2012Annual Report.pdf

THIS FILING IS
Item 1:j An Initial (Original) OR J Resubmission No. -
Submission
AvUo; Form I Approved
OMB No.1902-0021
(Expires 12/3112014)
Form 1-F Approved
OMB No.1902-0029
(Expires 12/31/2014)
Form 3-Q Approved
OMB No. 1902-0205
(Expires 05/31/2014)
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4) c TJ
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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
Exact Legal Name of Respondent (Company) Year/Period of Report
Avista Corporation End of 2012/Q4
FERC FORM No.113-Q (REV. 02-04)
FERC FORM NO. 113-Q:
REPORT OF MAJOR Fl FCTRI( 11TH ITIFA I I(FWSFF AWfl OTHFP
IDENTIFICATION
01 Exact Legal Name of Respondent 02 Year/Period of Report
Avista Corporation End of 2012/Q4
03 Previous Name and Date of Change (if name changed during year)
/-
04 Address of Principal Office at End of Period (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
05 Name of Contact Person 06 Title of Contact Person
Christy Burmeister-Smith VP, Controller, Prin. Acctg
07 Address of Contact Person (Street, City, State, Zip Code)
1411 East Mission Avenue, Spokane, WA 99207
08 Telephone of Contact Person,including 09 This Report Is 10 Date of Report
Area Code (1) An Original (2) E A Resubmission (Mb, Da, Yr)
[phone] 04/12/2013
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.
01 Name 03 04 Date Signed 7;4z=i

(Mo, Da, Yr) Burmeister-Smith
? O
VP, Controller, Prin. Acctg Officer 04/12/2013
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.
FERC FORM No.113-Q (REV. 02-04) Page 1
Name of Respondent
Avista Corporation
This Re ort Is: Date of Report Year/Period of Report
End of 2012/Q4
LIST OF SCHEDULES (Electric Utility)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
-
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
1 General Information 101
2 1 Control Over Respondent 102 N/A
3 Corporations Controlled by Respondent 103
4 Officers 104
5 Directors 105
6 Information on Formula Rates 106(a)(b)
7 Important Changes During the Year 108-109
8 Comparative Balance Sheet 110-113
9 Statement of Income for the Year 114-117
10 Statement of Retained Earnings for the Year 118-119
11 Statement of Cash Flows 120-121
12 Notes to Financial Statements 122-123
13 Statement of Accum Comp Income, Comp Income, and Hedging Activities I 22(a)(b)
14 Summary of Utility Plant & Accumulated Provisions for Dep, Amort & Dep 200-201
15 Nuclear Fuel Materials 202-203 N/A
16 Electric Plant in Service 204-207
17 Electric Plant Leased to Others 213 N/A
18 Electric Plant Held for Future Use 214
19 Construction Work in Progress-Electric 216
20 Accumulated Provision for Depreciation of Electric Utility Plant 219
21 Investment of Subsidiary Companies 224-225
22 Materials and Supplies 227
23 Allowances 228(ab)-229(ab) N/A
24 Extraordinary Property Losses 230 N/A
25 Unrecovered Plant and Regulatory Study Costs 230 N/A
26 Transmission Service and Generation Interconnection Study Costs 231
27 Other Regulatory Assets 232
28 Miscellaneous Deferred Debits 233
29 j Accumulated Deferred Income Taxes 234
30 Capital Stock 250-251
31 Other Paid-in Capital 253
32 Capital Stock Expense 254
33 Long-Term Debt 256-257
34 Reconciliation of Reported Net Income with Taxable Inc for Fed Inc Tax 261
35 Taxes Accrued, Prepaid and Charged During the Year 262-263
36 Accumulated Deferred Investment Tax Credits 266-267
FERC FORM NO. 1 (ED. 12-96) Page 2
Name of Respondent
Avista Corporation
This Re ort Is:
(2) AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 20121Q4
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms 'none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line
No.
-
Title of Schedule
(a)
Reference
Page No.
(b)
Remarks
(c)
37 Other Deferred Credits 269
38 Accumulated Deferred Income Taxes-Accelerated Amortization Property 272-273 N/A
39 Accumulated Deferred Income Taxes-Other Property 274-275
40 Accumulated Deferred Income Taxes-Other 276-277
41 Other Regulatory Liabilities 278
42 Electric Operating Revenues 300-301
43 Regional Transmission Service Revenues (Account 457.1) 302 N/A
44 Sales of Electricity by Rate Schedules 304
45 Sales for Resale 310-311
46 Electric Operation and Maintenance Expenses 320-323
47 Purchased Power 326-327
48 Transmission of Electricity for Others 328-330
49 Transmission of Electricity by ISO/RTOs 331 N/A
50 Transmission of Electricity by Others 332
51 Miscellaneous General Expenses-Electric 335
52 Depreciation and Amortization of Electric Plant 336-337
53 Regulatory Commission Expenses 350-351
54 Research, Development and Demonstration Activities 352-353
55 Distribution of Salaries and Wages 354-355
56 Common Utility Plant and Expenses 356
57 Amounts included in ISO/RTO Settlement Statements 397 N/A
58 Purchase and Sale of Ancillary Services 398
59 Monthly Transmission System Peak Load - 400
60 Monthly ISO/RTO Transmission System Peak Load 400a N/A
61 Electric Energy Account 401
62 Monthly Peaks and Output 401
63 Steam Electric Generating Plant Statistics 402-403
64 Hydroelectric Generating Plant Statistics 406407
65 Pumped Storage Generating Plant Statistics 408-409 N/A
66 Generating Plant Statistics Pages 410-411
FERC FORM NO. I (ED. 12-96) Page 3
Name of Respondent This Report Is: Date of Report Year/Period of Report
Avista Corporation (1)An Original (Mo, Da, Yr) End of 2012/Q4
(2)flA Resubmission 04/12/2013
LIST OF SCHEDULES (Electric Utility) (continued)
Enter in column (c) the terms "none," "not applicable," or "NA," as appropriate, where no information or amounts have been reported for
certain pages. Omit pages where the respondents are "none," "not applicable," or "NA".
Line Title of Schedule Reference Remarks
No. Page No.
(a) (b) (C)
67 Transmission Line Statistics Pages 422-423
68 Transmission Lines Added During the Year 424-425
69 Substations 426-427
70 Transactions with Associated (Affiliated) Companies 429
71 Footnote Data 450
- Stockholders' Reports Check appropriate box:
Two copies will be submitted
Li No annual report to stockholders is prepared
FERC FORM NO. I (ED. 12-96) Page 4
Name of Respondent This Report Is: Date of Report Year/Period of Report
Avista Corporation (1)An Original (Mo, Da, Yr)
(2)J A Resubmission 04/12/2013 End of 2012/Q4
GENERAL INFORMATION
1.Provide name and title of officer having custody of the general corporate books of account and address of
office where the general corporate books are kept, and address of office where any other corporate books of account
are kept, if different from that where the general corporate books are kept.
C. Burmeister-Smith, Vice President, Controller, and Principal Accounting Officer
1411 E. Mission Avenue
Spokane, WA 99207
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.
State of Washington, Incorporated March 15, 1889
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.
Not Applicable
4.State the classes or utility and other services furnished by respondent during the year in each State in which
the respondent operated.
Electric service in the states of Washington, Idaho, and Montana
Natural gas service in the states of Wasington, Idaho, and Oregon
5.Have you engaged as the principal accountant to audit your financial statements an accountant who is not
the principal accountant for your previous year's certified financial statements?
(1)El Yes... Enter the date when such independent accountant was initially engaged:
(2)No
FERC FORM No.1 (ED. 12-87) PAGE 101
Name of Respondent
Avista Corporation
I This Re ort Is:
(1)An Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
CORPORATIONS CONTROLLED BY RESPONDENT
1.Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. 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.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(c)
Footnote
Ref.
(d)
1 Avista Capital, Inc. Parent company to the 100
2 Company's subsidiaries.
3
4 Ecova, Inc. Provider of utility bill 78.96 Subsidiary of
5 processing, payment and Avista Capital
6 information services to multi
7 site customers in North Amer.
8
9
10 Avista Development, Inc. Maintains an investment 100 Subsidiary of
11 portfolio of real estate and Avista Capital
12 other investments.
13
14 Avista Energy, Inc. Inactive 100 Subsidiary of
15 Avista Capital
16
17 Pentzer Corporation Parent company of Bay Area 100 Subsidiary of
18 Manufacturing and Pentzer Avista Capital
19 Venture Holdings.
20
21 Pentzer Venture Holdings Inactive 100 Subsidiary of
22 Pentzer Corporation
23
24 Bay Area Manufacturing Holding Company 100 Subsidiary of
25 Pentzer Corporation
26
27 Advanced Manufacturing and Development, Inc. Performs custom sheet metal 82.95 Subsidiary of
FERCtORM NO. I (ED. 12-96) Page 103
Name of Respondent
Avista Corporation
This Report Is:
[]A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
CORPORATIONS CONTROLLED BY RESPONDENT
1 Report below the names of all corporations, business trusts, and similar organizations, controlled directly or indirectly by respondent
at any time during the year. 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.
Line
No.
Name of Company Controlled
(a)
Kind of Business
(b)
Percent Voting
Stock Owned
(C)
Footnote
Ref.
(d)
1 dba Metalfx manufacturing of electronic Bay Area
2 enclosures, parts and systems Manufacturing.
3 for the computer, telecom and
4 medical industries. AM&D
5 also has a wood products
6 division.
7
8 Spokane Energy, LLC Owns an electric capactiy 100 Affiliate of
contract. Avista Corp.
10
11 1 Avista Capital II An affiliated business trust 100 Affliate of
12 formed by the Company. Avista Corp.
13 Issued Pref. Trust Securities
14
15 Avista Northwest Resources, LLC Formed in 2009 to own 100 Affiliate of
16 an interest in a venture Avista Capital
17 fund investment
18
19 1 Steam Plant Square, LLC Commercial office and retail 85 Affiliate of
20 leasing. Avista Development
21
22 Courtyard Office Center, LLC Commercial office and retail 100 Affiliate of
23 leasing. Avista Development
24
25 Steam Plant Brew Pub, LLC Restaurant operations 85 Affiliate of Steam
26 Plant Square, LLC
27
FERC FORM NO. I (ED. 12-96) Page 103.1
Name of Respondent
Avista Corporation
This Rep ort Is
(1)JAn Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
n o 2012/Q4
OFFICERS
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.
piO.
Line
(a)
Name of Officer
(b)
Salary for Year
(c)
1 Chairman of the Board, President S. L. Morris
2 and Chief Executive Officer
3
4 Senior Vice President and Chief Financial Officer M. T. Thies
5
6 Senior Vice President, General Counsel M. M. Durkin
7 and Chief Compliance Officer
8
9 Senior Vice President-and Corporate Secretary K. S. Feltes
10 responsible for Human Resources
11
12 Senior Vice President and Environmental D. P. Vermillion
13 Compliance Officer
14
15 Vice President, Controller and C. M. Burmeister-Smith
16 Principal Accounting Officer
17
18 Vice President and Chief Information Officer J. M. Kensok
19
20 Vice President, responsible for Energy Delivery D. F. Kopczynski
21 and Customer Service (effective 6/2012)
22
23 Vice President and Chief Counsel for Regulatory and D. J. Meyer
24 Governmental Affairs
25
26 Vice President, responsible for State and K. 0. Norwood
27 Federal Regulations
28
29 Vice President and Chief Strategy Officer R. D. Woodworth
30
31 Vice President, responsible for Customer Solutions J. R. Thackston
32 (effective 6/2012)
33
34 Treasurer D. C. Thoren
35
36 Vice President, Energy Resources R. L. Storro
37
38
39
40
41
42
43
44
FERC FORM NO. I (ED. 12-96) Page 104
Name of Respondent
Avista Corporation
This Report Is:
(2) []A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
DIRECTORS
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.
CI1 No. Name (and Title) of Director (a) Principal Business Address (b)
I Scott L. Morris** 1411 E Mission Ave., Spokane, WA, 99202
2 (Chairman of the Board, President & CEO)
3
4 Erik J. Anderson 3720 Carillon Point, Kirkland, WA 98033
5 -
6 Kristianne Blake*** P.O. Box 28338, Spokane, WA 99228
7
8 Donald C. Burke 16 Ivy Court, Langhorne, PA 19047
9
10 Rick R. Holley 999 Third Ave., Suite 4300, Seattle, WA 98104
11
12 John F. Kelly*** P.O. Box 5782, Ketchum, ID 83340
13
14 Michael L. Noel 11960W. Six Shooter Rd., Prescott, AZ 86305
15
16 Heidi B. Stanley P.O. Box 2884, Spokane, WA 99220
17
18 R. John Taylor*** 111 Main Street, Lewiston, ID 83501
19
20 Marc F. Racicot 28013 Swan Cove Dr., Big Fork, MT 59911
21
22 Rebecca A. Klein 611 S. Congress Ave., Suite 125, Austin, TX 78704
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46
47
48
FERC FORM NO. 1 (ED. 12-95) Page 105
Name of Respondent
Avista Corporation
This Re ort Is:
(1)I2 An Original
(2)E A Resubmission
Date of Report
(Mo, Da, Yr)
04/1212013
Year/Period of Report
End of 2012/Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent have formula rates? Yes
No
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.
Line
No. FERC Rate Schedule or Tariff Number FERC Proceeding
2
3
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FERC FORM NO. 1 (NEW. 12-08) Page 106
Name of Respondent
Avista Corporation
This ReDort Is: (1) j An Original
(2)Ep A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
INFORMATION ON FORMULA RATES
FERC Rate Schedule/Tariff Number FERC Proceeding
Does the respondent file with the Commission annual (or more frequent)
filings containing the inputs to the formula rate(s)? Yes
No
2. If yes, provide a listing of such filings as contained on the Commission's eLibrary website
- Line
No. Accession No.
Document
Date
\ Filed Date Docket No. Description
Formula Rate FERC Rate
Schedule Number or
Tariff Number
2
3
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5
6
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49
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FERC FORM NO. I (NEW. 12-08) Page 106a
Name of Respondent
Avista Corporation
This Rort Is: ep (1) An Original
(2)Ej A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
INFORMATION ON FORMULA RATES
Formula Rate Variances
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
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.
Line
No. Page No(s). Schedule Column Line No
2
3
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FERC FORM NO. 1 (NEW. 12-08) Page 106b
Name of RespondE
Avista Corporation (1)An Original End of 2012/Q4
(2)A Resubmission 04/12/2013
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 I 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.
PAGE 108 INTENTIONALLY LEFT BLANK
SEE PAGE 109 FOR REQUIRED INFORMATION.
FERC FORM NO. I (ED. 12-96) Page 108
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/12/2013 2012/Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
1.None
2.None
3.None
4.None
5.None
6.Avista Corp. has a committed line of credit with various financial institutions in the total amount of
$400.0 million with an expiration date of February 2017. The committed line of credit is secured by
non-transferable First Mortgage Bonds of the Company issued to the agent bank that would only become due
and payable in the event, and then only to the extent, that the Company defaults on its obligations under the
committed line of credit.
Balances outstanding under the Company's revolving committed line of credit were as follows as of December
31, 2012 and December 31, 2011 (dollars in thousands):
December 31, December 31,

