder Park 29
55.00 -2.00 2.56 25.90S4341 1,277 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 31,132 33
20.00 -2.00 6.42 15.10S1345 656 34
35.00 -2.00 3.99 23.70R2.5346 57 35
Subtotal 33,341 36
37
Coyote Springs 2 38
55.00 -3.00 2.37 26.80S4341 11,560 39
55.00 -3.00 2.45 25.60R3342 19,318 40
45.00 -3.00 3.36 23.40R1344 137,143 41
20.00 -3.00 5.25 11.70S1345 16,933 42
35.00 -3.00 4.27 22.10R2.5346 1,003 43
Subtotal 185,957 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
04/15/2020 2019/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 22,538 18
65.00 -10.00 1.63 52.90S1.5352 25,868 19
44.00 -10.00 2.41 32.60R2353 290,493 20
75.00 -15.00 1.51 41.90R4354 17,161 21
63.00 -30.00 1.93 51.70R2.5355 280,744 22
70.00 -30.00 1.90 45.90R3356 159,395 23
60.00 1.64 47.40R4357 3,253 24
50.00 2.06 29.30S3358 2,603 25
70.00 1.41 42.80R4359 2,113 26
Subtotal 804,168 27
28
DISTRIBUTION PLANT 29
75.00 1.34 69.40R4360 4,071 30
60.00 -10.00 1.72 46.70S1.5361 34,136 31
42.00 -10.00 2.68 30.40R1.5362 148,162 32
15.00 6.80 13.50L3363 2,598 33
67.00 -60.00 2.47 51.70R2.5364 - WA 284,700 34
65.00 -60.00 2.57 51.70R2.5364 - ID 151,962 35
68.00 -50.00 2.27 44.40R3365 - WA 180,173 36
65.00 -50.00 2.45 44.40R3.5365 - ID 101,008 37
60.00 -30.00 1.56 46.50R1.5366 - WA 80,584 38
60.00 -30.00 2.14 46.50S2.5366 - ID 43,161 39
35.00 -30.00 3.44 24.70S1.5367 - WA 146,018 40
35.00 -20.00 2.99 24.70S1.5367 - ID 74,117 41
47.00 -10.00 2.16 35.50R2368 280,772 42
65.00 -40.00 2.10 50.40R4369 180,434 43
35.00 -2.00 2.89 S0370 - AN 157 44
15.00 9.06 7.70S2.5370.2 - ID 23,834 45
35.00 2.89 26.50S0370.3 - WA 48,954 46
10.00 10.36 9.50S1371 2,122 47
37.00 -20.00 1.87 27.90R2.5373 23,886 48
37.00 -20.00 3.04 29.20R2.5373.4 26,675 49
37.00 -20.00 3.17 36.10R2.5373.5 15,256 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
04/15/2020 2019/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 1,852,780 12
13
GENERAL PLANT 14
50.00 -5.00 1.90 42.20R2.5390.1 8,504 15
15.00 6.67 15.00SQ391 8 16
5.00 20.00 1.70SQ391.1 1,891 17
25.00 4.00 14.60SQ393 392 18
20.00 5.00 11.00SQ394 6,165 19
15.00 6.67 7.40SQ395 1,811 20
15.00 6.67 8.50SQ397 49,696 21
10.00 10.00 6.60SQ398 194 22
Subtotal 68,661 23
24
MISC POWER 25
16.00 5.48 12.20L2.5392 7,838 26
22.00 3.75 14.80S1396 3,865 27
Subtotal 11,703 28
29
30
31
32
33
34
35
36
37
38
TOTAL COMPANY 4,155,665 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
04/15/2020 2019/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. 2,596,139 32,603 2,628,742 4
5
6
7
8
Washington Utilities and Transportation 9
Commission: includes annual fee and various 10
other electric dockets 1,087,170 1,034,748 2,121,918 11
12
Includes annual fee and various other natural 13
gas dockets 291,397 279,668 571,065 14
15
Idaho Public Utilities Commission 16
Includes annual fee and various other electric 17
dockets 663,458 448,538 1,111,996 18
19
Includes annual fee and various other natural 20
gas dockets 154,795 89,959 244,754 21
22
Public Utility Commission of Oregon 23
Includes annual fees and various other natural 24
gas dockets 541,152 348,782 889,934 25
26
Not directly assigned electric 518,188 518,188 27
Not directly assigned natural gas 253,712 253,712 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 5,334,111 3,006,198 8,340,309
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
04/15/2020 2019/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 2,628,742928
5
6
7
8
9
10
Electric 11 2,121,918928
12
13
Gas 14 571,065928
15
16
17
Electric 18 1,111,996928
19
20
Gas 21 244,754928
22
23
24
Gas 25 889,934928
26
Electric 27 518,188928
Gas 28 253,712928
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
FERC FORM NO. 1 (ED. 12-96) Page 351
46 8,340,309
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
04/15/2020 2019/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
HUB-Morris Center Lab Test FacilityA. Electric (6) Other - Testing Lab & Facility 8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 352
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
04/15/2020 2019/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.