2012 2011
Balance outstanding at end of period $52,000 $61,000
Letters of credit outstanding at end of period $35,885 $29,030
In June 2012, Avista Corp. entered into a bond purchase agreement with certain institutional investors in the
private placement market for the purpose of issuing $80.0 million of 4.23 percent First Mortgage Bonds due in
2047. The new First Mortgage Bonds were issued under and in accordance with the Mortgage and Deed of
Trust, dated as of June 1, 1939, from the Company to Citibank, N.A., trustee, as amended and supplemented by
various supplemental indentures and other instruments. The issuance of the bonds occurred at closing in
November 2012. The total net proceeds from the sale of the new bonds were used to repay a portion of the
borrowings outstanding under the Company's $400.0 million committed line of credit and for general corporate
purposes. The debt issuance was approved by regulatory commissions as follows:WUTC (Docket No.
U-i 11176 Order 02) IPUC (Case No. AVU-U-1 1-01 Order No. 32338) and the OPUC (Docket UF 4269 Order
No. 11-334).
7.On May 10, 2012, the shareholders of Avista Corp. approved an amendment of the Company's Restated
Articles of Incorporation and Bylaws to reduce certain shareholder approval requirements to reduce the approval
standards for shareholder voting to a "Majority of Votes Cast", where permissible under Washington law, and
otherwise to be the lowest threshold permitted by Washington law.
8.Average annual wage increases were 2.4% for non-exempt employees effective February 27, 2012. Average
annual wage increases were 2.7% for exempt employees effective February 27, 2012. Officers received average
increases of 3.5% effective February 27, 2012. Certain bargaining unit employees received increases of 3.0%
effective March 26, 2012.
9.Reference is made to Note 18 of the Notes to Financial Statements.
10.None
11.Reserved
12.See page 123 of this report.
13.Effective June 1, 2012, Avista Corp. appointed Don Kopczynski as Vice President of Operations and Jason
Thackston as Vice President of Customer Solutions. Mr. Kopczynski was previously Vice President of
Customer Solutions and Mr. Thackston was previously Vice President of Energy Delivery.
IFERC FORM NO. I (ED. 12-96) Page 109.1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 20121Q4
IMPORTANT CHANGES DURING THE QUARTER/YEAR (Continued)
14. Proprietary capital is not less than 30 percent.
IFERC FORM NO. I (ED. 12-96) Page 109.2 I
Name of Respondent
Avista Corporation
This Report Is:
(1)An original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
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)
UTILITY PLANT
2 Utility Plant (101-106,114) 200-201 4,044,184,930 3,876,924,839
3 Construction Work in Progress (107) 200-201 139,513,892 78,182,230
4 TOTAL Utility Plant (Enter Total of lines 2 and 3) 4,183,698,822 3,955,107,069
5 (Less) Accum. Prov. for Depr. Amort. DepI. (108, 110, 111, 115) 200-201 1,408,153,972 1,333,212,160
6 Net Utility Plant (Enter Total of line 4 less 5) 2,775,544,850 2,621,894,909
7 Nuclear Fuel in Process of Ref., Conv.,Enrich., and Fab. (120.1) 202-203 0 0
8 Nuclear Fuel Materials and Assemblies-Stock Account (120.2) 0 0
9 Nuclear Fuel Assemblies in Reactor (120.3) 0 0
10 Spent Nuclear Fuel (120.4) 0 0
11 Nuclear Fuel Under Capital Leases (120.6) 0 0
12 (Less) Accum. Prov. for Amort. of Nucl. Fuel Assemblies (120.5) 202-203 0 0
13 Net Nuclear Fuel (Enter Total of lines 7-11 less 12) 0 0
14 Net Utility Plant (Enter Total of lines 6 and 13) . 2,775,544,850 2,621,894,909
15 Utility Plant Adjustments (116) 0 0
16 Gas Stored Underground - Noncurrent (117) 6,992,0761 6,992,076
17 OTHER PROPERTY AND INVESTMENTS
18 Nonutility Property (12 1) 5,536,702 6,021,869
19 (Less) Accum. Prov. for Depr. and Amort. (122) 921,820 915,043
20 Investments in Associated Companies (123) . 12,047,000 12,047,000
21 Investment in Subsidiary Companies (123.1) 224-225 118,714,423 71,971,368
22 (For Cost of Account 123.1, See Footnote Page 224, line 42)
23 Noncurrent Portion of Allowances 228-229 0 0
24 Other Investments (124) 16,439,055 18,889,385
25 Sinking Funds (125) 0 0
26 Depreciation Fund (126) 0 0
27 Amortization Fund - Federal (127) 0 0
28 Other Special Funds (128) 9,154,874 13,288,292
29 Special Funds (Non Major Only) (129) 0 0
30 Long-Term Portion of Derivative Assets (175) 1,092,593 184,929
31 Long-Term Portion of Derivative Assets - Hedges (176) 7,265,426 0
32 TOTAL Other Property and Investments (Lines 18-21 and 23-31) 169,328,253 121,487,800
33 CURRENT AND ACCRUED ASSETS
34 Cash and Working Funds (Non-major Only) (130) 0 0
35 Cash (131) 2,624,516 945,496
36 Special Deposits (132-134) 2,716,333 22,215,906
37 Working Fund (135) 799,065 861,010
38 Temporary Cash Investments (136) 251,390 60,913
39 Notes Receivable (141) 234,901 283,666
40 Customer Accounts Receivable (142) 159,703,153 173,557,636
41 Other Accounts Receivable (143) 5,188,679 7,943,467
42 (Less) Accum. Prov. for Uncollectible Acct.-Credit (144) 4,653,167 4,498,489
43 Notes Receivable from Associated Companies (145) 314,682 0
44 Accounts Receivable from Assoc. Companies (146) 700,835 29,252
45 Fuel Stock (151) 227 4,120,767 4,248,389
46 Fuel Stock Expenses Undistributed (152) 227 0 0
47 Residuals (Elec) and Extracted Products (153) 227 0 0
48 Plant Materials and Operating Supplies (154) 227 23,875,397 21,746,205
49 Merchandise (155) 227 0 0
50 Other Materials and Supplies (156) 227 0 0
51 Nuclear Materials Held for Sale (157) 202-203/227 0 0
52 Allowances (158.1 and 158.2) 228-229 0 0
El I
FERC FORM NO. I (REV. 12-03) Page 110
Name of Respondent
Avista Corporation
This Report Is:
(1)EJ An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
- COMPARATIVE BALANCE SHEET (ASSETS AND OTHER DEBlTSContinued)
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)
53 (Less) Noncurrent Portion of Allowances 0 0
54 Stores Expense Undistributed (163) 227 0 0
.55 Gas Stored Underground - Current (164.1) 17,276,287 23,609,470
56 Liquefied Natural Gas Stored and Held for Processing (164.2-164.3) 0 0
57 Prepayments (165) 16,090,480 16,554,560
58 Advances for Gas (166-167) 0 0
59 Interest and Dividends Receivable (17 1) 31,981 85,059
60 Rents Receivable (172) 830,718 1,568,627
61 Accrued Utility Revenues (173) 0 0
62 Miscellaneous Current and Accrued Assets (174) 429,169 254,324
63 Derivative Instrument Assets (175) 5,231,375 1,323,663
64 (Less) Long-Term Portion of Derivative Instrument Assets (175) 1,092,593 184,929
65 Derivative Instrument Assets - Hedges (176) 7,265,426 32,408
66 (Less) Long-Term Portion of Derivative Instrument Assets - Hedges (176 7,265,426 0
67 Total Current and Accrued Assets (Lines 34 through 66) 234,673,968 270,636,633
68 DEFERRED DEBITS
69 Unamortized Debt Expenses (181) 13,532,890 141332,877
70 Extraordinary Property Losses (182.1) 230a 0 0
71 Unrecovered Plant and Regulatory Study Costs (182.2) 230b 0 0
72 Other Regulatory Assets (182.3) 232 559,831,454 524,250,326
73 Prelim. Survey and Investigation Charges (Electric) (183) 3,894,551 4,180,937
74 Preliminary Natural Gas Survey and Investigation Charges 183.1) 0 0
75 Other Preliminary Survey and Investigation Charges (183.2) 0 0
76 Clearing Accounts (184) 0 0
77 Temporary Facilities (185) 0 0
78 Miscellaneous Deferred Debits (186) 233 15,701,369 34,001,379
79 Def. Losses from Disposition of Utility PIt. (187) 0 0
80 Research, Devel. and Demonstration Expend. (188) 352-353 0 0
81 Unamortized Loss on Reaquired Debt (189) 21,635,414 23,830,734
82 Accumulated Deferred Income Taxes (190) - 234 148,425,469 153,408,420
83 Unrecovered Purchased Gas Costs (191) -6,916,577 -12,140,283
84 Total Deferred Debits (lines 69 through 83) 756,104,570 741,864,390
85 TOTAL ASSETS (lines 14-16, 32, 67, and 84) 3,942,643,717 3,762,875,808
FERC FORM NO. 1 (REV. 12-03) - Page 111
Name of Respondent
Avista Corporation
This Report is:
(1)An Original
(2)A Resubmission
Date of Report
(mo, da, yr)
04/12/2013
Year/Period of Report
end of 2012/Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITS) -
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)
1 PROPRIETARY CAPITAL
2 Common Stock Issued (201) 250-251 863,316,222 832,413,930
3 Preferred Stock Issued (204) 250-251 0 0
4 Capital Stock Subscribed (202, 205) 0 0
5 Stock Liability for Conversion (203, 206) 0 0
6 Premium on Capital Stock (207) 0 0
7 Other Paid-In Capital (208-211) 253 10,942,942 11,686,949
B Installments Received on Capital Stock (212) 252 0 0
9 (Less) Discount on Capital Stock (213) 254 0 0
10 (Less) Capital Stock Expense (214) 254b -14,977,565 -11,086,811
11 Retained Earnings (215, 215.1, 216) 118-119 377,687,824 364,536,285
12 Unappropriated Undistributed Subsidiary Earnings (216.1) 118-119 -747,337 -28,386,302
13 (Less) Reaquired Capital Stock (217) 250-251 0 0
14 Noncorporate Proprietorship (Non-major only) (218) 0 0
15 Accumulated Other Comprehensive Income (219) 122(a)(b) -6,700,160 -5,636,826
16 Total Proprietary Capital (lines 2 through 15) 1,259,477,056 1,185,700,847
17 LONG-TERM DEBT
18 Bonds (221) 256-257 1,336,700,000 1,257,171,208
19 (Less) Reaquired Bonds (222) 256-257 83,700,000 83,700,000
20 Advances from Associated Companies (223) 256-257 51,547,000 51,547,000
21 Other Long-Term Debt (224) 256-257 0 0
22 Unamortized Premium on Long-Term Debt (225) 204,316 213,200
23 (Less) Unamortized Discount on Long-Term Debt-Debit (226) 1,656,685 1,838,814
24 Total Long-Term Debt (lines 18 through 23) 1,303,094,631 1,223,392,594
25 OTHER NONCURRENT LIABILITIES
26 Obligations Under Capital Leases - Noncurrent (227) 4,491,191 4,749,777
27 Accumulated Provision for Property Insurance (228.1) 0 0
28 Accumulated Provision for Injuries and Damages (228.2) 700,447 3,235,000
29 Accumulated Provision for Pensions and Benefits (228.3) 283,984,764 246,176,609
30 Accumulated Miscellaneous Operating Provisions (228.4) 0 0
31 Accumulated Provision for Rate Refunds (229) 0 0
32 Long-Term Portion of Derivative Instrument Liabilities 26,310,290 40,530,269
33 Long-Term Portion of Derivative Instrument Liabilities - Hedges 0 2,641,867
34 Asset Retirement Obligations (230) 3,167,936 3512,818
35 Total Other Noncurrent Liabilities (lines 26 through 34) 318,654,628 300,846,340
36 CURRENT AND ACCRUED LIABILITIES
37 Notes Payable (231) 52,000,000 61,000,000
38 Accounts Payable (232) 116,147,642 98,160,779
39 Notes Payable to Associated Companies (233) 598 1,866,383
40 Accounts Payable to Associated Companies (234) 709,623 709,883
41 Customer Deposits (235) 3,323,152 8,868,640
42 Taxes Accrued (236) 262-263 22,309,642 8,292,344
43 Interest Accrued (237) 12,038,698 11,797,709
44 Dividends Declared (238) 0 0
45 Matured Long-Term Debt (239) 0 0
FERC FORM NO. I (rev. 12-03) Page 112
Name of Respondent
Avista Corporation
This Report is:
(1)An Original
(2)J A Resubmission
Date of Report
(mo, da, yr)
04/1212013
Year/Period of Report
end of 20121Q4
COMPARATIVE BALANCE SHEET (LIABILITIES AND OTHER CREDITntinued)
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)
46 Matured Interest (240) 0 0
47 Tax Collections Payable (241) 120,427 104,100
48 Miscellaneous Current and Accrued Liabilities (242) 61,331657 55,333,088
49 Obligations Under Capital Leases-Current (243) 258,586 224,884
50 Derivative Instrument Liabilities (244) 55,825,491 111353,644
51 (Less) Long-Term Portion of Derivative Instrument Liabilities 26,310,290 40,530,269
52 Derivative Instrument Liabilities - Hedges (245) 1,433,160 18,895,143
53 (Less) Long-Term Portion of Derivative Instrument Liabilities-Hedges 0 2,641,867
54 Total Current and Accrued Liabilities (lines 37 through 53) 299,188,386 333,434,461
55 DEFERRED CREDITS
56 Customer Advances for Construction (252) 947,342 947,213
57 Accumulated Deferred Investment Tax Credits (255) 266-267 12,613,058 10,400,886
58 Deferred Gains from Disposition of Utility Plant (256) 0 0
59 Other Deferred Credits (253) 269 26,169,966 26,584,147
60 Other Regulatory Liabilities (254) 278 55,244,962 20,939,852
61 Unamortized Gain on Reaquired Debt (257) 2,355,118 2,484,655
62 Accum. Deferred Income Taxes-Accel. Amort.(281) 272-277 0 0
63 Accum. Deferred Income Taxes-Other Property (282) 419,216,613 398,500,293
64 Accum. Deferred Income Taxes-Other (283) 245,681,957 259,644,520
65 Total Deferred Credits (lines 56 through 64) 762,229,016 718,501,566
66 TOTAL LIABILITIES AND STOCKHOLDER EQUITY (lines 16, 24, 35, 54 and 65) 3,942,643,717 3,762,875,808
FERC FORM NO. I (rev. 12-03) Page 113
Name of Respondent
Avista Corporation
This Report Is:
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/1212013
Year/Period of Report
End of 2012/Q4
STATEMENT OF INCOME
Quarterly
1.Report in column (C) the current year to date balance. Column (c) equals the total of adding the data in column (g) plus the data in column (i) plus the
data in column (k). Report in column (d) similar data for the previous year. This information is reported in the annual filing only.
2.Enter in column (e) the balance for the reporting quarter and in column (f) the balance for the same three month period for the prior year.
3.Report in column (g) the quarter to date amounts for electric utility function; in column (I) the quarter to date amounts for gas utility, and in column (k)
the quarter to date amounts for other utility function for the current year quarter.
4.Report in column (h) the quarter to date amounts for electric utility function; in column U) the quarter to date amounts for gas utility, and in column (I)
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.
Line
No.
-
Title of Account
(a)
(Ref.)
Page No.
(b)
Total
Current Year to
Date Balance for
Quarter/Year
(c)

Total Current 3 Months
Prior Year to Ended
Date Balance for Quarterly Only
Quarter/Year No 4Th Quarter

(d) (e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
1 UTILITY OPERATING INCOME
2 Operating Revenues (400) 300-301 1,494,227,540 1,617,162,384
31 Operating Expenses
4 Operation Expenses (401) 320-323 1,051630,004 1,169,781,695
5 Maintenance Expenses (402) 320-323 61377,568 57,411,515
6 Depreciation Expense (403) 336-337 102,188,312 96,771,421
7 Depreciation Expense for Asset Retirement Costs (403.1) 336-337
8 1 Aniort. & Dept. of Utility Plant (404405) 336-337 12,353,382 11307,561
9 Amort. of Utility Plant Acq. Adj. (406) 336-337 99,047 99,047
10 Amort. Property Losses, Unrecov Plant and Regulatory Study Costs (407)
11 Amort. of Conversion Expenses (407)
12 Regulatory Debits (407.3) 5,612,331 3,529,991
13 (Less) Regulatory Credits (407.4) 24,170,474 19,872,716
14 Taxes Other Than Income Taxes (408.1) 262263 83,263,801 83,348,911
15 Income Taxes -Federal (409.1) 262-263 14,435,558 23,554,951
16 - Other (409.1) 262-263 379,911 1,264,963
17 Provision for Deferred Income Taxes (410.1) 234, 272-277 35,782,466 29,793,186
18 (Less) Provision for Deferred Income Taxes-Cr. (411.1) 234,272-277 4,224,555 2,475,028
19 Investment Tax Credit Adj. -Net (411.4) 266 2,073,106 2,458,952
20 (Less) Gains from Disp. of Utility Plant (411.6)
21 Losses from Disp. of Utility Plant (411.7)
22 (Less) Gains from Disposition of Allowances (411.8)
231 Losses from Disposition of Allowances (411.9)
24 Accretion Expense (411.10)
25 TOTAL Utility Operating Expenses (Enter Total of lines 4 thru 24) 1,340,800,457 1,456,974,449
26 Net Util Oper Inc (Enter Tot line 2 less 25) Carry to Pg117,11ne 27 153,427,083 160,187,935
FERC FORM NO. 113-Q (REV. 02-04) Page 114
Name of Respondent This Report Is: Date of Report Year/Period of Report
Avista Corporation (1)An Original (Mo, Da, Yr) End of 2012/Q4
(2)flA Resubmission 0411212013
STATEMENT OF INCOME FOR THE YEAR (Continued)
9.Use page 122 for important notes regarding the statement of income for any account thereof.
10.Give concise explanations concerning unsettled rate proceedings where a contingency exists such that refunds of a material amount may need to be
made to the utility's customers or which may result in material refund to the utility with respect to power or gas purchases. State for each year effected
the gross revenues or costs to which the contingency relates and the tax effects together with an explanation of the major factors which affect the rights
of the utility to retain such revenues or recover amounts paid with respect to power or gas purchases.
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.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY -
Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Current Year to Date Previous Year to Date Line
(in dollars) (in dollars) (in dollars) (in dollars) (in dollars) (in dollars) No.
(g) (h) (i) (j) (k)
1,017,916,105 1,053,850,680 476,311,435 563,311,704 2
3
664,363,922 702,686,156 387,266,082 467,095,539 4
50,481,432 47,524,279 10,896,136 9,887,236 5
83,017,204 78,744,936 19,171,108 18,026,485 6
7
9,725,903 9,015,875 2,627,479 2,291,686 8
99,047 99,047
10
11
4,618,160 3,366,279 994,171 163,712 12
22,537,730 17,238,278 1,632,744 2,634,438 13
62,217,029 61,363,417 21,046,772 21,985,494 14
16,824,429 23,647,758 -2,388,871 -92,807 15
432,992 922,947 -53,081 342,016 16
24,012,637 17,702,120 11,769,829 12,091,066 17
4,120,508 2,793,831 104,047 -318,803 18
2,115,166 2,502,656 -42,060 -43,704 19
20
21
22
23
24
891,249,683 927,543,361 449,550,774 529,431,088 25
126,666,422 126,307,319 26,760,661 33,880,616 26
FERC FORM NO. 1 (ED. 12-96) Page 115
FERC FORM NO. 113-Q (REV. 02-04) Page 117
Name of Respondent This Re ort Is Date of Report Year/Period of Report
Avista Corporation
[:]A Resubmission 04/1212013 End of 2012IQ4
STATEMENT OF INCOME FOR THE YEAR (continued)
Line
No.
-
Title of Account
(a)
(Ref.)
Page No.
(b)
TOTAL Current 3 Months
Ended
Quarterly Only
No 4th Quarter
(e)
Prior 3 Months
Ended
Quarterly Only
No 4th Quarter
(f)
Current Year
(c)
Previous Year
(d)
27 1 Net Utility Operating Income (Carried forward from page 114) 153,427,083 160,187,935
28 Other Income and Deductions
29 Other Income
30 Nonutilty, Operating Income
31 Revenues From Merchandising, Jobbing and Contract Work (415) I
32 (Less) Costs and Exp. of Merchandising, Job. & Contract Work (416)
331 Revenues From Nonutility , Operations (417) -236 -21,355
34 (Less) Expenses of Nonutility Operations (417.1) 8,415,859 6,836,563
35 Nonoperating Rental Income (418) -2,749 -2,731
36 Equity in Earnings of Subsidiary Companies (418.1) 119 -1,206,861 9,971,326
37 Interest and Dividend Income (419) 1,864,293 1,293,357
38 Allowance for Other Funds Used During Construction (419.1) 4,054,947 2,224,987
39 Miscellaneous Nonoperating Income (421)
40 Gain on Disposition of Property (421.1) 31,120
41 TOTAL Other Income (Enter Total of lines 31 thru 40) -3,706,4651 6,660,141
42 Other Income Deductions
43 Loss on Disposition of Property (421.2)
44 1 Miscellaneous Amortization (425) 304,717
45 Donations (426.1) 2,272,123 2,143,177
46 Life Insurance (426.2) 2,533,552 2,253,671
47 Penalties (426.3) 15,251 281,762
48 Exp. for Certain Civic, Political & Related Activities (426.4) 1,414,3381 1,186,022
49 Other Deductions (426.5) 1,815,326 407,223
50 TOTAL Other Income Deductions (Total of lines 43 thru 49) 8,050,590 6,576,572
51 Taxes Applic. to Other Income and Deductions
52 Taxes Other Than Income Taxes (408.2) 262-263 145,213 -2,275
53 Income Taxes-Federal (409.2) 262-263 106,965 -962,923
54 Income Taxes-Other (409.2) 262-263 -1,231,456 -349,700
55 Provision for Deferred Inc. Taxes (410.2) 234,272-277 -520,718 40,666
56 (Less) Provision for Deferred Income Taxes-Cr. (411.2) 234,272-277 5,190,742 4,710,550
57 Investment Tax Credit Adj.-Net (411.5)
58 (Less) Investment Tax Credits (420)
59 TOTAL Taxes on Other Income and Deductions (Total of lines 52-58) -6,690,738 -5,984,782
60 Net Other Income and Deductions (Total of lines 41, 50, 59) -5,066,317 6,068,351
61 Interest Charges
62 Interest on Long-Term Debt (427) 65,281,624 61,400,721
63 Amort. of Debt Disc, and Expense (428) 447,351 604,805
64 Amortization of Loss on Required Debt (428.1) 3,364,150 4,021,281
65 (Less) Amort. of Premium on Debt-Credit (429) 8,883 8,883
66 (Less) Amortization of Gain on Reaquired Debt-Credit (429.1)
67 Interest on Debt to Assoc. Companies (430) 885,123 -26,307
68 Other Interest Expense (431) 2,582,407 2,983,099
69 (Less) Allowance for Borrowed Funds Used During Construction-Cr. (432) 2,401,072 2,942,302
70 Net Interest Charges (Total of lines 62 thru 69) 70,150,700 66,032,414
71 Income Before Extraordinary Items (Total of lines 27,60 and 70) 78,210,066 100,223,872
72 Extraordinary Items
73 Extraordinary Income (434)
74 (Less) Extraordinary Deductions (435)
75 Net Extraordinary Items (Total of line 73 less line 74)
76 Income Taxes-Federal and Other (409.3) 262-263
77 Extraordinary Items After Taxes (line 75 less line 76)
78 Net Income (Total of line 71 and 77) . 78,210,066 100,223,872
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Re Is: Date of Report p (1)An Original (Mo, Da, Yr)
(2)fl A Resubmission 04/12/2013
Year/Period of Report
2012/Q4 n 0 ____________
STATEMENT OF RETAINED EARNINGS
1.Do not report Lines 49-53 on the quarterly version.
2.Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4.State the purpose and amount of each reservation or appropriation of retained earnings.
5.List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6.Show dividends for each class and series of capital stock.
7.Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8.Explain in a footnote the basis for determining the amount reserved or appropriated. 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.
Line
No.
Item
(a)
Contra Primary
Account Affected
(b)
Current
Quarter/Year
Year to Date
Balance
(c)
Previous
Quarter/Year
Year to Date
Balance
(d)
UNAPPROPRIATED RETAINED EARNINGS (Account 216)
1 Balance-Beginning of Period 325,313,182 1
2 Changes
AI 362.988,1641