579,917 1 1,507,094 107 2,087,011
639 2 16,275 557 16,914
3 99,239 587 99,239
43,224 4 8,016 598 51,240
87,105 5920 87,105
6 2,000 930 2,000
7
142,164 8 177,179 107 319,343
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
FERC FORM NO. 1 (ED. 12-87) Page 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
04/15/2020 2019/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
13,119,472Production 3
4,128,801Transmission 4
Regional Market 5
9,754,373Distribution 6
7,471,488Customer Accounts 7
599,173Customer Service and Informational 8
Sales 9
22,278,296Administrative and General 10
57,351,603TOTAL Operation (Enter Total of lines 3 thru 10) 11
Maintenance 12
5,163,196Production 13
1,020,436Transmission 14
Regional Market 15
3,999,308Distribution 16
Administrative and General 17
10,182,940TOTAL Maintenance (Total of lines 13 thru 17) 18
Total Operation and Maintenance 19
18,282,668Production (Enter Total of lines 3 and 13) 20
5,149,237Transmission (Enter Total of lines 4 and 14) 21
Regional Market (Enter Total of Lines 5 and 15) 22
13,753,681Distribution (Enter Total of lines 6 and 16) 23
7,471,488Customer Accounts (Transcribe from line 7) 24
599,173Customer Service and Informational (Transcribe from line 8) 25
Sales (Transcribe from line 9) 26
22,278,296Administrative and General (Enter Total of lines 10 and 17) 27
65,473,463 -2,061,080 67,534,543TOTAL 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
895,589Other Gas Supply 33
9,947Storage, LNG Terminaling and Processing 34
Transmission 35
6,249,270Distribution 36
3,259,054Customer Accounts 37
342,792Customer Service and Informational 38
Sales 39
8,958,668Administrative and General 40
19,715,320TOTAL 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
1,787,888Transmission 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
04/15/2020 2019/Q4
Line
No.
Classification
(c)(b)(a)
Direct Payroll Allocation of Total
(d)
Distribution Payroll charged forClearing Accounts
DISTRIBUTION OF SALARIES AND WAGES (Continued)
3,242,057Distribution 48
Administrative and General 49
5,029,945TOTAL 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
895,589Other Gas Supply (Enter Total of lines 33 and 45) 54
9,947Storage, LNG Terminaling and Processing (Total of lines 31 thru 47) 55
1,787,888Transmission (Lines 35 and 47) 56
9,491,327Distribution (Lines 36 and 48) 57
3,259,054Customer Accounts (Line 37) 58
342,792Customer Service and Informational (Line 38) 59
Sales (Line 39) 60
8,958,668Administrative and General (Lines 40 and 49) 61
31,805,752 7,060,487 24,745,265TOTAL Operation and Maint. (Total of lines 52 thru 61) 62
Other Utility Departments 63
Operation and Maintenance 64
97,279,215 4,999,407 92,279,808TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 65
Utility Plant 66
Construction (By Utility Departments) 67
56,493,382 13,479,982 43,013,400Electric Plant 68
16,135,147 4,571,235 11,563,912Gas Plant 69
Other (provide details in footnote): 70
72,628,529 18,051,217 54,577,312TOTAL Construction (Total of lines 68 thru 70) 71
Plant Removal (By Utility Departments) 72
2,464,955 504,622 1,960,333Electric Plant 73
595,144 121,837 473,307Gas Plant 74
Other (provide details in footnote): 75
3,060,099 626,459 2,433,640TOTAL Plant Removal (Total of lines 73 thru 75) 76
Other Accounts (Specify, provide details in footnote): 77
-2,499,877 2,499,877Stores Expense (163) 78
-4,601,566 4,601,566Small Tool Expense (184) 79
1,056,805 1,056,805Miscellaneous Deferred Debits (186) 80
1,058,754 1,058,754Non-Operating Expenses (417) 81
18,856 18,856Retirement/Bonus/Serp/HRA Settlement (228) 82
1,229,448 1,229,448Activities (426) 83
-14,549,409 14,549,409Employee Incentive Plan (232380) 84
-2,026,689 2,026,689DSM Tariff Rider 85
133,376 133,376Incentive/Stock Compensation (238000) 86
21,702,531 458 21,702,073Payroll Equilization Liability 87
88
89
90
91
92
93
94
25,199,770 -23,677,083 48,876,853TOTAL Other Accounts 95
198,167,613 198,167,613TOTAL 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
04/15/2020 2019/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 274,339,398
389 Land and Land Rights 13,815,624
390 Structures and Improvements 156,177,554
391 Office Furniture and Equipment 92,161,863
392 Transportation Equipment 14,287,313
393 Stores Equipment 4,910,772
394 Tools, Shop & Garage Equipment 14,532,607
395 Laboratory Equipment 1,568,515
396 Power Operated Equipment 2,026,723
397 Communications Equipment 77,551,368
398 Miscellaneous Equipment 626,313
399 Asset Retirement Cost 0
Total Common Plant 651,998,050
Const. Work in Progress 24,865,214
Total Utility Plant 676,863,264
Acc. Prov. for Dep. & Amort. 197,862,807
Net Utility Plant 479,000,457
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 252,054 131,577 120,477 #of cust @ yr end
902 Meter reading expenses 3,669,156 2,224,022 1,445,134 #of cust @ yr end
903 Cust rec & collectn expenses 15,374,892 8,333,675 7,041,217 #of cust @ yr end
903.90-99 A/R misc fees 0 0 0 net direct plant
904 Uncollectible accounts 400,000 208,808 191,192 #of cust @ yr end
905 Misc cust acct expenses 333,642 174,168 159,474 #of cust @ yr end
907 Cust svce & Info exp supervision 0 0 0 #of cust @ yr end
908 Cust assistance expenses 671,316 401,616 269,700 #of cust @ yr end
909 Info & instruct advert expenses 1,940,938 1,176,474 764,464 #of cust @ yr end
910 Misc cust serv & info expenses 491,416 256,529 234,887 #of cust @ yr end
911 Sales expense -supervision 0 0 0 #of cust @ yr end
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
04/15/2020 2019/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.
912 Demo and selling expenses 0 0 0 #of cust @ yr end
913 Advertising expenses 0 0 0 #of cust @ yr end
916 Misc sales expenses 0 0 0 #of cust @ yr end
920 Admin & gen salaries 33,498,958 23,719,038 9,779,920 four factor
921 Office supplies & expenses 6,286,833 4,441,305 1,845,528 four factor
922 Admin expenses tranf-credit 0 0 0 four factor
923 Outside services employed 12,951,952 9,147,448 3,804,504 four factor
924 Property insurance 1,618,025 1,141,970 476,055 four factor
925 Injuries and damages 6,707,709 4,890,538 1,817,171 four factor
926 Employee pensions&benefits 90,337,343 63,760,016 26,577,327 four factor
927 Franchise requirement 0 0 0 four factor
928 Regulatory commission expenses 2,053,656 1,524,134 529,522 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 5,402,940 3,835,817 1,567,123 four factor
931 Rents 433,782 308,077 125,705 four factor
935 Maint of general plant 15,592,094 11,136,091 4,456,003 four factor
403 Depreciation 25,450,157 18,188,621 7,261,536 four factor
404 Amort of LTD term plant 34,603,854 24,701,866 9,901,988 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
04/15/2020 2019/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) 2 957,925 856,734 849,655 938,050
Net Sales (Account 447) 3 ( 10,561,206)( 3,917,453) ( 5,324,792) ( 8,398,930)
Transmission Rights 4
Ancillary Services 5 ( 40,673)( 11,605) ( 22,438) ( 34,198)
Other Items (list separately) 6
Access Charge 7 185,123 71,505 182,292 183,990
Cost Recovery 8 ( 8,902) 10,526 9,572 ( 7,474)
Day Ahead Energy-Congestion Losses 9 ( 40,505)( 29,412) ( 42,441) ( 42,764)
FERC Fees 10 1,240 489 1,223 1,233
GMC 11 123,102 34,943 62,313 99,042
Hour Ahead Scheduling Process-RT 12 ( 2,818)( 1,021) ( 1,300) ( 994)
Other 13 1,883( 95) ( 767) ( 307)
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
( 9,384,831)( 2,985,389) ( 4,286,683) ( 7,262,352)
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
04/15/2020 2019/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
1,031,012MW 80Regulation and Frequency Response 3
1,144,875MWh 28,074 1,020,502MWh 27,157Energy Imbalance 4
773,259MW 60Operating Reserve - Spinning 5
712,386MW 60Operating Reserve - Supplement 6
10,604,106MW 847 10,604,106MW 847Other 7
14,265,638 29,121 11,624,608 28,004Total (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)
04/15/2020
Year/Period of Report
2019/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 04/15/2020 2019/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
18 183 288 288 337 1,424 80015 2,232January 1
16 408 258 288 400 1,543 800 7 2,639February 2
21 809 375 292 388 1,494 800 4 2,983March 3
55 1,400 921 868 1,125 4,461Total for Quarter 1 4
9 334 38 300 244 1,146 80010 2,024April 5
29 75 74 303 245 1,276170030 1,899May 6
26 74 460 305 280 1,427160013 2,086June 7
64 483 572 908 769 3,849Total for Quarter 2 8
32 124 67 301 304 1,546170023 2,276July 9
27 274 260 295 315 1,6151700 7 2,499August 10
31 74 588 292 257 1,3401800 4 1,963September 11
90 472 915 888 876 4,501Total for Quarter 3 12
39 114 99 288 349 1,492 80030 2,244October 13
17 439 167 282 296 1,270 80021 2,287November 14
13 536 120 282 295 1,357180011 2,471December 15
69 1,089 386 852 940 4,119Total for Quarter 4 16
278 3,444 2,794 3,516 3,710 16,930
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
04/15/2020 2019/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
1,898,160Steam3
Nuclear4
3,519,884Hydro-Conventional5
Hydro-Pumped Storage6
2,155,469Other7
Less Energy for Pumping8
7,573,513Net Generation (Enter Total of lines 3
through 8)
9
5,344,702Purchases10
Power Exchanges:11
9,046Received12
429,475Delivered13
-420,429Net Exchanges (Line 12 minus line 13)14
Transmission For Other (Wheeling)15
3,689,993Received16
3,689,993Delivered17
Net Transmission for Other (Line 16 minus
line 17)
18
Transmission By Others Losses19
12,497,786TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
20
DISPOSITION OF ENERGY21
9,015,988Sales to Ultimate Consumers (Including
Interdepartmental Sales)
22
Requirements Sales for Resale (See
instruction 4, page 311.)
23
2,942,248Non-Requirements Sales for Resale (See
instruction 4, page 311.)