3 Adjustments to Retained Earnings (Account 439)
4 I 10,509,950
9 TOTAL Credits to Retained Earnings (Acct. 439) 10,509,950
10
11
12
13
14
15 TOTAL Debits to Retained Earnings (Acct. 439)
16 Balance Transferred from Income (Account 433 less Account 418.1) 79,416,927 90,252,546
17 Appropriations of Retained Earnings (Acct. 436)
18
19
20
21
22 TOTAL Appropriations of Retained Earnings (Acct. 436)
23 Dividends Declared-Preferred Stock (Account 437)
24
25
26
27
28
29 TOTAL Dividends Declared-Preferred Stock (Acct. 437)
30 Dividends Declared-Common Stock (Account 438)
31 -68,552,375 ( 63,736,956)
32
33
34
35
36 TOTAL Dividends Declared-Common Stock (Acct. 438) -68,552,375 ( 63,736,956)
37 Transfers from Acct 216.1, Unapprop. Undistrib. Subsidiary Earnings 2,286,9871 649,442
38 Balance - End of Period (Total 1,9,15,16,22,29,36,37) 376,139,703 362,988,164
= APPROPRIATED RETAINED EARNINGS (Account 215)
FERC FORM NO. 1/3-Q (REV. 02-04) Page 118
Name of Respondent This Rep ort Is: Date of Report Year/Period of Report
Avista Corporation (1)FX1An Original (Mo, Da, Yr) 20121Q4 flu Ou (2)EA Resubmission 04/12/2013
STATEMENT OF RETAINED EARNINGS
1.Do not report Lines 49-53 on the quarterly version.
2.Report all changes in appropriated retained earnings, unappropriated retained earnings, year to date, and unappropriated
undistributed subsidiary earnings for the year.
3.Each credit and debit during the year should be identified as to the retained earnings account in which recorded (Accounts 433, 436
- 439 inclusive). Show the contra primary account affected in column (b)
4.State the purpose and amount of each reservation or appropriation of retained earnings.
5.List first account 439, Adjustments to Retained Earnings, reflecting adjustments to the opening balance of retained earnings. Follow
by credit, then debit items in that order.
6.Show dividends for each class and series of capital stock.
7.Show separately the State and Federal income tax effect of items shown in account 439, Adjustments to Retained Earnings.
8.Explain in a footnote the basis for determining the amount reserved or appropriated. 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.
Current Previous
Quarter/Year Quarter/Year
Contra Primary Year to Date Year to Date
Line Item Account Affected Balance Balance
No. (a) (b) (c) (d)
1,548,121 1,548,121
40
41
42
43
44
45 TOTAL Appropriated Retained Earnings (Account 215) 1 1,548,1211 1,548,121
- APPROP. RETAINED EARNINGS - AMORT. Reserve, Federal (Account 215.1)
46 TOTAL Approp. Retained Earnings-Amort. Reserve, Federal (Acct. 215.1)
47 TOTAL Approp. Retained Earnings (Acct. 215, 215.1) (Total 45,46) 1,548,1211 1,548,121
481 TOTAL Retained Earnings (Acct. 215, 215.1, 216) (Total 38, 47) (216.1) I 377,687,8241 364,536,285
- UNAPPROPRIATED UNDISTRIBUTED SUBSIDIARY EARNINGS (Account
Report only on an Annual Basis, no Quarterly
49 Balance-Beginning of Year (Debit or Credit) 28,386,3021 ( 24,343,434)'
50 Equity in Earnings for Year (Credit) (Account 418.1) -1206,861 9,971,326
51 (Less) Dividends Received (Debit)
52 Equity transactions of subsidiaries 28,845,826 ( 14,014,194)
53 Balance-End of Year (Total lines 49 thru 52) -747,337 ( 28,386,302)
FERC FORM NO. 1/3-a (REV. 02-04) Page 119
Name of Respondent
Avista Corporation
This Re ort Is:
(1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
STATEMENT OF CASH FLOWS
(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 US0fA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost.
Line
No.
-
Description (See Instruction No. 1 for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
(b)
Previous Year to Date
Quarter/Year
(c)
1 Net Cash Flow from Operating Activities:
2 Net Income (Line 78(c) on page 117) 78,210,066 100,223,872
3 INoncash Charges (Credits) to Income:
4 Depreciation and Depletion 112,091,663 105,727,999
5 Amortization of deferred power and natural gas costs 6,702,266 21,869,528
6 Amortization of debt expense 3,802,618 4,617,203
7 Amortization of investment in exchange power 2,450,031 2,450,030
8 Peferred Income Taxes (Net) 19,589,845 21,115,803
9 Investment Tax Credit Adjustment (Net) 2,212,172 2,558,524
10 Net (Increase) Decrease in Receivables 12,838,942 3,428,347
11 Net (Increase) Decrease in Inventory 4,331,613 -2,737,133
12 Net (Increase) Decrease in Allowances Inventory
13 Net Increase (Decrease) in Payables and Accrued Expenses 31,767,362 -1,250,437
14 Net (Increase) Decrease in Other Regulatory Assets -4,674,400 10,565,705
15 Net Increase (Decrease) in Other Regulatory Liabilities -4,241,041 -11,754,169
16 (Less) Allowance for Other Funds Used During Construction 4,054,947 2,224,987
17 (Less) Undistributed Earnings from Subsidiary Companies -1,206,861 9,971,326
18 Other (provide details in footnote) 17,162,806 15689679
19 Allowance for doubtful accounts 3,973,772 651,650
20 Changes in other non-current assets and liabilities -7,388,676 -816,072
21
22 Net Cash Provided by (Used in) Operating Activities (Total 2 thru 21) 275,980,953 228,764,858
23
24 Cash Flows from Investment Activities:
25 Construction and Acquisition of Plant (including land):
26 Gross Additions to Utility Plant (less nuclear fuel) -268,743,138 -240,025,802
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
34 Cash Outflows for Plant (Total of lines 26 thru 33) . -268,743,138 -240,025,802
35
36 Acquisition of Other Noncurrent Assets (d)
37 Proceeds from Disposal of Noncurrent Assets (d)
38 IFederal grant payments received 8,277,036 16,927,752
39 Investments in and Advances to Assoc. and Subsidiary Companies -19,138,510 -5,482,493
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. I (ED. 12-96) Page 120
Name of Respondent
Avista Corporation
This Re ort Is:
(2) E:] A Resubmission
Date of Report °'''
04/12/2013
Year/Period of Report
End of 2012/04
STATEMENT OF CASH FLOWS
(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 US0fA General Instruction 20; instead provide a reconciliation of the
dollar amount of leases capitalized with the plant cost
Line
No.
Description (See Instruction No. I for Explanation of Codes)
(a)
Current Year to Date
Quarter/Year
(b)
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):
54 jChanges in other property and investments 4,540198 -1754,160
I I
56 Net Cash Provided by (Used in) Investing Activities
57 Total of lines 34 thru 55) I -275,064,414 1 230,384,703
58
59 Cash Flows from Financing Activities:
60 Proceeds from Issuance of:
61 Long-Term Debt (b) I 80,000,000 ! 85,000,000
62 Preferred Stock
63 Common Stock 29,078,745 26,462,920
64 Other (provide details in footnote):
65
66 Net Increase in Short-Term Debt (C)
67 Other (provide details in footnote):
68
69
70 Cash Provided by Outside Sources (Total 61 thru 69) 109,078,7451 111,462,920
71
72 Payments for Retirement of:
73 Long-term Debt (b) -11,324,884 -195,575
74 Preferred Stock
75 Common Stock
76 Other (provide details in footnote):
77 Debt issuance costs 763,603 4477,097
78 Net Decrease in Short-Term Debt (C) -9,000,000 -49,000,000
79 Cash paid for settlement of interest rate swap -18,546,870 -10,557,000
80 Dividends on Preferred Stock
81 Dividends on Common Stock -68,552,375 -63,736,957
82 Net Cash Provided by (Used in) Financing Activities
83 (Total of lines 70 thru 81) 891,0131 -16,503,709
84
85 Net Increase (Decrease) in Cash and Cash Equivalents
86 (Total of lines 22,57 and 83) 1,807,552 -18,073,554
87
88 Cash and Cash Equivalents at Beginning of Period 1,867,4191 19,940,973
89
90 Cash and Cash Equivalents at End of period 3,674,971 1,867,419
FERC FORM NO. I (ED. 12-96) Page 121
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
FOOTNOTE DATA
Schedule Page: 120 Line No.: 18 Column: b
Power and natural gas deferrals 1,704,991
Change in special deposits 9,792,264
Change in other current assets 1,080,222
Non-cash stock compensation 4,549,448
Cash paid for foreign currency hedges 35,881
Schedule Page: 120 Line No.: 18 Column: c
Power and natural gas deferrals 193,076
Change in special deposits (14,234,011)
Change in other current assets (5,795,951)
Non-cash stock compensation 4,147,207
IFERC FORM NO.1 (ED. 12-87) Page 450.1 I
This Page Intentionally Left Blank
Name of Respondent This Report Is: Date of Report Year/Period of Report
Avista Corporation (1) An original 04/12/2013 End of 20121Q4
(2) A Resubmission
NOTES TO FINANCIAL STATEMENTS
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.
PAGE 122 INTENTIONALLY LEFT BLANK
SEE PAGE 123 FOR REQUIRED INFORMATION.
FERC FORM NO. I (ED. 12-96) Page 122
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Nature of Business
Avista Corporation (Avista Corp. or the Company) is an energy company engaged in the generation, transmission and distribution of
energy, as well as other energy-related businesses. Avista Corp. generates, transmits and distributes electricity in parts of eastern
Washington and northern Idaho. In addition, Avista Corp. has electric generating facilities in Montana and northern Oregon. Avista
Corp. also provides natural gas distribution service in parts of eastern Washington and northern Idaho, as well as parts of northeastern
and southwestern Oregon. Avista Capital, Inc. (Avista Capital), a wholly owned subsidiary of Avista Corp., is the parent company of
all of the subsidiary companies, except Spokane Energy, LLC (Spokane Energy). Avista Capital's subsidiaries include Ecova, Inc.
(Ecova), a 79.0 percent owned subsidiary as of December 31, 2012. Ecova is a provider of energy efficiency and other facility
information and cost management programs and services for multi-site customers and utilities throughout North America.
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 and (6) comprehensive
income.
Use of Estimates
The preparation of the financial statements in conformity with accounting principles generally accepted in the United States of
America (U.S. GAAP) requires management to make estimates and assumptions that affect amounts reported in the financial
statements. Significant estimates include:
• determining the market value of energy commodity derivative assets and liabilities,
• pension and other postretirement benefit plan obligations,
• contingent liabilities,
• 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.
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 Federal Energy Regulatory Commission (FERC) and adopted by the state regulatory commissions in Washington,
Idaho, Montana and Oregon.
Regulation
The Company is subject to state regulation in Washington, Idaho, Montana and Oregon. The Company is also subject to federal
regulation primarily by the FERC, as well as various other federal agencies with regulatory oversight of particular aspects of its
operations.
Operating Revenues
IFERC FORM NO. I (ED. 12-88) Page 123.1 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04112/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Revenues related to the sale of energy are recorded when service is rendered or energy is delivered to customers. The determination of
the energy sales to individual customers is based on the reading of their meters, which occurs on a systematic basis throughout the
month. At the end of each calendar month, the amount of energy delivered to customers since the date of the last meter reading is
estimated and the corresponding unbilled revenue is estimated and recorded.
Accounts receivable includes unbilled energy revenues of the following amounts as of December 31 (dollars in thousands):
2012 2011
Unbilled accounts receivable $ 77,298 $ 82,950
Advertising Expenses
The Company expenses advertising costs as incurred. Advertising expenses were not a material portion of the Company's operating
expenses in 2012 and 2011.
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:
2012 2011
Ratio of depreciation to average depreciable property 2.92% 2.92%
The average service lives for the following broad categories of utility plant in service are:
• electric thermal production - 33 years,
• hydroelectric production - 73 years,
• electric transmission - 51 years,
• electric distribution - 38 years, and
• natural gas distribution property -49 years.
Taxes Other Than Income Taxes
Taxes other than income taxes include state excise taxes, city occupational and franchise taxes, real and personal property taxes and
certain other taxes not based on net income. These taxes are generally based on revenues or the value of property. Utility related taxes
collected from customers (primarily state excise taxes and city utility taxes) are recorded as operating revenue and expense and totaled
the following amounts for the years ended December 31 (dollars in thousands):
2012 2011
Utility taxes $ 53,716 $ 55,739
Allowance for Funds Used During Construction
The Allowance for Funds Used During Construction (AFUDC) represents the cost of both the debt and equity funds used to finance
utility plant additions during the construction period As prescribed by regulatory authorities, AFUDC is capitalized as a part of the
cost of utility plant and the debt related portion is credited against total interest expense in the Statements of Income. The Company is
permitted, under established regulatory rate practices, to recover the capitalized AFUDC, and a reasonable return thereon, through its
inclusion in rate base and the provision for depreciation after the related utility plant is placed in service. Cash inflow related to
AFUDC does not occur until the related utility plant is placed in service and included in rate base. The effective AFUDC rate was the
following for the years ended December 31:
2012 2011
Effective AFUDC rate 762% 7.91%
FERC FORM NO. 1 (ED. 1218) Page 123.2 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1) An Original (Mo, Da, Yr)
Avista Corporation (2)_ AResubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Income Taxes
A deferred income tax asset or liability is determined based on the enacted tax rates that will be in effect when the differences between
the financial statement carrying amounts and tax basis of existing assets and liabilities are expected to be reported in the Company's
consolidated income tax returns. The deferred income tax expense for the period is equal to the net change in the deferred income tax
asset and liability accounts from the beginning to the end of the period. The effect on deferred income taxes from a change in tax rates
is recognized in income in the period that includes the enactment date. Deferred income tax liabilities and regulatory assets are
established for income tax benefits flowed through to customers as prescribed by the respective regulatory commissions.
Stock-Based Compensation
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. See Note 17 for further information.
Cash and Cash Equivalents
For the purposes of the Statements of Cash Flows, the Company considers all temporary investments with a maturity of three months or
less when purchased to be cash equivalents.
Allowance for Doubtful Accounts
The Company maintains an allowance for doubtful accounts to provide for estimated and potential losses on accounts receivable. The
Company determines the allowance for utility and other customer accounts receivable based on historical write-offs as compared to
accounts receivable and operating revenues. Additionally, the Company establishes specific allowances for certain individual accounts.
Utility Plant in Service
The cost of additions to utility plant in service, including an allowance for funds used during construction and replacements of units of
property and improvements, is capitalized. The cost of depreciable units of property retired plus the cost of removal less salvage is
charged to accumulated depreciation.
Derivative Assets and Liabilities
Derivatives are recorded as either assets or liabilities on the Balance Sheets measured at estimated fair value. In certain defined
conditions, a derivative may be specifically designated as a hedge for a particular exposure. The accounting for derivatives depends on
the intended use of the derivatives and the resulting designation.
The Washington Utilities and Transportation Commission (UTC) and the Idaho Public Utilities Commission (IPUC) issued accounting
orders authorizing Avista Corp. to offset commodity derivative assets or liabilities with a regulatory asset or liability. This accounting
treatment is intended to defer the recognition of mark-to-market gains and losses on energy commodity transactions until the period of
settlement. The orders provide for Avista Corp. to not recognize the unrealized gain or loss on utility derivative commodity
instruments in the Statements of Income. Realized gains or losses are recognized in the period of settlement, subject to approval for
recovery through retail rates. Realized gains and losses, subject to regulatory approval, result in adjustments to retail rates through
purchased gas cost adjustments, the Energy Recovery Mechanism (ERM) in Washington, the Power Cost Adjustment (PCA)
mechanism in Idaho, and periodic general rates cases. Regulatory assets are assessed regularly and are probable for recovery through
future rates.
Substantially all forward contracts to purchase or sell power and natural gas are recorded as derivative assets or liabilities at estimated
fair value with an offsetting regulatory asset or liability. Contracts that are not considered derivatives are accounted for on the accrual
basis until they are settled or realized, unless there is a decline in the fair value of the contract that is determined to be other than
temporary.
Fair Value Measurements
Fair value represents the price that would be received to sell an asset or paid to transfer a liability (an exit price) in an orderly
transaction between market participants at the measurement date. Energy commodity derivative assets and liabilities, deferred
compensation assets, as well as derivatives related to interest rate swap agreements and foreign currency exchange contracts, are
reported at estimated fair value on the Balance Sheets. See Note 15 for the Company's fair value disclosures.
IFERC FORM NO. I (ED. 12-88) Page 123.3
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Regulatory Deferred Charges and Credits
The Company prepares its financial statements in accordance with regulatory accounting practices because:
rates for regulated services re established by or subject to approval by independent third-party regulators,
the regulated rates are designed to recover the cost of providing the regulated services, and
in view of demand for the regulated services and the level of competition, it is reasonable to assume that rates can be
charged to and collected from customers at levels that will recover costs.
Regulatory accounting practices require that certain costs and/or obligations (such as incurred power and natural gas costs not
currently included in rates, but expected to be recovered or refunded in the future) are reflected as deferred charges or credits on the
Balance Sheets. These costs and/or obligations are not reflected in the Statements of Income until the period during which matching
revenues are recognized. If at some point in the future the Company determines that it no longer meets the criteria for continued
application of regulatory accounting practices for all or a portion of its regulated operations, the Company could be:
required to write off its regulatory assets, and
precluded from the future deferral of costs not recovered through rates at the time such costs are incurred, even if the
Company expected to recover such costs in the future.
See Note 20 for further details of regulatory assets and liabilities.
Investment in Exchange Power-Net
The investment in exchange power represents the Company's previous investment in Washington Public Power Supply System Project
3 (WNP-3), a nuclear project that was terminated prior to completion. Under a settlement agreement with the Bonneville Power
Administration in 1985, Avista Corp. began receiving power in 1987, for a 32.5-year period, related to its investment in WNP-3.
Through a settlement agreement with the UTC in the Washington jurisdiction, Avista Corp. is amortizing the recoverable portion of its
investment in WNP-3 (recorded as investment in exchange power) over a 32.5-year period that began in 1987. For the Idaho
jurisdiction, Avista Corp. fully amortized the recoverable portion of its investment in exchange power.
Unamortized Debt Expense
Unamortized debt expense includes debt issuance costs that are amortized over the life of the related debt.
Unamortized Loss on Reacquired Debt
For the Company's Washington regulatory jurisdiction and for any debt repurchases beginning in 2007 in all jurisdictions, premiums
paid to repurchase debt are amortized over the remaining life of the original debt that was repurchased or, if new debt is issued in
connection with the repurchase, these costs are amortized over the life of the new debt. In the Company's other regulatory
jurisdictions, premiums paid to repurchase debt prior to 2007 are being amortized over the average remaining maturity of outstanding
debt when no new debt was issued in connection with the debt repurchase. These costs are recovered through retail rates as a
component of interest expense.
Contingencies
The Company has unresolved regulatory, legal and tax issues which have inherently uncertain outcomes. The Company accrues a loss
contingency if it is probable that a liability has been incurred and the amount of the loss or impairment can be reasonably estimated.
The Company also discloses losses that do not meet these conditions for accrual, if there is a reasonable possibility that a loss may be
incurred.
NOTE 2. NEW ACCOUNTING STANDARDS
Effective January 1, 2012, the Company adopted Accounting Standards Update (ASU) No. 2011-04, "Fair Value Measurement (Topic
820): Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and IFRSs." This ASU
requires enhanced disclosures for fair value measurements, including quantitative analysis of unobservable inputs used in Level 3 fair
value measurements. The ASU also clarifies the FASB's intent about the application of existing fair value measurement requirements.
IFERC FORM NO. 1 (ED. 12-88) Page 123.4
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The adoption of this ASU did not have any impact on the Company's financial condition, results of operations and cash flows. See
Note 15 for the Company's fair value disclosures.
In February 2013, the FASB issued ASU No. 2013-02, "Comprehensive Income (Topic 220): Reporting of Amounts Reclassified Out
of Accumulated Other Comprehensive Income." This ASU does not change current requirements for reporting net income or other
comprehensive income in financial statements; however, it will require entities to disclose the effect on the line items of net income for
reclassifications out of accumulated other comprehensive income if the item being reclassified is required to be reclassified in its
entirety to net income under U.S. GAAP. For other items that are not required to be reclassified in their entirety to net income under
U.S. GAAP, an entity is required to cross-reference other disclosures required under U.S. GAAP to provide additional detail about
those items. This ASU is effective for fiscal years beginning after December 15, 2012. The Company does not expect that this ASU
will have any material impact on its financial condition, results of operations and cash flows.
In December 2011, the FASB issued ASU No. 2011-11, "Balance Sheet (Topic 210): Disclosures about Offsetting Assets and
Liabilities." This ASU enhances disclosure requirements about the nature of an entity's right to offset and related arrangements
associated with its financial instruments and derivative instruments. ASU No. 2011-11 requires the disclosure of the gross amounts
subject to rights of set-off, amounts offset in accordance with the accounting standards followed, and the related net exposure. The
Company will be required to adopt this ASU effective January 1, 2013. Adoption of this ASU will require additional disclosures in the
Company's financial statements; however, the Company does not expect that this ASU will have any material impact on its financial
condition, results of operations and cash flows.
In January 2013, the FASB issued ASU No. 2013-01, "Balance Sheet (Topic 210): Clarifying the Scope of Disclosures about
Offsetting Assets and Liabilities." This ASU clarifies which instruments and transactions are subject to the enhanced disclosure
requirements of ASU 2011-11 regarding the offsetting of financial assets and liabilities. ASU No. 2013-01 limits the scope of ASU
No. 2011-11 to only recognized derivative instruments, repurchase agreements and reverse repurchase agreements, and borrowing and
lending securities transactions that are offset in accordance with either ASC 210-20-45 or ASC 815-10-45. The Company will be
required to adopt this ASU effective January 1, 2013. The Company does not expect that this ASU will have a material impact on its
financial condition, results of operations and cash flows.
NOTE 3. VOLUNTARY SEVERANCE INCENTIVE PROGRAM
On October 22, 2012, Avista Corp. announced a voluntary severance incentive program to reduce the total utility workforce
and achieve necessary long-term, sustainable, Company-wide savings, in addition to other cost saving measures.
In general, most regular full and part-time employees of Avista Corp. (not including any of its subsidiaries) who were not
covered by a collective bargaining agreement were eligible to participate in the program. Based on the response to the
program by interested employees and the approvals by Company management, the program resulted in the termination of 55,
or approximately 6 percent, of the eligible 919 non-union employees, and the total severance costs under the program were
$7.3 million (pre-tax). The total severance costs are made up of the severance payments and the related payroll taxes and
employee benefit costs. Approximately 50 percent of the applicants to the program were approved for termination by
Company management. The long-term operating and maintenance cost savings under the program are expected to exceed the
severance costs of the program and the expected payback period for the severance costs will be approximately 1.4 years.
Each participant in the program was entitled to receive severance pay in an amount calculated by reference to the
participant's years of service and base pay as of December 31, 2012. In no event did the amount of severance pay exceed 78
weeks of a participant's base pay.
All terminations under the voluntary severance incentive program were completed by December 31, 2012. The cost of the
program was recognized as expense during the fourth quarter of 2012 and severance pay was distributed in a single lump sum
cashpayment to each participant during January 2013.
NOTE 4. ECOVA ACQUISITIONS
The acquisition of Cadence Network in July 2008 was funded by issuing additional Ecova common stock. Under the transaction
agreement, the previous owners of Cadence Network had a right to have their shares of Ecova common stock redeemed by Ecova
during July 2011 or July 2012 if their investment in Ecova was not liquidated through either an initial public offering or sale of the
business to a third party. These redemption rights were not exercised and expired effective July 31, 2012. As such, this redeemable
IFERC FORM NO. I (ED. 12-88) Pane 123.5 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
noncontrolling interest was reclassified to equity effective July 31, 2012. Additionally, certain minority shareholders and option
holders of Ecova have the right to put their shares back to Ecova at their discretion during an annual put window. Stock options and
other outstanding redeemable stock are valued at their maximum redemption amount which is equal to their intrinsic value (fair value
less exercise price).
In January 2011, Ecova acquired substantially all of the assets and liabilities of Building Knowledge Networks, LLC (BKN), a
Seattle-based real-time building energy management services provider.
On November 30, 2011, Ecova acquired all of the capital stock of Prenova, Inc. (Prenova), an Atlanta-based energy management
company.
On January 31, 2012, Ecova acquired all of the capital stock of LPB Energy Management (LPB), a Dallas, Texas-based energy
management company.
NOTE 5. DERIVATIVES AND RISK MANAGEMENT
Energy Commodity Derivatives
Avista Corp. is exposed to market risks relating to changes in electricity and natural gas commodity prices and certain other fuel prices.
Market risk is, in general, the risk of fluctuation in the market price of the commodity being traded and is influenced primarily by
supply and demand. Market risk includes the fluctuation in the market price of associated derivative commodity instruments. Avista
Corp. utilizes derivative instruments, such as forwards, futures, swaps and options in order to manage the various risks relating to these
commodity price exposures. The Company has an energy resources risk policy and control procedures to manage these risks. The
Company's Risk Management Committee establishes the Company's energy resources risk policy and monitors compliance. The Risk
Management Committee is comprised of certain Company officers and other members of management. The Audit Committee of the
Company's Board of Directors periodically reviews and discusses enterprise risk management processes, and it focuses on the
Company's material financial and accounting risk exposures and the steps management has undertaken to control them.
As part of the its resource procurement and management operations in the electric business, Avista Corp. 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. Avista Corp. transacts in wholesale markets by selling
and purchasing electric capacity and energy, fuel for electric generation, and derivative contracts related to capacity, energy and fuel.
Such transactions are part of the process of matching resources with our load obligations and hedging the related financial risks. These
transactions range from terms of intra-hour up to multiple years.
Avista Corp. makes continuing projections of
electric loads at various points in time (ranging from intra-hour to multiple years) based on, among other things,
estimates of customer usage and weather, historical data and contract terms, and
resource availability at these points in time based on, among other things, fuel choices and fuel markets, estimates of
streamfiows, availability of generating units, historic and forward market information, contract terms, and
experience.
On the basis of these projections, we make purchases and sales of electric capacity and energy, fuel for electric generation, and related
derivative instruments to match expected resources to expected electric load requirements and reduce our exposure to electricity (or
fuel) market price changes. Resource optimization involves generating plant dispatch and scheduling available resources and also
includes transactions such as:
purchasing fuel for generation,
when economical, selling fuel and substituting wholesale electric purchases, and
other wholesale transactions to capture the value of generation and transmission resources and fuel delivery capacity
contracts.
Avista Corp.'s optimization process includes entering into hedging transactions to manage risks. Transactions include both physical
energy contracts and related derivative instruments.
IFERC FORM NO. I (ED. 12-88) Page 123.6 --
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)ç An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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 significant
portion of its projected natural gas requirements through forward market transactions and derivative instruments. These transactions
may extend as much as four natural gas operating years (November through October) into the future. Avista Corp. also leaves a
significant portion of its natural gas supply requirements unhedged for purchase in short-term and spot markets.
Natural gas resource optimization activities include:
wholesale market sales of surplus natural gas supplies,
optimization of interstate pipeline transportation capacity not needed to serve daily load, and
purchases and sales of natural gas to optimize use of storage capacity.
The following table presents the underlying energy commodity derivative volumes as of December 31, 2012 that are expected to settle
in each respective year (in thousands of MWhs and mmBTUs):
Purchases Sales
Electric Derivatives Gas Derivatives Electric Derivatives Gas Derivatives
Physical (1) Financial (1) Physical Financial Physical Financial Physical Financial
Year MWH MATH mmBTUs mmBTUs MWH MWH mmBTUs mmBTUs
2013 713 3,365 18,523 88,391 264 2,712 7,252 91,962
2014 397 801 6,394 55,407 377 1,844 1,786 33,623
2015 379 614 3,390 42,930 286 982 - 35,575
2016 367 - 1,365 455 287 - - -
2017 366 - - - 286 - - -
Thereafter 583 - - - 443 - - -
(1) Physical transactions represent commodity transactions where Avista williake delivery of either electricity or natural gas and
financial transactions represent derivative instruments with no physical delivery, such as futures, swaps, options, or forward
contracts.
The above electric and natural gas derivative contracts will be included in either power supply costs or natural gas supply costs during
the period they settle and will be included in the various recovery mechanisms (ERM, PCA, and PGAs), or in the general rate case
process, and are expected to eventually be collected through retail rates from customers.
Foreign Currency Exchange Contracts
A significant portion of Avista Corp.'s natural gas supply (including fuel for power generation) is obtained from Canadian sources.
Most of those transactions are executed in U.S. dollars, which avoids foreign currency risk. A portion of Avista Corp.'s short-term
natural gas transactions and long-term Canadian transportation contracts are committed based on Canadian currency prices and settled
within sixty days with U.S. dollars. Avista Corp. economically hedges a portion of the foreign currency risk by purchasing Canadian
currency contracts when such commodity transactions are initiated. This risk has not had a material effect on the Company's financial
condition, results of operations or cash flows and these differences in cost related to currency fluctuations were included with natural
gas supply costs for ratemaking. The following table summarizes the foreign currency hedges that the Company has entered into as of
December 31 (dollars in thousands):
Number of contracts
Notional amount (in United States dollars)
Notional amount (in Canadian dollars)
Interest Rate Swap Agreements
2012 2011
20 28
$ 12,621 $ 7,033