24
Energy Furnished Without Charge25
86,149Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
26
453,401Total Energy Losses27
12,497,786TOTAL (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 04/15/2020 2019/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 15 1,475 217,189 0800 1,088,872
February 30 7 1,577 212,065 0800 1,064,342
March 31 1 1,527 310,411 0800 1,166,712
April 32 11 1,224 380,311 0800 1,091,759
May 33 30 1,309 386,851 1700 1,095,475
June 34 13 1,470 284,634 1600 1,009,485
July 35 23 1,590 226,577 1700 1,019,952
August 36 7 1,656 181,821 1700 1,007,778
September 37 4 1,385 222,870 1800 922,575
October 38 30 1,504 165,475 0800 955,260
November 39 1 1,418 174,636 0800 1,000,441
December 40 16 1,474 179,408 1800 1,075,135
FERC FORM NO. 1 (ED. 12-90) Page 401b
41 TOTAL 12,497,786 2,942,248
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
04/15/2020 2019/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)
63284 6 Net Peak Demand on Plant - MW (60 minutes)
637409 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
34590001890646000 12 Net Generation, Exclusive of Plant Use - KWh
1387530 13 Cost of Plant: Land and Land Rights
75102511559743 14 Structures and Improvements
13347298174396811 15 Equipment Costs
0351682 16 Asset Retirement Costs
14237076186308236 17 Total Cost
230.3734631.5533 18 Cost per KW of Installed Capacity (line 17/5) Including
6144560 19 Production Expenses: Oper, Supv, & Engr
7067732967512 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)
1073781624751 25 Electric Expenses
7999281900 26 Misc Steam (or Nuclear) Power Expenses
080866 27 Rents
00 28 Allowances
14104183191 29 Maintenance Supervision and Engineering
1945114321 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
863806556222 32 Maintenance of Electric Plant
20127194870 33 Maintenance of Misc Steam (or Nuclear) Plant
30861642148193 34 Total Production Expenses
0.08920.0223 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)
12440725 0 0 41880 0 0 38 Quantity (Units) of Fuel Burned
1020000 0 0 1020000 0 0 39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear)
2.650 0.000 0.000 1.688 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
2.650 0.000 0.000 1.688 0.000 0.000 41 Average Cost of Fuel per Unit Burned
2.598 0.000 0.000 1.655 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.017 0.000 0.000 0.020 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
6712.000 0.000 0.000 12350.000 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
04/15/2020 2019/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
156100 235 6
16636887 7923 7
16754 222 8
054 222 9
054 222 10
129 306 11
176180000316112000 1582048000 12
6216822289077 1321965 13
358020428656948 111103126 14
6084453280124261 216249590 15
0323787 16702865 16
65046418111394073 345377546 17
390.66922197.1218 1479.7667 18
920154779 200708 19
44096447834090 23017352 20
00 0 21
0592550 3168489 22
00 0 23
00 0 24
231050794284 83229 25
29647440623 2461320 26
00 15079 27
00 0 28
2875699292 398065 29
12679146467 614683 30
01657964 4147938 31
88017431938 205474 32
103039747243 476576 33
490375212899230 34788913 34
0.02780.0408 0.0220 35
WOOD GAS GASCOAL OIL 36
TON MCF MCFTON BBL 37
499986 8854 0 2087852 0 0970451 2075 0 38
8600000 1020000 0 1020000 0 016970000 5880000 0 39
15.632 2.082 0.000 2.112 0.000 0.00023.512 96.412 0.000 40
15.632 2.082 0.000 2.112 0.000 0.00023.512 96.412 0.000 41
1.818 2.041 0.000 2.071 0.000 0.0001.386 16.397 0.000 42
0.025 0.025 0.000 0.025 0.000 0.0000.014 0.000 0.000 43
13634.000 0.000 0.000 12088.000 0.000 0.00010417.000 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
04/15/2020 2019/Q4
Line
No.
Item
(b)(a)(c)
Plant
Name:
Plant
Name:
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. Indicate by a footnote any plant leased or operated
as a joint facility. 4. If net peak demand for 60 minutes is not available, give data which is available, specifying period. 5. If any employees attend
more than one plant, report on line 11 the approximate average number of employees assignable to each plant. 6. If gas is used and purchased on a
therm basis report the Btu content or the gas and the quantity of fuel burned converted to Mct. 7. Quantities of fuel burned (Line 38) and average cost
per unit of fuel burned (Line 41) must be consistent with charges to expense accounts 501 and 547 (Line 42) as show on Line 20. 8. If more than one
fuel is burned in a plant furnish only the composite heat rate for all fuels burned.