12,502 7,192
IFERC FORM NO. I (ED. 12-88) Page 123.7 I
Number of contracts
Notional amount
Mandatory cash settlement date
Number of contracts
Notional amount
Mandatory cash settlement date
Number of contracts
Notional amount
Mandatory cash settlement date
Number of contracts
Notional amount
Mandatory cash settlement date
2012 2011

- 3
$ - $ 75,000
- July 2012

2 2
$ 85,000 $ 85,000

June 2013 June 2013

2 -
$ 50,000 $ -

October 2014 -
$ 25,000 $ -

October 2015 -
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Avista Corp. hedges a portion of its interest rate risk with financial derivative instruments, which may include interest rate swaps and
U.S. Treasury lock agreements. These interest rate swap agreements are considered economic hedges against fluctuations in future cash
flows associated with anticipated debt issuances.
The following table summarizes the interest rate swaps that the Company has entered into as of December 31 (dollars in thousands):
In May 2012, the Company cash settled interest rate swap contracts (notional amount of $75.0 million) and paid a total of $18.5
million. The interest rate swap contracts were settled in connection with the pricing of $80.0 million of First Mortgage Bonds. In
September 2011, the Company cash settled interest rate swap contracts (notional amount of $85.0 million) and paid a total of $10.6
million. The interest rate swap contracts were settled in connection with the pricing of $85.0 million of First Mortgage Bonds.
Upon settlement of the interest rate swaps, the regulatory asset or liability (included as part of long-term debt) is amortized as a
component of interest expense over the life of the forecasted interest payments.
Derivative Instruments Summary
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2012 (in thousands):
Fair Value
Collateral Net Asset
Derivative Balance Sheet Location Asset Liability Netting (Liability)
Foreign currency contracts Derivative instrument liabilities
—Hedges $ 7 $ (34) $ - $ (27)
Interest rate contracts Derivative instrument liabilities
-Hedges - (1,406) - (1,406)
Interest rate contracts Long-term portion of derivative
instrument assets -Hedges 7,265 - - 7,265
Commodity contracts Derivative instrument assets
current 10,772 (6,633) - 4,139
Commodity contracts Long-term portion of derivative
assets 18,779 (17,686) - 1,093
Commodity contracts Derivative instrument liabilities
current 50,227 (89,449) 9,707 (29,515)
Commodity contracts Long-term portion of derivative
liabilities 2,247 (28,558) - (26,311)
Total derivative instruments recorded on the balance sheet $ 89,297 $ (143,766) $ 9,707 $ (44,762)
The following table presents the fair values and locations of derivative instruments recorded on the Balance Sheet as of December 31,
2011 (in thousands):
IFERC FORM NO. I (ED. 12-88) Page 123.8 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Fair Value
Net Asset
Derivative Balance Sheet Location Asset Liability (Liability)
Foreign currency contracts Derivative instrument assets —Hedges $ 32 $ - $ 32
Interest rate contracts Derivative instrument liabilities —Hedges - (16,253) (16,253)
Interest rate contracts Long-term portion of derivative
instrument liabilities - Hedges - (2,642) (2,642)
Commodity contracts Derivative instrument assets
current 1,618 (479) 1,139
Commodity contracts Long-term portion of
derivative assets 185 - 185
Commodity contracts Derivative instrument liabilities
current 40,090 (110,914) (70,824)
Commodity contracts Long-term portion of
derivative instrument liabilities 44,308 (84,838) (40,530)
Total derivative instruments recorded on the balance sheet $ 86,233 $ (215,126) $ (128,893)
Exposure to Demands for Collateral
The Company's derivative contracts often require collateral (in the form of cash or letters of credit) or other credit enhancements, or
reductions or terminations of a portion of the contract through cash settlement, in the event of a downgrade in the Company's credit
ratings or changes in market prices. In periods of price volatility, the level of exposure can change significantly. As a result, sudden
and significant demands may be made against the Company's credit facilities and cash. The Company actively monitors the exposure to
possible collateral calls and takes steps to mitigate capital requirements. As of December 31, 2012, the Company had cash deposited as
collateral of $10.1 million and letters of credit of $28.1 million outstanding related to its energy derivative contracts. The Balance
Sheet at December 31, 2012 reflects the offsetting of $9.7 million of cash collateral against net derivative positions where a legal right
of offset exists.
Certain of the Company's derivative instruments contain provisions that require the Company to maintain an investment grade credit
rating from the major credit rating agencies. If the Company's credit ratings were to fall below "investment grade," it would be in
violation of these provisions, and the counterparties to the derivative instruments could request immediate payment or demand
immediate and ongoing collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative
instruments with credit-risk-related contingent features that are in a liability position as of December 31, 2012 was $35.9 million. If the
credit-risk-related contingent features underlying these agreements were triggered on December 31, 2012, the Company could be
required to post $25.8 million of additional collateral to its counterparties.
Credit Risk
Credit risk relates to the potential losses that the Company would incur as a result of non-performance by counterparties of their
contractual obligations to deliver energy or make financial settlements. The Company often extends credit to counterparties and
customers and is exposed to the risk that it may not be able to collect amounts owed to the Company. Credit risk includes potential
counterparty default due to circumstances:
relating directly to it,
caused by market price changes, and
relating to other market participants that have a direct or indirect relationship with such counterparty.
Changes in market prices may dramatically alter the size of credit risk with counterparties, even when conservative credit limits are
established. Should a counterparty fail to perform, the Company may be required to honor the underlying commitment or to replace
existing contracts with contracts at then-current market prices.
We enter into bilateral transactions between Avista and various counterparties. We also trade energy and related derivative instruments
through clearinghouse exchanges.
The Company seeks to mitigate bilateral credit risk by:
entering into bilateral contracts that specify credit terms and protections against default,
IFERC FORM NO. 1 (ED. 12-88) Page 123.9 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/1212013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
applying credit limits and duration criteria to existing and prospective counterparties,
• actively monitoring current credit exposures,
• asserting our collateral rights with counterparties,
• carrying out transaction settlements timely and effectively, and
• conducting transactions on exchanges with fully collateralized clearing arrangements that significantly reduce
counterparty default risk.
The Company's credit policy includes an evaluation of the financial condition of counterparties. Credit risk management includes
collateral requirements or other credit enhancements, such as letters of credit or parent company guarantees. The Company enters into
various agreements that address credit risks including standardized agreements that allow for the netting or offsetting of positive and
negative exposures.
The Company has concentrations of suppliers and customers in the electric and natural gas industries including:
• electric and natural gas utilities,
electric generators and transmission providers,
• natural gas producers and pipelines,
• financial institutions including commodity clearing exchanges and related parties, and
energy marketing and trading companies.
In addition, the Company has concentrations of credit risk related to geographic location as it operates in the western United States and
western Canada. These concentrations of counterparties and concentrations of geographic location may impact the Company's overall
exposure to credit risk because the counterparties may be similarly affected by changes in conditions.
The Company maintains credit support agreements with certain counterparties and margin calls are periodically made and/or received.
Margin calls are triggered when exposures exceed contractual limits or when there are changes in a counterparty's creditworthiness.
Price movements in electricity and natural gas can generate exposure levels in excess of these contractual limits. Negotiating for
collateral in the form of cash, letters of credit, or performance guarantees is common industry practice.
NOTE 6. JOINTLY OWNED ELECTRIC FACILITIES
The Company has a 15 percent ownership interest in a twin-unit coal-fired generating facility, the Coistrip Generating Project
(Colstrip) located in southeastern Montana, and provides financing for its ownership interest in the project. The Company's share of
related fuel costs as well as operating expenses for plant in service are included in the corresponding accounts in the Statements of
Income. The Company's share of utility plant in service for Colstrip and accumulated depreciation were as follows as of December 31
(dollars in thousands):
Utility plant in service
Accumulated depreciation
NOTE 7. ASSET RETIREMENT OBLIGATIONS
2012 2011
$ 344,958 $ 342,539
(234,126) (225,746)
The Company records the fair value of a liability for an asset retirement obligation in the period in which it is incurred. When the
liability is initially recorded, the associated costs of the asset retirement obligation are capitalized as part of the carrying amount of the
related long-lived asset. The liability is accreted to its present value each period and the related capitalized costs are depreciated over
the useful life of the related asset. Upon retirement of the asset, the Company either settles the retirement obligation for its recorded
amount or incurs a gain or loss. The Company records regulatory assets and liabilities for the difference between asset retirement costs
currently recovered in rates and asset retirement obligations recorded since asset retirement costs are recovered through rates charged
to customers. The regulatory assets do not earn a return.
IFERC FORM NO. 1 (ED. 12-88) Page 123.10
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/1212013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Specifically, the Company has recorded liabilities for future asset retirement obligations to:
• restore ponds at Coistrip,
• cap a landfill at the Kettle Falls Plant,
• remove plant and restore the land at the Coyote Springs 2 site at the termination of the land lease,
. remove asbestos at the corporate office building, and
dispose of PCBs in certain transformers.
Due to an inability to estimate a range of settlement dates, the Company cannot estimate a liability for the:
removal and disposal of certain transmission and distribution assets, and
abandonment and decommissioning of certain hydroelectric generation and natural gas storage facilities.
The following table documents the changes in the Company's asset retirement obligation during the years ended December 31 (dollars
in thousands):
2012 2011
Asset retirement obligation at beginning of year $ 3,513 $ 3,887
New liability recognized - -
Liability settled (559) (612)
Accretion expense 214 238
Asset retirement obligation at end of year $ 3,168 $ 31513
NOTE 8. PENSION PLANS AND OTHER POSTRETIREMENT BENEFIT PLANS
The Company has a defined benefit pension plan covering substantially all regular full-time employees at Avista Corp. Individual
benefits under this plan are based upon the employee's years of service, date of hire and average compensation as specified in the plan.
The Company's 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 $44 million in cash to the pension plan in 2012 and $26 million in 2011. The Company expects to contribute $44
million in cash to the pension plan in 2013.
The Company also has a Supplemental Executive Retirement Plan (SERP) that provides additional pension benefits to executive
officers of the Company. The SERP is intended to provide benefits to executive Officers whose benefits under the pension plan are
reduced due to the application 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):
2013 2014 2015 2016 2017 Total 2018-2022
Expected benefit payments $ 24,504 $ 24,280 $ 25,434 $ 26,567 $ 27,797 $ 162,488
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 substantially all of its retired employees. The Company
accrues the estimated cost of postretirernent benefit obligations during the years that employees provide services. The Company
elected to amortize the transition obligation of $34.5 million over a period of 20 years, beginning in 1993.
The Company has a Health Reimbursement Arrangement to provide employees with tax-advantaged funds to pay for allowable
medical expenses upon retirement. The amount earned by the employee is fixed on the retirement date based on the employee's years
of service and the ending salary. The liability and expense of this plan are included as other postretirement benefits.
IFERC FORM NO. I (ED. 12-881 Paae 123.11 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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):
2013 2014 2015 2016 2017 Total 2018-2022
Expected benefit payments $ 6,099 $ 6,160 $ 6,261 $ 6,389 $ 6,571 $ 36,342
The Company expects to contribute $6.1 million to other postretirement benefit plans in 2013, representing expected benefit payments
to be paid during the year. The Company uses a December 31 measurement date for its pension and other postretirement benefit plans.
IFERC FORM NO. 1 (ED. 12-88) Page 123.12 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table sets forth the pension and other postretirement benefit plan disclosures as of December 31, 2012 and 2011 and the
components of net periodic benefit costs for the years ended December 31, 2012 and 2011 (dollars in thousands):
Other Post-
Pension Benefits retirement Benefits
2012 2011 2012 2011
$ 494,192 $ 433,491 $ 104,730 $ 60,339

15,551 12,936 2,804 1,805
24,349 24,134 5,056 4,126
72,170 44,148 24,543 42,476

- - 336 450
(21,643) (20,517) (4,928) (4,466)
$ 584,619 $ 494,192 $ 132,541 $ 104,730
$ 328,150 $ 306,712 $ 22,455 $ 22,875
54,318 14,705 2,833 (420)
44,000 26,000 - -
(20,407) (19,267) - -
$ 406,061 $ 328,150 $ 25,288 $ 22,455
Funded status $ (178,558) $ (166,042) $ (107,253) $ (82,275)
Unrecognized net actuarial loss 223,308 192,883 94,202 76,187
Unrecognized prior service cost 319 665 (856) (1,005)
Unrecognized net transition obligation - - - 505
Prepaid (accrued) benefit cost 45,069 27,506 (13,907) (6,588)
Additional liability (223,627) (193,548) (93,346) (75,687)
Accrued benefit liability $ (178,558) $ (166,042) $ (107,253) $ (82,275)
Accumulated pension benefit obligation $ 505,695 $ 429,135 - -
Accumulated postretirement benefit obligation:
For retirees
For fully eligible employees
For other participants
Included in accumulated comprehensive loss (income) (net of
tax):
Unrecognized net transition obligation
Unrecognized prior service cost
Unrecognized net actuarial loss
Total
Less regulatory asset
Accumulated other comprehensive loss (income)
Other Post-
Pension Benefits retirement Benefits
2012 2011 2012 2011
Change in benefit obligation:
Benefit obligation as of beginning of year
Service cost
Interest cost
Actuarial loss
Transfer of accrued vacation
Benefits paid
Benefit obligation as of end of year
Change in plan assets:
Fair value of plan assets as of beginning of year
Actual return on plan assets
Employer contributions
Benefits paid
Fair value of plan assets as of end of year
49,232 $ 39,470
35,570 $ 29,597
47,739 $ 35,663
$ - $ - $ - $ 328

207 433 (556) (653)