Internal Comb 1 Kind of Plant (Internal Comb, Gas Turb, Nuclear
Conventional 2 Type of Constr (Conventional, Outdoor, Boiler, etc)
2002 3 Year Originally Constructed
2002 4 Year Last Unit was Installed
0.0024.60 5 Total Installed Cap (Max Gen Name Plate Ratings-MW)
025 6 Net Peak Demand on Plant - MW (60 minutes)
02978 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
066910000 12 Net Generation, Exclusive of Plant Use - KWh
0185629 13 Cost of Plant: Land and Land Rights
01276684 14 Structures and Improvements
032064610 15 Equipment Costs
00 16 Asset Retirement Costs
033526923 17 Total Cost
01362.8830 18 Cost per KW of Installed Capacity (line 17/5) Including
04080 19 Production Expenses: Oper, Supv, & Engr
01472415 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)
0206063 25 Electric Expenses
033826 26 Misc Steam (or Nuclear) Power Expenses
00 27 Rents
00 28 Allowances
096739 29 Maintenance Supervision and Engineering
04177 30 Maintenance of Structures
00 31 Maintenance of Boiler (or reactor) Plant
0310098 32 Maintenance of Electric Plant
096704 33 Maintenance of Misc Steam (or Nuclear) Plant
02224102 34 Total Production Expenses
0.00000.0332 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)
594300 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)
2.478 0.000 0.000 0.000 0.000 0.000 40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year
2.478 0.000 0.000 0.000 0.000 0.000 41 Average Cost of Fuel per Unit Burned
2.429 0.000 0.000 0.000 0.000 0.000 42 Average Cost of Fuel Burned per Million BTU
0.022 0.000 0.000 0.000 0.000 0.000 43 Average Cost of Fuel Burned per KWh Net Gen
9060.000 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
04/15/2020 2019/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 00 0 0 38
0 0 0 0 0 00 0 0 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.1
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
04/15/2020 2019/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
04/15/2020 2019/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 00 0 0 38
0 0 0 0 0 00 0 0 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.2
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
04/15/2020 2019/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
04/15/2020 2019/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 00 0 0 38
0 0 0 0 0 00 0 0 39
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 40
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 41
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 42
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 43
0.000 0.000 0.000 0.000 0.000 0.0000.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.3
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)
04/15/2020
Year/Period of Report
2019/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
04/15/2020 2019/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 23 17
Plant Hours Connect to Load 7 8,476 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 98,076,000 66,538,000
Cost of Plant 13
Land and Land Rights 14 51,600 1,081,854
Structures and Improvements 15 12,113,194 974,617
Reservoirs, Dams, and Waterways 16 9,972,020 7,789,435
Equipment Costs 17 14,563,523 5,539,522
Roads, Railroads, and Bridges 18 50,448 508,242
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 36,750,785 15,893,670
Cost per KW of Installed Capacity (line 20 / 5) 21 2,483.1611 1,589.3670
Production Expenses 22
Operation Supervision and Engineering 23 4,513 3,845
Water for Power 24 0 0
Hydraulic Expenses 25 3,108 3,528
Electric Expenses 26 513,064 521,003
Misc Hydraulic Power Generation Expenses 27 13,197 21,731
Rents 28 0 0
Maintenance Supervision and Engineering 29 54,484 11,145
Maintenance of Structures 30 9,607 4,651
Maintenance of Reservoirs, Dams, and Waterways 31 213,682 63,164
Maintenance of Electric Plant 32 58,647 28,663
Maintenance of Misc Hydraulic Plant 33 7,077 3,288
Total Production Expenses (total 23 thru 33) 34 877,379 661,018
Expenses per net KWh 35 0.0089 0.0099
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
04/15/2020 2019/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 26628 6
7,162 8,6036,960 7
8
18 25538 9
18 29538 10
5 115 11
68,660,000 991,068,000119,575,000 12
13
3,672,815 16,380,17833,429 14
4,171,447 25,349,24018,899,291 15
25,503,438 44,405,80528,683,217 16
4,780,903 60,700,08764,150,086 17
577,944 1,671,013594,870 18
0 00 19
38,706,547 148,506,323112,360,893 20
2,615.3072 560.40122,988.3216 21
22
12,524 41,41714,382 23
0 00 24
5,650 2,011285 25
667,334 1,079,998672,182 26
73,590 183,10291,857 27
0 00 28
3,069 26,41620,682 29
37,162 71,27546,107 30
96,002 180,36046,341 31
50,211 685,211228,798 32
26,889 16,01634,722 33
972,431 2,285,8061,155,356 34
0.0142 0.00230.0097 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
04/15/2020 2019/Q4
Line
No.
Item FERC Licensed Project No.
(b)(a)(c)
Plant Name:
FERC Licensed Project No.
Plant Name:
1. Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2. If any plant is leased, operated under a license from the Federal Energy Regulatory Commission, or operated as a joint facility, indicate such facts in a
footnote. If licensed project, give project number.
3. If net peak demand for 60 minutes is not available, give that which is available specifying period.