145,150 125,374 61,231 495 ,22

145,357 125,807 60,675 49,197

(138,184) (119,360) (60,981) (49,873)
$ 7,173 $ 6,447 $ (306) $ (676)
Weighted average assumptions as of December 31:
Discount rate for benefit obligation
Discount rate for annual expense
Expected long-term return on plan assets
Rate of compensation increase
Medical cost trend pre-age 65 - initial
Medical cost trend pre-age 65 - ultimate
Ultimate medical cost trend year pre-age 65
Medical cost trend post-age 65 - initial
Medical cost trend post-age 65 - ultimate
4.15% 5.04% 4.15% 4.98%
5.04% 5.68% 4.98% 5.53%
6.95% 7.40% 6.55% 7.00%
4.89% 4.87%
7.00% 7.50%
5.00% 5.00%
2019 2017
7.50% 8.00%
5.00% 6.00%
IFERC FORM NO. I (ED. 12-88) Page 123.13 I
Name of Respondent
'
Report is: Date of Report Year/Period of Report
An Original (Mo, Da, Yr)
Avista Corporation A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Ultimate medical cost trend year post-age 65 2021 2018
Pension Benefits Other Postretirement Benefits
2012 2011 2012 2011
Components of net periodic benefit
cost:
Service cost
Interest cost
Expected return on plan assets
Transition obligation recognition
Amortization of prior service cost
Net loss recognition
Net periodic benefit cost
Plan Assets
$ 15,551 $ 12,936
24,349 24,134
(23,810) (23,115)
346 475
11,637 9,493
$ 28,073 $ 23,923
$ 2,804 $ 1,805
5,056 4,126
(1,471) (1,601)
505 505
(149) (149)
5,020 3,458
$ 11,765 $ 8,144
The Finance Committee of the Company's Board of Directors approves investment policies, objectives and strategies that seek an
appropriate return for the pension plan and other postretirement benefit plans and reviews and approves changes to the investment and
funding policies.
The Company has contracted with investment consultants who are responsible for managing/monitoring the individual investment
managers. The investment managers' performance and related individual fund performance is periodically reviewed by an internal
benefits committee and by the Finance Committee to monitor compliance with investment policy objectives and strategies.
IFERC FORM NO. I (ED. 12-88) Page 123.14 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/12/2013 201 2/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Pension plan assets are invested primarily in marketable debt and equity securities. Pension plan assets may also be invested in real
estate, absolute return, venture capital/private equity and commodity funds. In seeking to obtain the desired return to fund the pension
plan, the investment consultant recommends allocation percentages by asset classes. These recommendations are reviewed by the
internal benefits committee, which then recommends their adoption by the Finance Committee. The Finance Committee has established
target investment allocation percentages by asset classes as indicated in the table below:
2012 2011
Equity securities 51% 51%
Debt securities 31% 31%
Real estate 5% 5%
Absolute return 10% 10%
Other 3% 3%
The market-related value of pension plan assets invested in debt and equity securities was based primarily on fair value (market
prices). The fair value of investment securities traded on a national securities exchange is determined based on the last reported sales
price; securities traded in the over-the-counter market are valued at the last reported bid price. Investment securities for which market
prices are not readily available or for which market prices do not represent the value at the time of pricing, are fair-valued by the
investment manager based upon other inputs (including valuations of securities that are comparable in coupon, rating, maturity and
industry). Investments in common/collective trust funds are presented at estimated fair value, which is determined based on the unit
value of the fund. Unit value is determined by an independent trustee, which sponsors the fund, by dividing the fund's net assets by its
units outstanding at the valuation date. The fair value of the closely held investments and partnership interests is based upon the
allocated share of the fair value of the underlying assets as well as the allocated share of the undistributed profits and losses, including
realized and unrealized gains and losses.
The market-related value of pension plan assets invested in real estate was determined by the investment manager based on three basic
approaches:
• properties are externally appraised on an annual basis by independent appraisers, additional appraisals may be
performed as warranted by specific asset or market conditions,
• property valuations are reviewed quarterly and adjusted as necessary, and
• loans are reflected at fair value.
The market-related value of pension plan assets was determined as of December 31, 2012 and 2011.
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of the
pension plan's assets measured and reported as of December 31, 2012 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Mutual funds:
Fixed income securities $ 83,037 $ - $ - $ 83,037
U.S. equity securities 135,436 - - 135,436
International equity securities 79,448 - - 79,448
Absolute return (1) 20,764 - - 20,764
Commodities (2) 8,258 - - 8,258
Common/collective trusts:
Fixed income securities - 43,107 - 43,107
Real estate - - 17,596 17,596
Partnership/closely held investments:
Absolute return (1) - - 17,755 17,755
Private equity funds (3) - - 660 660
Total $ 326,943 $ 43,107 $ 36,011 $ 406,061
IFERC FORM NO. 1 (ED. 12-88) Page 123.15 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/1212013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of the
pension plan's assets measured and reported as of December 31, 2011 at fair value (dollars in thousands):
Level 1 Level 2 Level 3 Total
Cash equivalents $ - $ 7,550 $ - $ 7,550
Mutual funds:
Fixed income securities 76,486 - 76,486
U.S. equity securities 102,790 - - 102,790
International equity securities 52,241 - - 52,241
Absolute return (1) 16,121 - - 16,121
Commodities (2) 6,526 - - 6,526
Common/collective trusts:
Fixed income securities - 27,774 - 27,774
U.S. equity securities - 12,669 - 12,669
Real estate - - 8,598 8,598
Partnership/closely held investments:
Absolute return (1) - - 16,587 16,587
Private equity funds (3) - - 808 808
Total $ 254,164 $ 47,993 $ 25,993 $ 3281 150
(1)This category invests in multiple strategies to diversify risk and reduce volatility. The strategies include: (a) event driven,
relative value, convertible, and fixed income arbitrage, (b) distressed investments, (c) long/short equity and fixed income, and
(d) market neutral strategies.
(2)The fund primarily invests in derivatives linked to commodity indices to gain exposure to the commodity markets. The fund
manager fully collateralizes these positions with debt securities.
(3)This category includes private equity funds that invest primarily in U.S. companies.
The table below discloses the summary of changes in the fair value of the pension plan's Level 3 assets for the year ended
December 31, 2012 (dollars in thousands):
Common/collective trusts Partnership/closely held investments
Balance, as of January 1, 2012
Realized gains
Unrealized gains (losses)
Purchases (sales), net
Balance, as of December 31, 2012
Real Absolute Private equity
estate return funds
$ 8,598 $ 16,587 $ 808
411 - 108
1,087 1,168 80
7,500 - (336)
$ 17,596 $ 17,755
1 $ 660
The table below discloses the summary of changes in the fair value of the pension plan's Level 3 assets for the year ended
December 31, 2011 (dollars in thousands):
Common/collective trusts Partnership/closely held investments
Balance, as of January 1, 2011
Realized gains (losses)
Unrealized gains (losses)
Purchases (sales), net
Balance, as of December 31, 2011
Absolute Real Absolute Private equity
return estate return funds
$ 95 $ 423 $ 16,917 $ 1,272
(748) 22 - 373
746 1,098 (330) (218)
(93) 71055 - (619)
$ - $ 8,598 $ 16,587 $ 808
The market-related value of other postretirement plan assets invested in debt and equity securities was based primarily on fair value
(market prices). The fair value of investment securities 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
FERC FORM NO. I (ED. 12-88) Page 123.16 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
which market prices are not readily available or for which market prices do not represent the value at the time of pricing, are
fair-valued by the investment manager based upon other inputs (including valuations of securities that are comparable in coupon,
rating, maturity and industry). The target asset allocation was 62 percent equity securities and 38 percent debt securities in 2012 and
2011.
The market-related value of other postretirement plan assets was determined as of December 31, 2012 and 2011.
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of other
postretirement plan assets measured and reported as of December 31, 2012 at fair value (dollars in thousands):
Cash equivalents
Mutual funds:
Fixed income securities
U.S. equity securities
International equity securities
Total
Level 1 Level 2 Level 3 Total
$ 6$ —$ 6

9,314 - — 9,314

10,266 — - 10,266

5,702 - - 51702
$ 25,282 $ 6 $ — $ 25,288
The following table discloses by level within the fair value hierarchy (see Note 15 for a description of the fair value hierarchy) of other
postretirement plan assets measured and reported as of December 31, 2011 at fair value (dollars in thousands):
Cash equivalents
Mutual funds:
Fixed income securities
U.S. equity securities
International equity securities
U.S. equity securities
Other
Total
Level 1 Level 2 Level 3 Total
$ - $ 86 $ — $ 86

8,683 - - 8,683

7,278 — — 7,278

4,766 — — 4,766

1,569 - — 1,569
73 - — 73
$ 22,369 $ 86 $ - $ 22,455
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, 2012 by $20.8 million and the service and interest cost by $1.4 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, 2012 by
$16.7 million and the service and interest cost by $1.1 million.
The Company has a salary deferral 401(k) plans that is a defined contribution plan and cover substantially all employees. Employees
can make contributions to their respective accounts in the plan on a pre-tax basis up to the maximum amount permitted by law. The
Company matches a portion of the salary deferred by each participant according to the schedule in the plan.
Employer matching contributions were as follows for the years ended December 31 (dollars in thousands):
2012 2011
Employer 401(k) matching contributions 5,813 $ 5,452
The Company has an Executive Deferral Plan. This plan allows executive officers and other key employees the opportunity to defer
until the earlier of their retirement, termination, disability or death, up to 75 percent of their base salary and/or up to 100 percent of
their incentive payments. Deferred compensation funds are held by the Company in a Rabbi Trust. There were deferred compensation
assets and corresponding deferred compensation liabilities on the Balance Sheets of the following amounts as of December 31 (dollars
in thousands):
2012 2011
Deferred compensation assets and liabilities $ 8,806 $ 8,653
NOTE 9. ACCOUNTING FOR INCOME TAXES
IFERC FORM NO. 1 (ED. 12-88) Page 123.17
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Deferred income taxes reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for
financial reporting purposes and the amounts used for income tax purposes and tax credit carryforwards. As of December 31, 2012, the
Company had $13.9 million of state tax credit carryforwards. State tax credits expire from 2015 to 2025. The Company recognizes the
effect of state tax credits generated from utility plant as they are utilized.
The realization of deferred income tax assets is dependent upon the ability to generate taxable income in future periods. The Company
evaluated available evidence supporting the realization of its deferred income tax assets and determined it is more likely than not that
deferred income tax assets will be realized.
The Company and its eligible subsidiaries file consolidated federal income tax returns. The Company also files state income tax returns
in certain jurisdictions, including Idaho, Oregon and Montana. Subsidiaries are charged or credited with the tax effects of their
operations on a stand-alone basis. The Internal Revenue Service (IRS) has completed its examination of all tax years through 2009 and
all issues were resolved related to these years. The IRS has not completed an examination of the Company's 2010 through 2011 federal
income tax returns. The Company does not believe that any open tax years for federal or state income taxes could result in any
adjustments that would be significant to the financial statements.
The Company did not incur any penalties on income tax positions in 2012 or 2011.
The Company had net regulatory assets related to the probable recovery of certain deferred income tax liabilities from customers
through future rates as of December 31 (dollars in thousands):
2012 2011
Regulatory assets for deferred income taxes $ 79,406 $ 84,576
NOTE 10. ENERGY PURCHASE CONTRACTS
Avista Corp. has contracts for the purchase of fuel for thermal generation, natural gas for resale and various agreements for the
purchase or exchange of electric energy with other entities. The termination dates of the contracts range from one month to the year
2055. Total expenses for power purchased, natural gas purchased, fuel for generation and other fuel costs were as follows for the years
ended December 31 (dollars in thousands):
2012 2011
Utility power resources $ 523,416 $ 557,619
The following table details Avista Corp.'s future contractual commitments for power resources (including transmission contracts) and
natural gas resources (including transportation contracts) (dollars in thousands):
2013 2014 2015 2016 2017 Thereafter Total
Power resources $ 196,877 $ 132,378 $ 118,054 $ 117,779 $ 116,580 $ 1,025,941 $ 1,707,609
Natural gas resources 109,406 961092 77,688 60,104 51,950 678,042 1,073,282
Total $ 306,283 $ 228,470 $ 195,742 $ 177,883 $ 168,530 $ 1,703,983 $ 2,780,891
These energy purchase contracts were entered into as part of Avista Corp.'s obligation to serve its retail electric and natural gas
customers' energy requirements. 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.
In addition, Avista Corp. has operational agreements, settlements and other contractual obligations for its generation, transmission and
distribution facilities. The following table details future contractual commitments for these agreements (dollars in thousands):
2013 2014 2015 2016 2017 Thereafter Total
Contractual obligations $ 30,913 $ 31,732 $ 29,259 $ 35,844 $ 27,708 $ 230,453 $ 385,909
Avista Corp. has fixed contracts with certain Public Utility Districts (PUD) to purchase portions of the output of certain generating
facilities. Although Avista Corp. has no investment in the PUD generating facilities, the fixed contracts obligate Avista Corp. to pay
certain minimum amounts (based in part on the debt service requirements of the PUD) whether or not the facilities are operating.
IFERC FORM NO I (ED 12-88) Page 12318 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04112/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Expenses under these PUD contracts were as follows for the years ended December 31 (dollars in thousands):

2012 2011
PJJD contract costs $ 8,436 $ 10,533
Information as of December 31, 2012 pertaining to these PUD contracts is summarized in the following table (dollars in thousands):
Company's Current Share of
Debt
Kilowatt Annual Service Bonds Expiration
Output Costs (1)
Douglas County PUD:
Wells Project 3.4% 24,048 2,716 874 3,117 2018
Grant County PUD:
Priest Rapids and
Wanapum Projects 3.3% 65,800 51717 2,425 30,655 2055
Totals 89,848 $ 8,433 $ 3,299 $ 33,772
(1) The annual costs will change in proportion to the percentage of output allocated to Avista Corp. in a particular year. Amounts
represent the operating costs for 2012. Debt service costs are included in annual costs.
The estimated aggregate amounts of required minimum payments (Avista Corp.'s share of existing debt service costs) under these PUD
contracts are as follows (dollars in thousands):
2013 2014 2015 2016 2017 Thereafter Total
Minimum payments $ 3,348 $ 3,332 $ 3,223 $ 3,222 $ 3,220 $ 42,988 $ 59,333
In addition, Avista Corp. will be required to pay its proportionate share of the variable operating expenses of these projects.
NOTE 11. NOTES PAYABLE
Avista Corp. has a committed line of credit with various financial institutions in the total amount of $400.0 million with an expiration
date of February 2017.
The committed line of credit is secured by non-transferable First Mortgage Bonds of the Company issued to the agent bank that would
only become due and payable in the event, and then only to the extent, that the Company defaults on its obligations under the
committed line of credit.
The committed line of credit agreement contains customary covenants and default provisions. The credit agreement has a covenant
which does not permit the ratio of "consolidated total debt" to "consolidated total capitalization" of Avista Corp. to be greater than 65
percent at any time. As of December 31, 2012, 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):

2012 2011
alance outstanding at end of period $ 52,000 $ 61,000
Letters of credit outstanding at end of period $ 35,885 $ 29,030
Average interest rate at end of period 1.12% 1.12%
NOTE 12. BONDS
The following details bonds outstanding as of December 31 (dollars in thousands):
Maturity Interest
Year Description Rate 2012 2011
2012 Secured Medium-Term Notes 7.37% $ - $ 7,000
2013 First Mortgage Bonds 1.68% 50,000 50,000
IFERC FORM NO. 1 (ED. 12-88) Page 123.19
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)2An Original (Mo, Da, Yr)
Avista Corporation (2) - A Resubmission 04/1212013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
2018 First Mortgage Bonds 5.95% 250,000 250,000
2018 Secured Medium-Term Notes 7.39%-7.45% 22,500 22,500
2019 First Mortgage Bonds 5.45% 90,000 90,000
2020 First Mortgage Bonds 3.89% 52,000 52,000
2022 First Mortgage Bonds 5.13% 250,000 250,000
2023 Secured Medium-Term Notes 7.18%-7.54% 13,500 13,500
2028 Secured Medium-Term Notes 6.37% 25,000 25,000
2032 Secured Pollution Control Bonds (1) (1) 66,700 66,700
2034 Secured Pollution Control Bonds (2) (2) 17,000 17,000
2035 First Mortgage Bonds 6.25% 150,000 150,000
2037 First Mortgage Bonds 5.70% 150,000 150,000
2040 First Mortgage Bonds 5.55% 35,000 35,000
2041 First Mortgage Bonds 4.45% 85,000 85,000
2047 First Mortgage Bonds (3) 4.23% 80,000 -
Total secured bonds 1,336,700 1,263,700
2023 Unsecured Pollution Control Bonds 6.00% - 4,100
Settled interest rate swaps (27,900) (10,629)
Secured Pollution Control Bonds held by Avista
Corporation (1) (2) (83,700) (83,700)
Total bonds $ 1,225,100 $ 1,173,471
(1)In December 2010, $66.7 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds (Avista
Corporation Colstrip Project) due 2032, which had been held by Avista Corp. since 2008, were refunded by a new bond issue
(Series 201 OA). 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 Sheet.
(2)In December 2010, $17.0 million of the City of Forsyth, Montana Pollution Control Revenue Refunding Bonds, (Avista
Corporation Colstrip Project) due 2034, which had been held by Avista Corp. since 2009, were refunded by a new bond issue
(Series 20 lOB). The new bonds were not offered to the public and were purchased by Avista Corp. due to market conditions.
The Company expects that at a later date, subject to market conditions, the bonds may be remarketed to unaffiliated investors.
So long as Avista Corp. is the holder of these bonds, the bonds will not be reflected as an asset or a liability on Avista Corp.'s
Balance Sheet.
(3)In November 2012, the Company issued $80.0 million of 4.23 percent First Mortgage Bonds due in 2047.
The following table details future long-term debt maturities including advances from associated companies (see Note 13) (dollars in
thousands):
2013 2014 2015 2016 2017 Thereafter Total
Debt maturities $ 50,000 $ - $ - $ - $ - $ 1,254,547 $ 1,304,547
Substantially all utility properties owned by the Company are subject to the lien of the Company's mortgage indenture. Under the
Mortgage and Deed of Trust securing the Company's First Mortgage Bonds (including Secured Medium-Term Notes), the Company
may issue additional First Mortgage Bonds in an aggregate principal amount equal to the sum of: 1) 66-2/3 percent of the cost or fair
value (whichever is lower) of property additions which have not previously been made the basis of any application under the
Mortgage, or 2) an equal principal amount of retired First Mortgage Bonds which have not previously been made the basis of any
application under the Mortgage, or 3) deposit of cash. However, the Company may not issue any additional First Mortgage Bonds
(with certain exceptions in the case of bonds issued on the basis of retired bonds) unless the Company's "net earnings" (as defined in
the Mortgage) for any period of 12 consecutive calendar months out of the preceding 18 calendar months were at least twice the annual
interest requirements on all mortgage securities at the time outstanding, including the First Mortgage Bonds to be issued, and on all
indebtedness of prior rank. As of December 31, 2012, property additions and retired bonds would have allowed, and the net earnings
test would not have prohibited the issuance of $640.1 million in aggregate principal amount of additional First Mortgage Bonds.
See Note 11 for information regarding First Mortgage Bonds issued to secure the Company's obligations under its committed line of
credit agreement.
IFERC FORM NO. I (ED. 12-88) Page 123.20
Low distribution rate
High distribution rate
Distribution rate at the end of the year
2012 2011
1.19% 1.13%
1.40 1.40
1.19 1.40
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr) 1 Avista Corporation (2)- A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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:
Concurrent with the issuance of the Preferred Trust Securities, Avista Capital II issued $1.5 million of Common Trust Securities to the
Company. These debt securities may be redeemed at the option of Avista Capital II on or after June 1, 2007 and mature on June 1,
2037. 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. LEASES
The Company has multiple lease arrangements involving various assets, with minimum terms ranging from 1 to forty-five years. Rental
expense under operating leases was as follows for the years ended December 31 (dollars in thousands):