4. If a group of employees attends more than one generating plant, report on line 11 the approximate average number of employees assignable to each
plant.
Kind of Plant (Run-of-River or Storage) 1 Storage Storage
Plant Construction type (Conventional or Outdoor) 2 Outdoor Conventional
Year Originally Constructed 3 1959 1915
Year Last Unit was Installed 4 1977 1924
Total installed cap (Gen name plate Rating in MW) 5 487.80 70.00
Net Peak Demand on Plant-Megawatts (60 minutes) 6 556 91
Plant Hours Connect to Load 7 4,301 6,780
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 12 6
Net Generation, Exclusive of Plant Use - Kwh 12 1,573,513,000 438,456,000
Cost of Plant 13
Land and Land Rights 14 35,968,495 2,500,473
Structures and Improvements 15 22,764,035 9,789,347
Reservoirs, Dams, and Waterways 16 37,009,326 36,754,005
Equipment Costs 17 109,657,885 12,896,877
Roads, Railroads, and Bridges 18 259,750 0
Asset Retirement Costs 19 0 0
TOTAL cost (Total of 14 thru 19) 20 205,659,491 61,940,702
Cost per KW of Installed Capacity (line 20 / 5) 21 421.6062 884.8672
Production Expenses 22
Operation Supervision and Engineering 23 244,753 9,428
Water for Power 24 0 0
Hydraulic Expenses 25 54,594 8,652
Electric Expenses 26 984,913 678,477
Misc Hydraulic Power Generation Expenses 27 226,901 137,262
Rents 28 0 0
Maintenance Supervision and Engineering 29 87,860 53,239
Maintenance of Structures 30 205,593 150,447
Maintenance of Reservoirs, Dams, and Waterways 31 412,407 525,692
Maintenance of Electric Plant 32 890,157 87,061
Maintenance of Misc Hydraulic Plant 33 73,197 24,909
Total Production Expenses (total 23 thru 33) 34 3,180,375 1,675,167
Expenses per net KWh 35 0.0020 0.0038
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
04/15/2020 2019/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 0.0040.40 5
0 037 6
0 06,780 7
8
0 088 9
0 088 10
0 05 11
0 0163,998,000 12
13
0 04,325,371 14
0 03,958,492 15
0 06,716,892 16
0 053,286,645 17
0 00 18
0 00 19
0 068,287,400 20
0.0000 0.00001,690.2822 21
22
0 0998 23
0 00 24
0 07,895 25
0 0607,205 26
0 034,006 27
0 0979,249 28
0 0269 29
0 057,636 30
0 048,262 31
0 0106,489 32
0 010,203 33
0 01,852,212 34
0.0000 0.00000.0113 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 04/15/2020 2019/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 16.0 18,274,000 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 04/15/2020 2019/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
242 54,669 494,465 1,323,903 1Nat Gas 83,249
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
04/15/2020 2019/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 1,551.00 3 Group Sum
4
Steel Tower 230.00 230.00 1.00 1 5 Beacon Sub #4 BPA Bell Sub
H Type 230.00 230.00 5.00 1 6 Beacon Sub #4 BPA Bell Sub
Steel Pole 230.00 230.00 3.00 1 7 Beacon Sub #5 BPA Bell Sub
H Type 230.00 230.00 3.00 1 8 Beacon Sub #5 BPA Bell Sub
Steel Tower 230.00 230.00 1.00 1 9 Beacon Cabinet Gorge Plant
Steel Pole 230.00 230.00 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 12.00 2 13 Beacon Sub Lolo Sub
H Type 230.00 230.00 87.00 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 Tower 230.00 230.00 2.00 1 34 BPA/Hot Springs #2 Noxon Plant (dead)
Steel Pole 230.00 230.00 2.00 1 35 BPA/Hot Springs #2 Noxon Plant
FERC FORM NO. 1 (ED. 12-87) Page 422
36 TOTAL 2,240.00 3.00 40
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
04/15/2020 2019/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
262,569,945 250,346,744 12,223,201 475,913 346,228 129,685 3
4
1272 ACSS 5
1,447,4721272 ACSS 1,429,560 17,912 5,570 3,298 2,272 6
1272 ACSS 7
3,305,6801272 ACSS 3,275,357 30,323 644 644 8
1590 ACSS 9
1590 ACSS 10
42,933,8571590 ACSR 41,777,661 1,156,196 112,744 112,744 11
1590 ACSS 12
1590 ACSS 13
1272 AAC 14
23,623,9471272 ACSS 23,167,785 456,162 33,959 33,579 380 15
1622 ACSS 16
49,318,9401590 ACSS 48,748,733 570,207 17
1272 ACSR 18
1590 ACSS 19
20,234,734954 AAC 19,137,055 1,097,679 136,466 131,763 4,703 20
795 ACSR 21
2,109,040954 AAC 1,924,829 184,211 60,878 60,878 22
5,655,540954 AAC 5,268,081 387,459 14,063 14,063 23
7,151,2651272 AAC 7,065,037 86,228 29,743 24,372 5,371 24
1272 AAC 25
1272 ACSR 26
8,403,3351272 ACSR 7,779,351 623,984 12,735 12,735 27
1272 ACSR 28
10,915,9811272 ACSR 10,043,831 872,150 29
1590 ACSS 30
10,555,8351272 AAC 10,350,488 205,347 16,919 16,887 32 31
1272 ACSR 32
19,5211272 ACSR 19,521 14,342 10,073 4,269 33
1272 McMAL 34
1272 ACSR 35
FERC FORM NO. 1 (ED. 12-87) Page 423
36 22,651,659 483,043,010 505,694,669 244,378 956,232 88,581 1,289,191
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
04/15/2020 2019/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.
H Type 230.00 230.00 68.00 1 1 BPA/Hot Springs #2 Noxon Plant
Steel Pole 230.00 230.00 2.00 2 2 Coulee West Side Sub
Steel Pole 230.00 230.00 2.00 2 3 BPA Line West Side Sub
H Type 230.00 230.00 7.00 1 4 Hatwai N. Lewiston Sub
H Type 230.00 230.00 20.00 1 5 Divide Creek Imnaha
500.00 500.00 6 Colstrip Plant Broadview
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 2,240.00 3.00 40
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
04/15/2020 2019/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.