2012 2011
Rental expense $ 3,274 $ 2,853
Future minimum lease payments required under operating leases having initial or remaining noncancelable lease terms in excess of one
year as of December 31 were as follows (dollars in thousands):
2013 2014 2015 2016 2017 Thereafter Total
Minimum payments required $ 1,749 $ 1,517 $ 498 $ 162 $ 148 $ 2,712 $ 6,786
NOTE 15. FAIR VALUE
The carrying values of cash and cash equivalents, special deposits, accounts and notes receivable, accounts payable and notes payable
are reasonable estimates of their fair values. Bonds and advances from associated companies are reported at carrying value on the
Balance Sheets.
The 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):
2012 2011
Carrying Estimated Carrying Estimated
Value Fair Value Value Fair Value
Bonds (Level 2) $ 951,000 $ 1,164,639 $ 962,100 $ 1,135,536
Bonds (Level 3) 302,000 320,892 222,000 234,226
Advances from associated companies (Level 3) 51,547 43,686 51,547 43,810
These estimates of fair value were primarily based on available market information.
The fair value hierarchy prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted.
prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3
measurement).
IFERC FORM NO. 1 (ED. 12-88) Page 123.21
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The three levels of the fair value hierarchy are defined as follows:
Level 1 - Quoted prices are available in active markets for identical assets or liabilities. Active markets are those in which
transactions for the asset or liability occur with sufficient frequency and volume to provide pricing information on an ongoing basis.
Level 2 - Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly
observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation
methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward
prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well
as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term
of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the
marketplace.
Level 3 - Pricing inputs include significant inputs that are generally unobservable from objective sources. These inputs maybe
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.
IFERC FORM NO. 1 (ED. 12-88) Page 123.22 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)XAn Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
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, 2012 and 2011 at fair value on a recurring basis (dollars in thousands):
Counterparty
and Cash
Collateral
Level I Level 2 Level 3 Netting (1) Total
December 31, 2012
Assets:
Energy commodity derivatives $ - $ 81,640 $ - $ (76,408) $ 5,232
Level 3 energy commodity derivatives:
Power exchange agreements - - 385 (385) -
Foreign currency derivatives - 7 - (7) -
Interest rate swaps - 7,265 - - 7,265
Deferred compensation assets:
Fixed income securities 2,010 - - - 2,010
Equity securities 5,955 - - 5,955
Total $ 7,965 $ 88,912 $ 385 $ (76,800) $ 20,462
Liabilities:
Energy commodity derivatives $ - $ 119,390 $ - $ (86,115) $ 33,275
Level 3 energy commodity derivatives:
Natural gas exchange agreements - - 2,379 - 2,379
Power exchange agreements - - 19,077 (385) 18,692
Power option agreements - - 1,480 - 1,480
Foreign currency derivatives - 34 - (7) 27
Interest rate swaps - 1,406 - - 1 1406
Total $ - $ 120,830 $ 22,936 $ (86,507) $ 57,259
IFERC FORM NO. I (ED. 12-88) Page 123.23 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/1212013 2012104
NOTES TO FINANCIAL STATEMENTS (Continued)
December 31, 2011
Assets:
Energy commodity derivatives
Level 3 energy commodity derivatives:
Natural gas exchange agreements
Power exchange agreements
Foreign currency derivatives
Deferred compensation assets:
Fixed income securities
Equity securities
Total
Liabilities:
Energy commodity derivatives
Level 3 energy commodity derivatives:
Natural gas exchange agreements
Power exchange agreements
Power option agreements
Interest rate swaps
Total
Counterparty
and Cash
Collateral
Level I Level 2 Level 3 Netting (1) Total
- $ 80,571 $ - $ (79,247) $ 1,324
- - 956 (956) -

— 4,674 (4,674) -
— 32 - - 32

2,116 - - - 2,116

5,252 - - - 5,252
$ 7,368 $ 80,603 $ 5,630 1 $ (84,877) $ 8,724
$ - $ 177,743 $ (79,247) $ 98,496
- - 2,644 (956) 1,688
- - 14,584 (4,674) 9,910
- - 1,260 - 1,260
- 18,895 - - 18,895
$ - $ 196,638 $ 18,488 $ (84,877) $ 130,249
(1) The Company is permitted to net derivative assets and derivative liabilities with the same counterparty when a legally enforceable
master netting agreement exists. In addition, the Company nets derivative assets and derivative liabilities against any payables and
receivables for cash collateral held or placed with these same counterparties.
Avista Corp. enters into forward contracts to purchase or sell a specified amount of energy at a specified time, or during a specified
period, in the future. These contracts are entered into as part of Avista Corp.'s management of loads and resources and certain
contracts are considered derivative instruments. The difference between the amount of derivative assets and liabilities disclosed in
respective levels and the amount of derivative assets and liabilities disclosed on the Balance Sheets is due to netting arrangements with
certain counterparties. The Company uses quoted market prices and forward price curves to estimate the fair value of utility derivative
commodity instruments included in Level 2. In particular, electric derivative valuations are performed using broker quotes, adjusted
for periods in between quotable periods. Natural gas derivative valuations are estimated using New York Mercantile Exchange
(NYMEX) pricing for similar instruments, adjusted for basin differences, using broker quotes. Where observable inputs are available
for substantially the full term of the contract, the derivative asset or liability is included in Level 2.
Deferred compensation assets and liabilities represent funds held by the Company in a Rabbi Trust for an executive deferral plan.
These funds consist of actively traded equity and bond funds with quoted prices in active markets. The balance disclosed in the table
above excludes cash and cash equivalents of $0.8 million as of December 31, 2012 and $1.3 million as of December 31, 2011.
Level 3 Fair Value
For power exchange agreements, the Company compares the Level 2 brokered quotes and forward price curves described above to an
internally developed forward price which is based on the average operating and maintenance (O&M) charges from four surrogate
nuclear power plants around the country for the current year. Because the nuclear power plant O&M charges are only known for one
year, all forward years are estimated assuming an annual escalation. In addition to the forward price being estimated using
unobservable inputs, the Company also estimates the volumes of the transactions that will take place in the future based on historical
average transaction volumes per delivery year (November to April). Significant increases or decreases in any of these inputs in
isolation would result in a significantly higher or lower fair value measurement. Generally, a change in the current year O&M charges
for the surrogate plants is accompanied by a directionally similar change in O&M charges in future years. There is generally not a
correlation between external market prices and the O&M charges used to develop the internal forward price.
For power commodity option agreements, the Company uses the Black-Scholes-Merton valuation model to estimate the fair value, and
IFERC FORM NO. I (ED. 12-88) Page 123.24
Name of Respondent This Report is: Date of Report Year/Period of Report
I (1)An Original (Mo, Da, Yr)
L Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
I NOTES TO FINANCIAL STATEMENTS (Continued)
this model includes significant inputs not observable or corroborated in the market. These inputs include 1) the strike price (which is
an internally derived price based on a combination of generation plant heat rate factors, natural gas market pricing, delivery and other
O&M charges, 2) estimated delivery volumes for years beyond 2013, and 3) volatility rates for periods beyond January 2016.
Significant increases or decreases in any of these inputs in isolation would result in a significantly higher or lower fair value
measurement. Generally, changes in overall commodity market prices and volatility rates are accompanied by directionally similar
changes in the strike price and volatility assumptions used in the calculation.
For natural gas commodity exchange agreements, the Company uses the same Level 2 brokered quotes described above; however, the
Company also estimates the purchase and sales volumes (within contractual limits) as well as the timing of those transactions.
Changing the timing of volume estimates changes the timing of purchases and sales, impacting which brokered quote is used. Because
the brokered quotes can vary significantly from period to period, the unobservable estimates of the timing and volume of transactions
can have a significant impact on the calculated fair value. The Company currently estimates volumes and timing of transactions based
on a most likely scenario using historical data. Historically, the timing and volume of transactions have not been highly correlated with
market prices and market volatility.
The following table presents the quantitative information which was used to estimate the fair values of the Level 3 assets and liabilities
above as of December 31, 2012 (dollars in thousands):
Fair Value (Net)
at

December 31, Valuation
2012 Technique
Power exchange agreements $ (18,692) Surrogate facility
pricing
Unobservable Input Range
O&M charges $30.49-$53.82/MWh (1)

Escalation factor 5% - 2013 to 2015
3%-2016to 2019
Transaction volumes 365,619- 379,156 MWhs
Power option agreements (1,480) Black-Scholes- Strike price $52.6 1/MWh - 2013
Merton
$76.63/MWh - 2019

Delivery volumes 128,491 - 287,147 MWhs

Volatility rates 0.20(2)
Natural gas exchange (2,379) Internally derived Forward purchase
agreements weighted average prices

cost of gas $3.19 - $3.38/mmBTU

Forward sales prices $3.29 - $4.46/mmBTU
Purchase volumes 135,000 - 465,000 mmBTUs
Sales volumes 140,010 - 620,000 mmBTUs
(1)The average O&M charges for 2012 were $40.87 per MWh.
(2)The estimated volatility rate of 0.20 is compared to actual quoted volatility rates of 0.33 for 2012 to 0.21 in January 2016.
Avista Corp.'s risk management team and accounting team are responsible for developing the valuation methods described above and
both groups report to the Chief Financial Officer. The valuation methods, the significant inputs, and the resulting fair values described
above are reviewed on at least a quarterly basis by the risk management team and the accounting team to ensure they provide a
reasonable estimate of fair value each reporting period.
IFERC FORM NO. 1 (ED. 12-88) Page 123.25 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
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):
Year ended December 31, 2012:
Balance as of January 1, 2012
Total gains or losses (realized/unrealized):
Included in net income
Included in other comprehensive income
Included in regulatory assets/liabilities (1)
Purchases
Issuance
Settlements
Transfers to/from other categories
Ending balance as of December 31, 2012
Year ended December 31, 2011:
Balance as of January 1, 2011
Total gains or losses (realized/unrealized):
Included in net income
Included in other comprehensive income
- Included in regulatory assets/liabilities (1)
Purchases
Issuance
Settlements
Transfers from other categories (2)
Ending balance as of December 31, 2011

Natural Gas Power

Exchange Exchange Power Option
Agreements Agreements Total
$ (1,688) $ (9,910) $ (1,260) $ (12,858)

343 (15,236) (220) (15,113)

(1,034) 6,454 - 5,420
$(2,379) $ (18,692) $ (1,480) $ (22,551)
$ - $ 15,793 $ (2,334) $ 13,459

2,621 (28,571) 1,074 (24,876)

95 2,868 - 2,963

(4,404) - - (4,404)
$ (1,688) $ (9,910).$ (1,260) $ (12,858)
(1)The UTC and the IPUC issued accounting orders authorizing Avista Corp. to offset commodity derivative assets or liabilities
with a regulatory asset or liability. This accounting treatment is intended to defer the recognition of mark-to-market gains and
losses on energy commodity transactions until the period of settlement. The orders provide for Avista Corp. to not recognize
the unrealized gain or loss on utility derivative commodity instruments in the Statements of Income. Realized gains or losses
are recognized in the period of settlement, subject to approval for recovery through retail rates. Realized gains and losses,
subject to regulatory approval, result in adjustments to retail rates through purchased gas cost adjustments, the ERM in
Washington, the PCA mechanism in Idaho, and periodic general rates cases.
(2)A derivative contract was reclassified from Level 2 to Level 3 during 2011 due to a particular unobservable input becoming
more significant to the fair value measurement. There were not any reclassifications between Level 1 and Level 2. The
Company's policy is to reclassify identified items as of the end of the reporting period.
NOTE 16. COMMON STOCK
The Company has a Direct Stock Purchase and Dividend Reinvestment Plan under which the Company's shareholders may
automatically reinvest their dividends and make optional cash payments for the purchase of the Company's common stock at current-
market value.
The payment of dividends on common stock is restricted by provisions of certain covenants applicable to preferred stock contained in
the Company's Articles of Incorporation, as amended.
In August 2012, the Company entered into two sales agency agreements under which the Company may sell up to 2,726,390 shares of
its common stock from time to time. As of December 31, 2012, the Company had 1,795,199 shares available to be issued under these
agreements.
IFERC FORM NO. 1 (ED. 12-88) Page 123.26 I

92,499 201,674

(89,499) (107,575)

- (1,600)

3,000 92,499
$ 10.63 $ 12.25
$ - $ 11.80
$ 12.41 $ 10.69
$ 951 $ 1,318
$ 1,349 $ 1,279
$ 35 $ 1,393
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
Shares issued under sales agency agreements were as follows in the year ended December 31:
2012 2011
Shares issued under sales agency agreement 931,191 807,000
The Company has 10 million authorized shares of preferred stock. The Company did not have any preferred stock outstanding as of
December 3l,2012 and 2011.
NOTE 17. STOCK COMPENSATION PLANS
A vista Corp.
1998 Plan
In 1998, the Company adopted, and shareholders approved, the Long-Term Incentive Plan (1998 Plan). Under the 1998 Plan, certain
key employees, officers and non-employee directors of the Company and its subsidiaries may be granted stock options, stock
appreciation rights, stock awards (including restricted stock) and other stock-based awards and dividend equivalent rights. The
Company has available a maximum of 4.5 million shares of its common stock for grant under the 1998 Plan. As of December 31, 2012,
0.7 million shares were remaining for grant under this plan.
2000 Plan
In 2000, the Company adopted a Non-Officer Employee Long-Term Incentive Plan (2000 Plan), which was not required to be
approved by shareholders. The provisions of the 2000 Plan are essentially the same as those under the 1998 Plan, except for the
exclusion of non-employee directors and executive officers of the Company. The Company has available a maximum of 2.5 million
shares of its common stock for grant under the 2000 Plan. However, the Company currently does not plan to issue any further options
or securities under the 2000 Plan. As of December 31, 2012, 1.9 million shares were remaining for grant under this plan.
Stock Compensation
The Company records compensation cost relating to share-based payment transactions in the financial statements based on the fair
value of the equity or liability instruments issued. The Company recorded stock-based compensation expense (included in other
operating expenses) and income tax benefits in the Statements of Income of the following amounts for the years ended December 31
(dollars in thousands):
2012 2011
Stock-based compensation expense $ 5,792 $ 5,756
Income tax benefits 2,027 2,014
Stock Options
The following summarizes stock options activity under the 1998 Plan and the 2000 Plan for the years ended December 31:
2012 2011
Number of shares under stock options:
Options outstanding at beginning of year
Options granted
Options exercised
Options canceled
Options outstanding and exercisable at end of year
Weighted average exercise price:
Options exercised
Options canceled
Options outstanding and exercisable at end of year
Cash received from options exercised (in thousands)
Intrinsic value of options exercised (in thousands)
Intrinsic value of options outstanding (in thousands)
IFERC FORM NO. I (ED. 12-88) Page 123.27 1
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Information for options outstanding and exercisable as of December 31, 2012 is as follows:
Weighted Weighted
Average Average
Number Exercise Remaining
Exercise Price Prim-. i .w (in yea)
$12.41 3,000 12.41 0.35
As of December 31, 2012 and 2011, the Company's stock options were fully vested and expensed.
Restricted Shares
Restricted share awards vest in equal thirds each year over a three-year period and are payable in Avista Corp. common stock at the
end of each year if the service condition is met. In addition to the service condition, the Company must meet a return on equity target
in order for the CEO's restricted shares to vest. During the vesting period, employees are entitled to dividend equivalents which are
paid when dividends on the Company's common stock are declared. Restricted stock is valued at the close of market of the Company's
common stock on the grant date. The weighted average remaining vesting period for the Company's restricted shares outstanding as of
December 31, 2012 was 0.7 years. The following table summarizes restricted stock activity for the years ended December 31:
2012 2011
Unvested shares at beginning of year 93,482 84,134
Shares granted 70,281 50,618
Shares canceled (790) (431)
Shares vested (45,855) (40,839)
Unvested shares at end of year 117,118 93,482
Weighted average fair value at grant date $ 25.83 $ 23.06
Unrecognized compensation expense at end of year (in thousands) $ 1,428 $ 932
Intrinsic value, unvested shares at end of year (in thousands) $ 2,824 $ 2,407
Intrinsic value, shares vested during the year (in thousands) $ 1,173 $ 934
Performance Shares
Performance share awards vest after a period of three years and are payable in cash or Avista Corp. common stock at the end of the
three-year period. Performance share awards entitle the recipients to dividend equivalent rights, are subject to forfeiture under certain
circumstances, and are subject to meeting specific performance conditions. Based on the attainment of the performance condition, the
amount of cash paid or common stock issued will range from 0 to 150 percent of the performance shares granted for grants prior to
2011 and 0 to 200 percent for grants in 2011 and after, depending on the change in the value of the Company's common stock relative
to an external benchmark. Dividend equivalent rights are accumulated and paid out only on shares that eventually vest.
Performance share awards entitle the grantee to shares of common stock or cash payable once the service condition is satisfied. Based
on attainment of the performance condition, grantees may receive 0 to 150 percent of the original shares granted for grants prior to
2011 and 0 to 200 percent for shares granted in 2011 and after. The performance condition used is the Company's Total Shareholder
Return performance over a three-year period as compared against other utilities; this is considered a market-based condition.
Performance shares may be settled in common stock or cash at the discretion of the Company. Historically, the Company has settled
these awards through issuance of stock and intends to continue this practice. These awards vest at the end of the three-year period.
Performance shares are equity awards with a market-based condition, which results in the compensation cost for these awards being
recognized over the requisite service period, provided that the requisite service period is rendered, regardless of when, if ever, the
market condition is satisfied.
The Company measures (at the grant date) the estimated fair value of performance shares awarded. The fair value of each performance
share award was estimated on the date of grant using a statistical model that incorporates the probability of meeting performance
targets based on historical returns relative to a peer group. Expected volatility was based on the historical volatility of Avista Corp.
common stock over a three-year period. The expected term of the performance shares is three years based on the performance cycle.
The risk-free interest rate was based on the U.S. Treasury yield at the time of grant. The compensation expense on these awards will
only be adjusted for changes in forfeitures.
IFERC FORM NO. 1 (ED. 12-88) Page 123.28
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
The following summarizes the weighted average assumptions used to determine the fair value of performance shares and related
compensation expense as well as the resulting estimated fair value of performance shares granted:
Risk-free interest rate
Expected life, in years
Expected volatility
Dividend yield
Weighted average grant date fair value (per share)
The fair value includes both performance shares and dividend equivalent rights.
The following summarizes performance share activity:
Opening balance of unvested performance shares
Performance shares granted
Performance shares canceled
Performance shares vested
Ending balance of unvested performance shares
Intrinsic value of unvested performance shares (in thousands)
Unrecognized compensation expense (in thousands)
2012 2011
0.3% 1.2%
3 3
22.7% 26.9%
4.5% 4.7%
26.06 $ 20.79
2012 2011

351,345 325,700

181,000 184,600

(4,544) (2,177)

(168,101) (156,778)

359,700 351,345
$ 8,672 $ 9,047
$ 3,800 $ 2,991
The weighted average remaining vesting period for the Company's performance shares outstanding as of December 31, 2012 was 1.5
years. Unrecognized compensation expense as of December 31, 2012 will be recognized during 2013. The following summarizes the
impact of the market condition on the vested performance shares:
2012 2011
Performance shares vested 168,101 156,778
Impact of market condition on shares vested (168,101) (15,678)
Shares of common stock earned - 141,100
Intrinsic value of common stock earned (in thousands) $ - $ 3,633
Shares earned under this plan are distributed to participants in the quarter following vesting.
Outstanding performance share awards include a dividend component that is paid in cash. This component of the performance share
grants is accounted for as a liability award. These liability awards are revalued on a quarterly basis taking into account the number of
awards outstanding, historical dividend rate, and the change in the value of the Company's common stock relative to an external
benchmark. Over the life of these awards, the cumulative amount of compensation expense recognized will match the actual cash paid.
As of December 31, 2012 and 2011, the Company had recognized compensation expense and a liability of $0.7 million and $1.0
million related to the dividend component of performance share grants.
NOTE 18. 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.
Federal Energy Regulatory Commission Inquiry
In April 2004, the Federal Energy Regulatory Commission (FERC) approved the contested Agreement in Resolution of Section 206
Proceeding (Agreement in Resolution) between Avista Corp., Avista Energy and the FERC's Trial Staff which stated that there was: (1)
no evidence that any executives or employees of Avista Corp. or Avista Energy knowingly engaged in or facilitated any improper
trading strategy during 2000 and 2001; (2) no evidence that Avista Corp. or Avista Energy engaged in any efforts to manipulate the
IFERC FORM NO. 1 (ED. 12-88) Page 123.29
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
western energy markets during 2000 and 2001; and (3) no finding that Avista Corp. or Avista Energy withheld relevant information
from the FERC's inquiry into the western energy markets for 2000 and 2001 (Trading Investigation). The Attorney General of the State
of California (California AG), the California Electricity Oversight Board, and the City of Tacoma, Washington (City of Tacoma)
challenged the FERC's decisions approving the Agreement in Resolution, which are now pending before the United States Court of
Appeals for the Ninth Circuit (Ninth Circuit). In May 2004, the FERC provided notice that Avista Energy was no longer subject to an
investigation reviewing certain bids above $250 per MW in the short-term energy markets operated by the California Independent
System Operator (Ca1ISO) and the California Power Exchange (Ca1PX) from May 1, 2000 to October 2, 2000 (Bidding Investigation).
That matter is also pending before the Ninth Circuit, after the California AG, Pacific Gas & Electric (PG&E), Southern California
Edison Company (SCE) and the California Public Utilities Commission (CPUC) filed petitions for review in 2005.
Based on the FERC's order approving the Agreement in Resolution in the Trading Investigation and order denying rehearing requests,
the Company does not expect that this proceeding will have any material effect on its financial condition, results of operations or cash
flows. Furthermore, based on information currently known to the Company regarding the Bidding Investigation and the fact that the
FERC Staff did not find any evidence of manipulative behavior, the Company does not expect that this matter will have a material
effect on its financial condition, results of operations or cash flows.
California Refund Proceeding
In July 2001, the FERC ordered an evidentiary hearing to determine the amount of refunds due to California energy buyers for
purchases made in the spot markets operated by the CalISO and the Ca1PX during the period from October 2, 2000 to June 20, 2001
(Refund Period). Proposed refunds are based on the calculation of mitigated market clearing prices for each hour. The FERC ruled that
if the refunds required by the formula would cause a seller to recover less than its actual costs for the Refund Period, sellers may
document these costs and limit their refund liability commensurately. In September 2005, Avista Energy submitted its cost filing claim
pursuant to the FERC's August 2005 order. The filing was initially accepted by the FERC, but in March 2011, the FERC ordered
Avista Energy to remove any return on equity in a compliance filing with the CalISO, which Avista Energy did in April 2011. A
challenge to Avista Energy's cost filing by the California AG, the CPUC, PG&E and SCE was denied in July 2011 as a collateral attack
on the FERC's prior orders accepting Avista Energy's cost filing. In July 2011, the California AG, the CPUC, PG&E and SCE filed a
petition for review of the FERC's orders regarding Avista Energy's cost filing with the Ninth Circuit.
The 2001 bankruptcy of PG&E resulted in a default on its payment obligations to the CaIPX. As a result, Avista Energy has not been
paid for all of its energy sales during the Refund Period. Those funds are now in escrow accounts and will not be released until the
FERC issues an order directing such release in the California refund proceeding. The Ca1ISO continues to work on its compliance
filing for the Refund Period, which will show "who owes what to whom." In July 2011, the FERC accepted the preparatory rerun
compliance filings by the Ca1PX and Ca1ISO, and responded to the Ca1PX request for guidance on issues related to completing the
final determination of "who owes what to whom." The FERC directed both the Ca1ISO and the Ca1PX to prepare and submit to the
FERC their final refund rerun compliance filings. The FERC's order also directs the Ca1PX to pay past due principal amounts to
governmental entities. In February 2012, the FERC denied the challenges made to the July 2011 order by the California AG, the
CPUC, PG&E and SCE. As of September 30, 2012, Avista Energy's accounts receivable outstanding related to defaulting parties in
California were fully offset by reserves for uncollected amounts and funds collected from the defaulting parties.
In August 2006, the Ninth Circuit upheld October 2, 2000 as the refund effective date for the FPA section 206 refund proceeding, but
remanded to the FERC its decision not to consider an FPA section 309 remedy for tariff violations prior to that date. In an order issued
in May 2011, the FERC clarified the issues set for hearing for the period May 1, 2000 - October 1, 2000 (Summer Period): (1) which
market practices and behaviors constitute a violation of the then-current Ca1ISO, Ca1PX, and individual seller's tariffs and FERC
orders; (2) whether any of the sellers named as respondents in this proceeding engaged in those tariff violations; and (3) whether any
such tariff violations affected the market clearing price. The FERC reiterated that the California Parties are expected to be very
specific when presenting their arguments and evidence, and that general claims would not suffice. The FERC also gave the California
Parties an opportunity to show that exchange transactions with the CaIISO during the Refund Period were not just and reasonable.
Avista Energy has one exchange transaction with the CaIISO. The California AG, the CPUC, PG&E and SCE filed for rehearing of the
FERC's May 2011 order, arguing that it improperly denies them a market-wide remedy for the pre-refund period. That request for
rehearing was denied in an order issued by FERC on November 2, 2012. The California AG, the CPUC, PG&E and SCE filed a
petition for review of the May 2011 and November 2012 orders with the Ninth Circuit on November 7, 2012.
A FERC hearing commenced on April 11, 2012 and concluded on July 19, 2012. On August 27, 2012, the Presiding Administrative
Law Judge issued a partial initial decision granting Avista Corp.'s motion for summary disposition, based on the stipulation by the
IFERC FORM NO. 1 (ED. 12-88) Page 123.30
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/Q4
NOTES TO FINANCIAL STATEMENTS (Continued)
California Parties that there are no allegations of tariff violations made against Avista Corp. in this proceeding and therefore no tariff
violations by Avista Corp. that affected the market clearing price in any hour during the Summer Period. On November 2, 2012, FERC
issued an order affirming the partial initial decision and dismissing Avista Corp. from the proceeding, thereby terminating all claims
against Avista Corp. for the Summer Period. In the same order, FERC also held that a market-wide remedy would not be appropriate
with regard to any respondent during the Summer Period. FERC stated that it is clear that the Ninth Circuit did not mandate a specific
remedy on remand and, instead, left it to the FERC's discretion to determine which remedy would be appropriate. On December 3,
2012, the California Parties filed a request for clarification and rehearing of the November 2, 2012 order. On February 15, 2013, the
Administrative Law Judge issued an initial decision finding that certain Respondents committed various tariff and other violations that
affected the market clearing price in the California organized markets during the Summer Period. The tariff violations identified for
Avista Energy are type II and III bidding violations; false export violations; and selling ancillary services without market-based rate
authority. The initial decision did not discuss evidence offered by Avista Energy, on an hour by hour basis, rebutting the alleged
violations and Avista Energy is currently preparing briefs on exceptions which will identify these errors. With respect to Avista
Energy's one exchange transaction with the Ca1ISO during the Refund Period, the judge made no findings with respect to the justness
and reasonableness of that transaction, but nonetheless determined that Avista Energy owed approximately $0.2 million in refunds with
regard to the transaction.
Because the resolution of the California refund proceeding remains uncertain, legal counsel cannot express an opinion on the extent of
the Company's liability, if any. However, based on information currently known, the Company does not expect that the refunds
ultimately ordered for the Refund Period would result in a material loss. In the event that the Commission does not overturn the legal
and factual errors in the February 15, 2013 initial decision, the Company does not expect that the refunds ultimately ordered for that
period would result in a material loss either. This is primarily due to the fact that the FERC orders have stated that any refunds will be
netted against unpaid amounts owed to the respective parties and the Company does not believe that refunds would exceed unpaid
amounts owed to the Company.
Pacflc Northwest Refund Proceeding
In July 2001, the FERC initiated a preliminary evidentiary hearing to develop a factual record as to whether prices for spot market
sales of wholesale energy in the Pacific Northwest between December 25, 2000 and June 20, 2001 were just and reasonable. In June
2003, the FERC terminated the Pacific Northwest refund proceedings, after finding that the equities do not justify the imposition of
refunds. In August 2007, the Ninth Circuit found that the FERC, in denying the request for refunds, had failed to take into account new
evidence of market manipulation in the California energy market and its potential ties to the Pacific Northwest energy market and that
such failure was arbitrary and capricious and, accordingly, remanded the case to the FERC, stating that the FERC's findings must be
reevaluated in light of the evidence. In addition, the Ninth Circuit concluded that the FERC abused its discretion in denying potential
relief for transactions involving energy that was purchased by the California Energy Resources Scheduling (CERS) in the Pacific
Northwest and ultimately consumed in California. The Ninth Circuit expressly declined to direct the FERC to grant refunds. The Ninth
Circuit denied petitions for rehearing by various parties, and remanded the case to the FERC in April 2009.
On October 3, 2011, the FERC issued an Order on Remand, finding that, in light of the Ninth Circuit's remand order, additional
procedures are needed to address possible unlawful activity that may have influenced prices in the Pacific Northwest spot market
during the period from December 25, 2000 through June 20, 2001. The Order establishes an evidentiary, trial-type hearing before an
Administrative Law Judge (AU), and reopens the record to permit parties to present evidence of unlawful market activity during the
relevant period. The Order also allows participants to supplement the record with additional evidence on CERS transactions in the
Pacific Northwest spot market from January 18, 2001 to June 20, 2001. The Order states that parties seeking refunds must submit
evidence demonstrating that specific unlawful market activity occurred, and must demonstrate that such activity directly affected
negotiations with respect to the specific contract rate about which they complain. Simply alleging a general link between the
dysfunctional spot market in California and the Pacific Northwest spot market will not be sufficient to establish a causal connection
between a particular seller's alleged unlawful activities and the specific contract negotiations at issue. Claimants filed notice of their
claims on August 17, 2012, and they filed their direct testimony on September 21, 2012. Respondents' filed their answering testimony
on December 17, 2012 and staff filed its answering testimony on February 5, 2013. Respondents' cross-answering testimony is due
February 22, 2013 and claimants' rebuttal testimony is due March 12, 2013. The hearing is scheduled to begin on April 15, 2013. On
July 11, 2012, Avista Energy and Avista Corp. filed settlements of all issues in this docket with regard to the claims made by the City
of Tacoma. On September 21, 2012, and September 26, 2012, the FERC issued orders approving the settlements between the City of
Tacoma and Avista Corp. and Avista Energy, respectively, thus terminating those claims. The two remaining direct claimants against
Avista Corp. and Avista Energy in this proceeding are the City of Seattle, Washington, and the California Attorney General (on behalf
of CERS).
IFERC FORM NO. 1 (ED. 12-88) Page 123.31
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
Both Avista Corp. and Avista Energy were buyers and sellers of energy in the Pacific Northwest energy market during the period
between December 25, 2000 and June 20, 2001 and, are subject to potential claims in this proceeding, and if refunds are ordered by the
FERC with regard to any particular contract, could be liable to make payments. The Company cannot predict the outcome of this
proceeding or the amount of any refunds that Avista Corp. or Avista Energy could be ordered to make. Therefore, the Company cannot
predict the potential impact the outcome of this matter could ultimately have on the Company's results of operations, financial
condition or cash flows.
California Attorney General Complaint (the "Lockyer Complaint")
In May 2002, the FERC conditionally dismissed a complaint filed in March 2002 by the California AG that alleged violations of the
FPA by the FERC and all sellers (including Avista Corp. and its subsidiaries) of electric power and energy into California. The
complaint alleged that the FERC's adoption and implementation of market-based rate authority was flawed and, as a result, individual
sellers should refund the difference between the rate charged and ajust and reasonable rate. In May 2002, the FERC issued an order
dismissing the complaint. In September 2004, the Ninth Circuit upheld the FERC's market-based rate authority, but held that the FERC
erred in ruling that it lacked authority to order refunds for violations of its reporting requirement. The Court remanded the case for
further proceedings.
In March 2008, the FERC issued an order establishing a trial-type hearing to address "whether any individual public utility seller's
violation of the FERC's market-based rate quarterly reporting requirement led to an unjust and unreasonable rate for that particular
seller in California during the 2000-2001 period." Purchasers in the California markets were given the opportunity to present evidence
that "any seller that violated the quarterly reporting requirement failed to disclose an increased market share sufficient to give it the
ability to exercise market power and thus cause its market-based rates to be unjust and unreasonable." In March 2010, the Presiding
ALJ granted the motions for summary disposition and found that a hearing was "unnecessary" because the California AG, CPUC,
PG&E and SCE "failed to apply the appropriate test to determine market power during the relevant time period." The judge
determined that "[w]ithout a proper showing of market power, the California Parties failed to establish a prima facie case." In May
2011, the FERC affirmed "in all respects" the AL's decision. In June 2011, the California AG, CPUC, PG&E and SCE filed for
rehearing of that order. Those rehearing requests were denied by the FERC on June 13, 2012. On June 20, 2012, the California AG,
CPUC, PG&E and SCE filed a petition for review of the FERC's order with the Ninth Circuit. On February 6, 2013, the California AG,
CPUC, PG&E, and SCE filed an unopposed motion with the Ninth Circuit, requesting that a briefing schedule be established, such that
petitioners' joint opening brief would be due May 17, 2013; respondents' answering brief would be due July 16, 2013;
respondent-intervenors' joint brief would be due August 6, 2013; and petitioners' optional joint reply brief would be due September 10,
2013.
Based on information currently known to the Company's management, the Company does not expect that this matter will have a
material effect on its financial condition, results of operations or cash flows.
Coistrip Generating Project Complaint
In March 2007, two families that own property near the holding ponds from Units 3 & 4 of the Colstrip Generating Project (Colstrip)
filed a complaint against the owners of Colstrip and Hydrometrics, Inc. in Montana District Court. Avista Corp. owns a 15 percent
interest in Units 3 & 4 of Colstrip. The plaintiffs alleged that the holding ponds and remediation activities adversely impacted their
property. They alleged contamination, decrease in water tables, reduced flow of streams on their property and other similar impacts to
their property. They also sought punitive damages, attorney's fees, an order by the court to remove certain ponds, and the forfeiture of
profits earned from the generation of Colstrip. In September 2010, the owners of Colstrip filed a motion with the court to enforce a
settlement agreement that would resolve all issues between the parties. In October 2011 the court issued an order which enforces the
settlement agreement. The plaintiffs subsequently appealed the court's decision and, on December 31, 2012, the Montana Supreme
Court issued its decision, holding that the District Court properly granted the motion to enforce the settlement agreement. A petition
for rehearing before the Supreme Court was denied on February 5, 2013. Under the settlement, Avista Corp.'s portion of payment
(which was accrued in 2010) to the plaintiffs was not material to its financial condition, results of operations or cash flows.
Sierra Club and Montana Environmental Information Center Notice
On July 30, 2012, Avista Corp. received a Notice of Intent to Sue for violations of the Clean Air Act at Colstrip Steam Electric Station
(Notice) from counsel on behalf of the Sierra Club and the Montana Environmental Information Center (MEIC), an Amended Notice
was received on September 4, 2012, and a Second Amended Notice was received on October 1, 2012. A "supplemental" Notice was
received on December 4, 2012. The Notice, Amended Notice, Second Amended Notice and Supplemental Notice were all addressed to
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NOTES TO FINANCIAL STATEMENTS (Continued)
the Owner or Managing Agent of Coistrip, and to the other Coistrip co-owners: PPL Montana, Puget Sound Energy, Portland General
Electric Company, NorthWestern Energy and PacifiCorp. The Notice alleges certain violations of the Clean Air Act, including the
New Source Review, Title V and opacity requirements. The Amended Notice alleges additional opacity violations at Colstrip, and the
Second Amended Notice alleges additional Title V allegations. All three notices state that Sierra Club and MEIC will request a United
States District Court to impose injunctive relief and civil penalties, require a beneficial environmental project in the areas affected by
the alleged air pollution and require reimbursement of Sierra Club's and MEIC's costs of litigation and attorney's fees. Under the Clean
Air Act, lawsuits cannot be filed until 60 days after the applicable notice date. Avista Corp. is evaluating the allegations set forth in the
Notice, Amended Notice and Second Amended Notice and Supplemental Notice, and cannot at this time predict the outcome of this
matter.
Harbor Oil Inc. Site
Avista Corp. used Harbor Oil Inc. (Harbor Oil) for the recycling of waste oil and non-PCB transformer oil in the late 1980s and early
1990s. In June 2005, the Environmental Protection Agency (EPA) Region 10 provided notification to Avista Corp. and several other
parties, as customers of Harbor Oil, that the EPA had determined that hazardous substances were released at the Harbor Oil site in
Portland, Oregon and that Avista Corp. and several other parties may be liable for investigation and cleanup of the site under the
Comprehensive Environmental Response, Compensation, and Liability Act, commonly referred to as the federal "Superfund" law,
which provides for joint and several liability. The initial indication from the EPA is that the site may be contaminated with PCBs,
petroleum hydrocarbons, chlorinated solvents and heavy metals. Six potentially responsible parties, including Avista Corp., signed an
Administrative Order on Consent with the EPA on May 31, 2007 to conduct a remedial investigation and feasibility study (RI/FS). The
draft final RI/FS was submitted to the EPA in December 2011 and was accepted as pre-fmal in March 2012. The EPA issued a notice
of its plan to make a finding of No Further Action in November 2012. Should the EPA make a No Further Action determination, the
EPA stated it would then propose removal of the site from the National Priority List. Based on the review of its records related to
Harbor Oil, the Company does not believe it is a significant contributor to this potential environmental contamination based on the
small volume of waste oil it delivered to the Harbor Oil site. As such, the Company does not expect that this matter will have a material
effect on its financial condition, results of operations or cash flows. The Company has expensed its share of the RI/FS ($0.5 million)
for this matter.
Spokane River Licensing
The Company owns and operates six hydroelectric plants on the Spokane River. Five of these (Long Lake, Nine Mile, Upper Falls,
Monroe Street, and Post Falls) are regulated under one 50-year FERC license issued in June 2009 and are referred to as the Spokane
River Project. The sixth, Little Falls, is operated under separate Congressional authority and is not licensed by the FERC. The license
incorporated the 4(e) conditions that were included in the December 2008 Settlement Agreement with the United States Department of
Interior and the Coeur d'Alene Tribe, as well as the mandatory conditions that were agreed to in the Idaho 401 Water Quality
Certifications and in the amended Washington 401 Water Quality Certification.
As part of the Settlement Agreement with the Washington Department of Ecology (Ecology), the Company has participated in the
Total Maximum Daily Load (TIvIDL) process for the Spokane River and Lake Spokane, the reservoir created by Long Lake Dam. On
May 20, 2010, the EPA approved the TMDL and on May 27, 2010, Ecology filed an amended 401 Water Quality Certification with
the FERC for inclusion into the license. The amended 401 Water Quality Certification includes the Company's level of responsibility,
as defined in the TMDL, for low dissolved oxygen levels in Lake Spokane. The Company submitted a draft Water Quality Attainment
Plan for Dissolved Oxygen to Ecology in May 2012 and this was approved by Ecology in September 2012. This plan was subsequently
approved by the FERC. The Company will begin to implement this plan, and management believes costs will not be material. On July
16, 2010, the City of Post Falls and the Hayden Area Regional Sewer Board filed an appeal with the United States District Court for
the District of Idaho with respect to the EPA's approval of the TMDL. The Company, the City of Coeur d'Alene, Kaiser Aluminum and
the Spokane River Keeper subsequently moved to intervene in the appeal. In September 2011, the EPA issued a stay to the litigation
that will be in effect until either the permits are issued and all appeals and challenges are complete or the court lifts the stay. The stay is
still in effect.
The IPUC and the UTC approved the recovery of licensing costs through the general rate case settlements in 2009. The Company will
continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to implementing the license for
the Spokane River Project.
Cabinet Gorge Total Dissolved Gas Abatement Plan
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NOTES TO FINANCIAL STATEMENTS (Continued)
Dissolved atmospheric gas levels in the Clark Fork River exceed state of Idaho and federal water quality standards downstream of the
Cabinet Gorge Hydroelectric Generating Project (Cabinet Gorge) during periods when excess river flows must be diverted over the
spillway. Under the terms of the Clark Fork Settlement Agreement as incorporated in Avista Corp.'s FERC license for the Clark Fork
Project, Avista Corp. has worked in consultation with agencies, tribes and other stakeholders to address this issue. In the second
quarter of 2011, the Company completed preliminary feasibility assessments for several alternative abatement measures. In 2012,
Avista Corp., with the approval of the Clark Fork Management Committee (created under the Clark Fork Settlement Agreement),
moved forward to test one of the alternatives by constructing a spill crest modification on a single spill gate. The modification will be
tested in 2013 to evaluate whether this approach will provide significant TDG reduction, and whether it could be applied to other spill
gates. The Company will continue to seek recovery, through the ratemaking process, of all operating and capitalized costs related to
this issue.
Fish Passage at Cabinet Gorge and Noxon Rapids