13,672,3591272 AAC 10,069,035 3,603,324 43,315 43,315 1
8,4821272 ACSR 8,482 2
631,0041272 ACSR 594,543 36,461 3
2,760,8951590 ACSR 2,605,651 155,244 2,265 2,265 4
1,517,4861272 AAC 1,312,224 205,262 5,704 5,704 5
38,087,120 37,491,331 595,789 323,931 88,581 137,684 97,666 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 22,651,659 483,043,010 505,694,669 244,378 956,232 88,581 1,289,191
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
04/15/2020 2019/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 N/A
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
04/15/2020 2019/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 04/15/2020 2019/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 04/15/2020 2019/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 20 1Two Stage Fan 3
536 4 560 2Two Stage Fan 4
318 3 530 3Two Stage Fan 5
24 2 40 2Frcd Oil & Air Fan 6
12 1 20 1Two Stage Fan 7
12 1 20 16Frcd Oil&Air Fan&Cap 8
36 2 60 2Two Stage Fan 9
32 3 49 3Frcd Oil & Air Fan 10
12 1 20 1Two Stage Fan 11
12 1 20 1Two Stage Fan 12
150 1 250 223Two Stage Fan & Caps 13
12 1 20 1Frcd Oil & Air Fan 14
12 1 20 1FrOil/Air Fan 15
12 1 20 1Two Stage Fan 16
24 2 40 2Fr Oil/Air/2StgFan 17
36 2 60 2Two Stage Fan 18
16 2 17 1One Stage Fan 19
12 1 20 1Frcd Oil & Air Fan 20
18 1 30 1Two Stage Fan 21
12 1 20 1Two Stage Fan 22
36 2 60 2Two Stage Fan 23
12 1 20 1Two Stage Fan 24
24 2 40 14Two Stg/Frcd Oil&Cap 25
12 1 20 1Frcd Oil & Air Fan 26
36 2 60 2Two Stage Fan 27
24 2 40 2Two Stage Fan 28
12 1 20 1Two Stage Fan 29
12 1 30
36 2 60 2Two Stage Fan 31
18 1 30 1Two Stage Fan 32
24 2 40 2Two Stage Fan 33
24 2 40 2Frcd Oil & Air Fan 34
24 2 40 2Two Stage Fan 35
36 2 60 2Two Stage Fan 36
24 2 40 2Two Stage Fan 37
24 2 40 2Two Stage Fan 38
12 1 20 1Two Stage Fan 39
24 2 40 2FrOil/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 04/15/2020 2019/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
Shawnee 115.00 230.00 13.80Trans. Unattended 5
Silver Lake 13.80 115.00Distr. Unattended 6
Southeast 13.80 115.00Distr. Unattended 7
South Othello 13.80 115.00Distr. Unattended 8
South Pullman 13.80 115.00Distr. Unattended 9
Sunset 13.80 115.00Distr. Unattended 10
Terre View 13.80 115.00Dist. Unattended 11
Third & Hatch 13.80 115.00Distr. Unattended 12
Turner 13.80 115.00Dist. Unattended 13
Waikiki 13.80 115.00Distr. Unattended 14
West Side 115.00 230.00 13.80Trans. Unattended 15
Other: 27 substa less than 10MVA Distr. Unattended 16
17
STATE OF IDAHO 18
Appleway 13.80 115.00Dist. Unattended 19
Avondale 13.80 115.00Dist. Unattended 20
Benewah 115.00 230.00 13.80Trans. Unattended 21
Big Creek 13.80 115.00Distr. Unattended 22
Blue Creek 13.80 115.00Distr. Unattended 23
Bunker Hill Limited 13.80 115.00Distr. Unattended 24
Cabinet Gorge (Switchyard) 115.00 230.00 13.80Trans. Unattended 25
Clark Fork 21.80 115.00Distr. Unattended 26
Coeur d'Alene 15th Ave 13.80 115.00Distr. Unattended 27
Cottonwood 24.90 115.00Distr. Unattended 28
Dalton 13.80 115.00Distr. Unattended 29
Grangeville 13.80 115.00Distr. Unattended 30
Holbrook 13.80 115.00Distr. Unattended 31
Huetter 13.80 115.00Distr. Unattended 32
Idaho Road 13.80 115.00Distr Unattended 33
Juliaetta 13.80 115.00Distr. Unattended 34
Kamiah 13.80 115.00Dist. Unattended 35
Kooskia 13.80 115.00Distr. Unattended 36
Lewiston Mill Rd 13.20 115.00Distr. Unattended 37
Lolo 115.00 230.00 13.80Tran & Dist Unattnd 38
Moscow 13.80 115.00Distr. Unattended 39
Moscow 230Kv 115.00 230.00 13.80Tran & Dist Unattnd 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 04/15/2020 2019/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 60 2Frcd Oil 1
24 2 40 2Two Stage Fan 2
30 2 54 2Two Stage Fan 3
24 2 40 2Two Stage Fan 4
150 1 250 1Two Stage Fan 5
12 1 20 1Two Stage Fan 6
36 2 60 2Two Stage Fan 7
12 1 20 1Two Stage Fan 8
30 2 50 2Two Stage Fan 9
33 2 55 50Two Stage Fan & Caps 10
12 1 20 1Two Stage Fan 11
54 3 90 103Two Stg Fan & Cap 12
36 2 60 2Two Stg Fan 13
24 2 40 2Two Stage Fan 14
275 2 375 1Two Stage Fan 15
164 28 16
17
18
36 2 60 2Two Stage Fan 19
12 1 20 1Two Stage Fan 20
75 1 125 223Two Stage Fan & Caps 21
18 2 22 2Portable Fan 22
12 1 20 1Two Stage Fan 23
12 1 16 1Frcd Air Fan 24
75 1 125 1Two Stage Fan 25
10 1 13 1Frcd Air Fan 26
36 2 60 2Two Stage Fan 27
12 1 20 1Two Stage Fan 28
12 1 20 1Two Stage Fan 29
25 4 34 17FrcdOil/Air/Pt Fan&C 30
12 1 20 1Two Stage Fan 31
12 1 20 1Two Stage Fan 32
12 1 20 1Two Stage Fan 33
12 1 20 1Frcd Oil & Air Fan 34
12 1 20 1Two Stage Fan 35
15 3 20 3Frcd Air Fan 36
18 1 30 1Two Stage Fan 37
262 3 270 1Frcd Oil/Air/Two Stg 38
24 2 40 2FrOil/Air/2Stg Fan 39
162 2 270 76Frcd Air Fan & Caps 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 04/15/2020 2019/Q4
Line
No.Name and Location of Substation Primary
(c)(b)(a)
Tertiary
(d)
Character of Substation
(e)
Secondary
VOLTAGE (In MVa)
1. Report below the information called for concerning substations of the respondent as of the end of the year.
2. Substations which serve only one industrial or street railway customer should not be listed below.
3. Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according to
functional character, but the number of such substations must be shown.
4. Indicate in column (b) the functional character of each substation, designating whether transmission or distribution and whether
attended or unattended. At the end of the page, summarize according to function the capacities reported for the individual stations in
column (f).
North Lewiston 230kV 115.00 230.00 13.80Tran & Dist Unattnd 1
North Moscow 13.80 115.00Distr. Unattended 2
Oden 21.80 115.00Distr. Unattended 3
Oldtown 21.80 115.00Distr. Unattended 4
Orofino 24.00 115.00Distr. Unattended 5
Osburn 13.80 115.00Distr. Unattended 6
Pine Creek 115.00 230.00 13.80Tran & Dist Unattnd 7
Pleasant View 13.80 115.00Distr. Unattended 8
Plummer 13.80 115.00Dist Unattended 9
Post Falls 13.80 115.00Distr. Unattended 10
Potlatch 24.90 115.00Distr. Unattended 11
Prarie 13.80 115.00Distr. Unattended 12
Priest River 20.80 115.00Distr. Unattended 13
Rathdrum 115.00 230.00 13.80Trans & Distr Unattd 14
Sagle 21.80 115.00Dist. Unattended 15
Sandpoint 20.80 115.00Distr. Unattended 16
South Lewiston 13.80 115.00Distr. Unattended 17
Sweetwater 24.90 115.00Distr. Unattended 18
St. Maries 23.90 115.00Distr. Unattended 19
Tenth & Stewart 13.80 115.00Distr. Unattended 20
21
Other: 13 substa less than 10 MVA Distr. Unattended 22
23
STATE OF MONTANA 24
1 substation less than 10 MVA Distr. Unattended 25
26
SUBSTA. @ GENERATING PLANTS 27
STATE OF WASHINGTON 28
Boulder Park 13.80 115.00Trans. Attended 29
Kettle Falls 13.80 115.00Trans. Attended 30
Long Lake 4.00 115.00Trans. Attended 31
Nine Mile 13.80 115.00Trans. Attended 32
Little Falls 4.00 115.00Trans. Attended 33
Northeast 13.80 115.00Trans. Attended 34
Post Street 4.00 13.80Trans. Attended 35
36
STATE OF IDAHO 37
Cabinet Gorge (HED) 13.80 230.00Trans. Attended 38
Post Falls 2.30 115.00Trans. Attended 39
Rathdrum 13.80 115.00Trans. 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 04/15/2020 2019/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.
258 2 260 48Frcd Air Fan & Caps 1
12 1 20 1Two Stage Fan 2
10 1 13 1Frcd Air Fan 3
18 2 22 2Frcd Air Fan 4
20 2 28 1Frcd Oil & Air Fan 5
12 1 15 1Portable Fan 6
212 3 270 45Two Stg Fan/Capacito 7
12 1 20 1Two Stage Fan 8
12 1 20 1Two Stage Fan 9
18 1 30 1Two Stage Fan 10
15 2 19 2Portable Fan 11
12 1 20 1Frcd Oil & Air Fan 12
10 1 13 1Frcd Air Fan 13
474 4 490 50Frcd Oil & Air Fan 14
12 1 20 1Two Stage Fan 15
30 3 38 3Frcd Air Fan 16
27 4 39 4Port Fan/FrcdOil/Air 17
12 1 20 1Frcd Oil & Air Fan 18
24 2 40 2Two Stage Fan 19
30 2 50 2Frcd Oil/Air/Two Stg 20
21
73 13 22
23
24
5 1 25
26
27
28
36 1 60 1Two Stage Fan 29
34 1 1 62 1Two Stage Fan 30
80 4 1 31
42 2 56 1Two Stage Fan 32
24 2 40 2Frcd Oil & Air Fan 33
36 1 60 1Two Stage Fan 34
35 2 35
36
37
300 6 1 38
16 2 21 2Frcd Air/Oil/Air Fan 39
114 2 1 190 2Two Stage 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 04/15/2020 2019/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).
1
STATE OF MONTANA 2
Noxon 13.80 230.00Trans. Attended 3
4
STATE OF OREGON 5
Coyote Springs II 13.80 500.00 18.00Trans. Attended 6
7
SUMMARY: 8
Washington: 3 subs Trans. Unattended 9
76 subs Distr. Unattended 10
2 subs Tran & Dist Unattnd 11
7 subs Trans. Attended 12
Idaho 2 subs Trans. Unattended 13
48 subs Distr. Unattended 14
5 subs Tran & Dist Unattnd 15
3 subs Trans. Attended 16
Montana: 1 sub Trans. Attended 17
1 sub Distr. Unattended 18
Oregon: 1 sub Trans. Unattended 19
System: 149 subs 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 426.3
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 04/15/2020 2019/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
2
435 9 1 635 6Two Stage Fan 3
4
5
213 1 355 1Two Stage fan 6
7
8
575 9
1271 10
854 11
287 12
150 13
661 14
1368 15
430 16
435 17
5 18
213 19
6249 20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1 (ED. 12-96) Page 427.3
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
04/15/2020 2019/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
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 261,360Salix Inc. 146000
22 Corporate Support 281,610Avista Development Inc 146000
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. 1 (New) Page 429
FERC FORM NO. 1-F (New)