In 1999, the USFWS listed bull trout as threatened under the Endangered Species Act. The Clark Fork Settlement Agreement describes
programs intended to help restore bull trout populations in the project area. Using the concept of adaptive management and working
closely with the USFWS, the Company evaluated the feasibility of fish passage at Cabinet Gorge and Noxon Rapids. The results of
these studies led, in part, to the decision to move forward with development of permanent facilities, among other bull trout
enhancement efforts. As of the end of 2012, fishway design for Cabinet Gorge was still being finalized. Construction cost estimates
and schedules will be developed in 2013. Fishway design for Noxon Rapids has also been initiated, and is still in early stages.
In January 2010, the USFWS revised its 2005 designation of critical habitat for the bull trout to include the lower Clark Fork River as
critical habitat. The Company believes its ongoing efforts through the Clark Fork Settlement Agreement continue to effectively address
issues related to bull trout. The Company will continue to seek recovery, through the ratemaking process, of all operating and
capitalized costs related to fish passage at Cabinet Gorge and Noxon Rapids.
Aluminum Recycling Site
In October 2009, the Company (through its subsidiary Pentzer Venture Holdings II, Inc. (Pentzer)) received notice from Ecology
proposing to find Pentzer liable for a release of hazardous substances under the Model Toxics Control Act, under Washington state
law. Pentzer owns property that adjoins land owned by the Union Pacific Railroad (UPR). UPR leased their property to operators of a
facility designated by Ecology as "Aluminum Recycling - Trentwood." Operators of the UPR property maintained piles of aluminum
dross, which designate as a state-only dangerous waste in Washington State. In the course of its business, the operators placed a
portion of the aluminum dross pile on the property owned by Pentzer. Pentzer does not believe it is a contributor to any environmental
contamination associated with the dross pile, and submitted a response to Ecology's proposed findings in November 2009. In
December 2009, Pentzer received notice from Ecology that it had been designated as a potentially liable party for any hazardous
substances located on this site. UPR completed a Remedial Investigation/Feasibility Study during 2011, which was approved by
Ecology in 2012. Based on information currently known to the Company's management, the Company does not expect this issue will
have a material effect on its financial condition, results of operations or cash flows.
Collective Bargaining Agreements
The Company's collective bargaining agreement with the International Brotherhood of Electrical Workers represents approximately 45
percent of all of Avista Corp.'s employees. The agreement with the local union in Washington and Idaho representing the majority
(approximately 90 percent) of the bargaining unit employees expires in March 2014. Two local agreements in Oregon, which cover
approximately 50 employees, expire in March 2014.
Other Contingencies
In the normal course of business, the Company has various other legal claims and contingent matters outstanding. The Company
believes that any ultimate liability arising from these actions will not have a material impact on its financial condition, results of
operations or cash flows. It is possible that a change could occur in the Company's estimates of the probability or amount of a liability
being incurred. Such a change, should it occur, could be significant.
The Company routinely assesses, based on studies, expert analyses and legal reviews, its contingencies, obligations and commitments
for remediation of contaminated sites, including assessments of ranges and probabilities of recoveries from other responsible parties
who either have or have not agreed to a settlement as well as recoveries from insurance carriers. The Company's policy is to accrue
and charge to current expense identified exposures related to environmental remediation sites based on estimates of investigation,
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NOTES TO FINANCIAL STATEMENTS (Continued)
cleanup and monitoring costs to be incurred. For matters that affect Avista Corp.'s operations, the Company seeks, to the extent
appropriate, recovery of incurred costs through the ratemaking process.
The Company has potential liabilities under the Endangered Species Act for species of fish 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 this issue.
Under the federal licenses for its hydroelectric projects, the Company is obligated to protect its property rights, including water rights.
The state of Montana is examining the status of all water right claims within state boundaries. Claims within the Clark Fork River basin
could adversely 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. In addition, the state of Washington has indicated an interest in initiating adjudication for the Spokane River
basin in the next several years. The Company is and will continue to be a participant in these adjudication processes. The complexity
of such adjudications makes each unlikely to be concluded in the foreseeable future. As such, it is not possible for the Company to
estimate the impact of any outcome at this time.
NOTE 19. INFORMATION SERVICES CONTRACTS
The Company has information services contracts that expire at various times through 2018. The largest of these contracts provides for
increases due to changes in the cost of living index and further provides flexibility in the annual obligation from year-to-year subject to
a three-year true-up cycle. Total payments under these contracts were as follows for the years ended December 31 (dollars in
thousands):
2012 2011
Information service contract payments $ 13,221 $ 13,038
The majority of the costs are included in other operating expenses in the Statements of Income. The following table details minimum
future contractual commitments for these agreements (dollars in thousands):
2013 2014 2015 2016 2017 Thereafter Total
Contractual obligations $ 11,175 $ 9,400 $ 8,700 $ 8,700 $ 8,600 $ 900 $ 47,475
IFERC FORM NO. 1 (ED. 12-88) Page 123.35
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NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 20. REGULATORY MATTERS
Power Cost Deferrals and Recovery Mechanisms
Deferred power supply costs are recorded as a deferred charge on the Balance Sheets for future prudence review and recovery through
retail rates. The power supply costs deferred include certain differences between actual net power supply costs incurred by Avista
Corp. and the costs included in base retail rates. This difference in net power supply costs primarily results from changes in:
short-term wholesale market prices and sales and purchase volumes,
• the level of hydroelectric generation,
• the level of thermal generation (including changes in fuel prices), and
• retail loads.
In Washington, the Energy Recovery Mechanism (ERM) allows Avista Corp. to periodically increase or decrease electric rates with
UTC approval to reflect changes in power supply costs. The ERM is an accounting method used to track certain differences between
actual net power supply costs, net of the margin on wholesale sales and sales of fuel, and the amount included in base retail rates for
Washington customers. In the 2010 Washington general rate case settlement, the parties agreed that there would be no deferrals under
the ERM for 2010. Deferrals under the ERM resumed in 2011. Total net deferred power costs under the ERM were a liability of $22.2
million as of December 31, 2012, and this balance represents the customer portion of the deferred power costs. As part of the approved
Washington general rate case settlement filed on October 19, 2012 and approved on December 26, 2012, during 2013 a one-year credit
of $4.4 million would be returned to electric customers from the existing ERM deferral balance so the net average electric rate increase
to customers in 2013 would be 2.0 percent. Additionally, during 2014 a one-year credit of $9.0 million would be returned to electric
customers from the then-existing ERIvI deferral balance, if such funds are available, so the net average electric rate increase to
customers effective January 1, 2014 would be 2.0 percent. The credits to customers from the ERM balances would not impact the
Company's net income.
Under the ERM, the Company absorbs the cost or receives the benefit from the initial amount of power supply costs in excess of or
below the level in retail rates, which is referred to as the deadband. The annual (calendar year) deadband amount is currently $4.0
million. The Company will incur the cost of, or receive the benefit from, 100 percent of this initial power supply cost variance. The
Company shares annual power supply cost variances between $4.0 million and $10.0 million with its customers. There is a 50 percent
customers/SO percent Company sharing ratio when actual power supply expenses are higher (surcharge to customers) than the amount
included in base retail rates within this band. There is a 75 percent customers/25 percent Company sharing ratio when actual power
supply expenses are lower (rebate to customers) than the amount included in base retail rates within this band. To the extent that the
annual power supply cost variance from the amount included in base rates exceeds $10.0 million, 90 percent of the cost variance is
deferred for future surcharge or rebate. The Company absorbs or receives the benefit in power supply costs of the remaining 10 percent
of the annual variance beyond $10.0 million without affecting current or future customer rates.
The following is a summary of the ERM:
Deferred for Future
Surcharge or Rebate Expense or Benefit
Annual Power Supply Cost Variability to Customers
within +1- $0 to $4 million (deadband) 0% 100%
higher by $4 million to $10 million 50% 50%
lower by $4 million to $10 million 75% 25%
higher or lower by over $10 million 90% 10%
As part of the 2012 Washington general rate case settlement, the proposed modifications to the ERM deadband and other sharing
bands that were included in the original April 2012 general rate case filing were not agreed to and the ERM will continue unchanged.
However, the trigger point at which rates will change under the ERM was modified to be $30 million rather than the current 10 percent
of base revenues (approximately $45 million) under the mechanism.
Avista Corp. has a Power Cost Adjustment (PCA) mechanism in Idaho that allows it to modify electric rates on October 1 of each year
with Idaho Public Utilities Commission (IPUC) approval. Under the PCA mechanism, Avista Corp. defers 90 percent of the difference
between certain actual net power supply expenses and the amount included in base retail rates for its Idaho customers. These annual
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NOTES TO FINANCIAL STATEMENTS (Continued)
October 1 rate adjustments recover or rebate power costs deferred during the preceding July-June twelve-month period. Total net
power supply costs deferred under the PCA mechanism were a regulatory liability of $5.1 million as of December 31, 2012 and $0.7
million as of December 31, 2011.
Natural Gas Cost Deferrals and Recovery Mechanisms
Avista Corp. files a purchased gas cost adjustment (PGA) in all three states it serves to adjust natural gas rates for: 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. These annual PGA filings in Washington and Idaho provide for
the deferral, and recovery or refund, of 100 percent of the differeiice between actual and estimated commodity and pipeline
transportation costs, subject to applicable regulatory review. The annual PGA filing in Oregon provides for deferral, and recovery or
refund, of 100 percent of the difference between actual and estimated pipeline transportation costs and commodity costs that are fixed
through hedge transactions. Commodity costs that are not hedged for Oregon customers are subject to a sharing mechanism whereby
Avista Corp. defers, and recovers or refunds, 90 percent of the difference between these actual and estimated costs. Total net deferred
natural gas costs to be refunded to customers were a liability of $6.9 million as of December 31, 2012 and $12.1 million as of
December 31, 2011.
Washington General Rate Cases
In December 2011, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in May
2011. As agreed to in the settlement agreement, base electric rates for the Company's Washington customers increased by an average
of 4.6 percent, which is designed to increase annual revenues by $20.0 million. Base natural gas rates for the Company's Washington
customers increased by an average of 2.4 percent, which is designed to increase annual revenues by $3.75 million. The new electric
and natural gas rates became effective on January 1, 2012.
As part of the settlement agreement, the Company agreed to not file a general rate case in Washington prior to April 1, 2012.
The settlement agreement also provides for the deferral of certain generation plant maintenance costs. In order to address the
variability in year-to-year maintenance costs, beginning in 2011, the Company is deferring changes in maintenance costs related to its
Coyote Spring 2 natural gas-fired generation plant and its 15 percent ownership interest in Units 3 & 4 of the Coistrip generation plant.
The Company compares actual, non-fuel, maintenance expenses for the Coyote Springs 2 and Colstrip plants with the amount of
baseline maintenance expenses used to establish base retail rates, and defers the difference. The deferral occurred annually, with no
carrying charge, with deferred costs being amortized over a four-year period, beginning in January of the year following the period
costs are deferred. The amount of expense to be requested for recovery in future general rate cases would be the actual maintenance
expense recorded in the test period, less any amount deferred during the test period, plus the amortization of previously deferred costs.
Total net deferred costs under this mechanism in Washington were a regulatory asset of $4.0 million as of December 31, 2012
compared to a regulatory liability of $0.5 million as of December 31, 2011.
As part of the settlement agreement in October 2012 to the Company's latest general rate case discussed in further detail below, the
parties have agreed that the maintenance cost deferral mechanism on these generation plants will terminate on December 31, 2012,
with the four-year amortization of the 2011 and 2012 deferrals to conclude in 2015 and 2016, respectively.
In December 2012, the UTC approved a settlement agreement in the Company's electric and natural gas general rate cases filed in
April 2012. Agreed to in the settlement, effective January 1, 2013, base rates for Washington electric customers increased by an
overall 3.0 percent (designed to increase annual revenues by $13.6 million), and base rates for Washington natural gas customers
increased by an overall 3.6 percent (designed to increase annual revenues by $5.3 million). The settling parties agree that a one-year
credit of $4.4 million will be returned to electric customers from the existing ERM deferral balance so the net average electric rate
increase impact to the Company's customers in 2013 will be 2.0 percent. The credit to customers from the ERM balance will not
impact the Company's earnings.
The settlement also provided that, effective January 1, 2014, the Company will implement temporary base rate increases for
Washington electric customers by an overall 3.0 percent (designed to increase annual revenues by $14.0 million), and for Washington
natural gas customers by an overall 0.9 percent (designed to increase annual revenues by $1.4 million). The settling parties agree that a
one-year credit of $9.0 million will be returned to electric customers from the then-existing ERM deferral balance, if such funds are
available, so the net average electric rate increase to customers effective January 1, 2014 would be 2.0 percent. The credit to customers
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NOTES TO FINANCIAL STATEMENTS (Continued)
from the ERM balance will not impact the Company's earnings.
The UTC order approving the settlement agreement included certain conditions. The new retail rates to become effective January 1,
2014 will be temporary rates, and on January 1, 2015 electric and natural gas base rates will revert back to 2013 levels absent any
intervening action from the UTC. The settlement agreement also states that the Company will not file a general rate case in
Washington that would cause an increase in base retail rates before January 1, 2015. The Company could, however, make a filing prior
to January 2015, but new rates resulting from the filing would not take effect prior to January 1, 2015. This does not preclude the
Company from filing annual rate adjustments such as the PGA.
In addition, in its Order, the UTC found that much of the approved base rate increases are justified by the planned capital expenditures
necessary to upgrade and maintain the Company's utility facilities. If these capital projects are not completed to a level that was
contemplated in the original settlement agreement, this could result in base rates which are considered too high by the UTC. As a
result, Avista Corp. must file capital expenditure progress reports with the UTC on a periodic basis so that the UTC can monitor the
capital expenditures and ensure they are in line with those contemplated in the settlement agreement.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 47.0 percent, resulting in an
overall return on rate base of 7.64 percent.
Idaho General Rate Cases
In September 2011, the IPUC approved a settlement agreement in the Company's general rate case filed in July 2011. The new electric
and natural gas rates became effective on October 1, 2011. As agreed to in the settlement agreement, base electric rates for the
Company's Idaho customers increased by an average of 1.1 percent, which was designed to increase annual revenues by $2.8 million.
Base natural gas rates for the Company's Idaho customers increased by an average of 1.6 percent, which was designed to increase
annual revenues by $1.1 million.
As part of the settlement agreement, the Company agreed to not seek to make effective a change in base electric or natural gas rates
prior to April 1, 2013, by means of a general rate case filing. This does not preclude the Company from filing annual rate adjustments
such as the PCA and the PGA.
The settlement agreement also provides for the deferral of certain generation plant operation and maintenance costs. In order to address
the variability in year-to-year operation and maintenance costs, beginning in 2011, the Company is deferring changes in operation and
maintenance costs related to the Coyote Spring 2 natural gas-fired generation plant and its 15 percent ownership interest in Units 3 & 4
of the Colstrip generation plant. The Company compares actual, non-fuel, operation and maintenance expenses for the Coyote Springs
2 and Coistrip plants with the amount of expenses authorized for recovery in base rates in the applicable deferral year, and defers the
difference from that currently authorized. The deferral occurs annually, with no carrying charge, with deferred costs being amortized
over a three-year period, beginning in January of the year following the period costs are deferred. The amount of expense to be
requested for recovery in future general rate cases will be the actual operation and maintenance expense recorded in the test period,
less any amount deferred during the test period, plus the amortization of previously deferred costs. Total net deferred costs under this
mechanism in Idaho were regulatory assets of $2.3 million as of December 31, 2012 and $0.1 million as of December 31, 2011.
On October 11, 2012, the Company filed electric and natural gas general rate cases with the IPUC. The Company requested an overall
increase in electric rates of 4.6 percent and an overall increase in natural gas rates of 7.2 percent. The filings were designed to increase
annual electric revenues by $11.4 million and increase annual natural gas revenues by $4.6 million. The Company's requests were
based on a proposed overall rate of return of 8.46 percent, with a common equity ratio of 50 percent and a 10.9 percent return on
equity.
On February 6, 2013, Avista Corp. and certain other parties filed a settlement agreement with the IPUC with respect to Avista Corp.'s
electric and natural gas general rate cases. Parties to the settlement agreement include the staff of the IPUC, Clearwater Paper
Corporation, Idaho Forest Group, LLC, the Idaho Conservation League, and the Company. Community Action Partnership Association
of Idaho (CAPAI), a low-income customer advocacy group, and the Snake River Alliance did not join in the settlement agreement.
However, on February 20, 2013 the Snake River Alliance provided a letter to the IPUC supporting the settlement agreement. This
settlement agreement is subject to approval by the IPUC and would conclude the proceedings related the general rate requests filed by
the Company on October 11, 2012. New rates would be implemented in two phases: April 1, 2013 and October 1, 2013.
IFERC FORM NO. 1 (ED. 12-88) Page 123.38 I
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NOTES TO FINANCIAL STATEMENTS (Continued)
The settlement agreement proposes that, effective April 1, 2013, Avista Corp. would be authorized to implement a base rate increase
for Idaho natural gas customers of 4.9 percent (designed to increase annual revenues by $3.1 million). There would be no change in
base electric rates on April 1, 2013. However, the settlement agreement would provide for the recovery of the costs of the Palouse
Wind Project through the Power Cost Adjustment mechanism beginning April 1, 2013.
The settlement agreement also proposes that, effective October 1, 2013, Avista Corp. would be authorized to implement a base rate
increase for Idaho natural gas customers of 2.0 percent (designed to increase annual revenues by $1.3 million). A credit resulting from
deferred natural gas costs of $1.6 million would be returned to the Company's Idaho natural gas customers from October 1, 2013
through December 31, 2014, so the net annual average natural gas rate increase to natural gas customers effective October 1, 2013
would be 0.3 percent.
Further, the settlement proposes that, effective October 1, 2013, Avista Corp. would be authorized to implement a base rate increase
for Idaho electric customers of 3.1 percent (designed to increase annual revenues by $7.8 million). A $3.9 million credit resulting from
a payment to be made to Avista Corp. by the Bonneville Power Administration relating to its prior use of Avista Corp.'s transmission
system would be returned to Idaho electric customers from October 1, 2013 through December 31, 2014, so the net annual average
electric rate increase to electric customers effective October 1, 2013 would be 1.9 percent.
The $1.6 million credit to Idaho natural gas customers and the $3.9 million credit to Idaho electric customers would not impact the
Company's net income.
Also included in the settlement agreement is a provision that Avista Corp. may file a general rate case in Idaho in 2014;
however, new rates resulting from the filing would not take effect prior to January 1, 2015.
The settlement agreement provides for an authorized return on equity of 9.8 percent and an equity ratio of 50.0 percent.
The settlement also includes an after-the-fact earnings test for 2013 and 2014, such that if Avista Corp., on a consolidated basis for
electric and natural gas operations in Idaho, earns more than a 9.8 percent return on equity, Avista Corp. would refund to customers 50
percent of any earnings above the 9.8 percent.
Oregon General Rate Cases
In March 2011, the OPUC approved an all-party settlement stipulation in the Company's general rate case that was filed in September
2010. The settlement provides for an overall rate increase of 3.1 percent for the Company's Oregon customers, designed to increase
annual revenues by $3.0 million. Part of the rate increase became effective March 15, 2011, with the remaining increase effective
June 1, 2011. An additional rate adjustment designed to increase revenues by $0.6 million will occur on June 1, 2012 to recover capital
costs associated with certain reinforcement and replacement projects upon a demonstration that such projects are complete and the
costs were prudently incurred.
On January 1, 2013, Avista Corp. purchased the Klamath Falls Lateral (Lateral), a 15-mile, 6-inch natural gas transmission pipeline
from Williams Northwest Pipeline (Williams). The Klamath Falls Lateral interconnects with another interstate pipeline, Gas
Transmission Northwest, to transport natural gas to serve Avista Corp.'s customers in Klamath Falls, Oregon. The purchase price was
approximately $2.3 million and will save Oregon customers approximately $1.4 million annually as Avista Corp. will be able to reduce
its contracted natural gas transportation requirements from Williams. In Order No. 12429, the OPUC approved the Company's request
to recover from customers the revenue requirement associated with the purchase of the Lateral, which is approximately $0.5 million
annually. This approval will provide a return of and a return on Avista Corp.'s investment in the lateral. While the OPUC approved the
recovery of the revenue requirement, it will not determine whether the purchase of the Lateral was prudent until the Company's next
Oregon general rate case.
IFERC FORM NO. 1 (ED. 12-88) Page 123.39 I
Name of Respondent This Report is: Date of Report Year/Period of Report
(1)X An Original (Mo, Da, Yr)
Avista Corporation (2)- A Resubmission 04/12/2013 2012/04
NOTES TO FINANCIAL STATEMENTS (Continued)
NOTE 21. SUPPLEMENTAL CASH FLOW INFORMATION (in thousands)
2012 2011
Cash paid for interest $68,508 $63,876
Cash paid for income taxes $6,631 $16,631
FERC FORM NO. 1 (ED. 12-88) Page 123.40
This Page Intentionally Left Blank
Name of Respondent This Report Is: Date of Report Year/Period of Report
Avista Corporation End of 2012/Q4
(2) AResubmission
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
1 Report in columns (b),(c),(d) and (e) the amounts of accumulated other comprehensive income items, on a net-of-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.
Item Unrealized Gains and Minimum Pension Foreign Currency Other Line Losses on Available- Liability adjustment Hedges Adjustments No for-Sale Securities (net amount)
(a) (b) (c) (d) (e)
1 Balance of Account 219 at Beginning of
- Preceding Year ( 4,325,953)
2 Preceding QtrIYr to Date Reclassifications
- from Acct 219 to Net Income
3 Preceding Quarter/Year to Date Changes in
- Fair Value 134,046 ( 1,444,919)
4 Total (lines 2 and 3) 134,046 ( 1,444,919)
5 Balance of Account 219 at End of
- Preceding Quarter/Year 134,046 ( 5,770,872)
6 Balance of Account 219 at Beginning of
- Current Year 134,046 ( 5,770,872)
7 Current Qtr/Yr to Date Reclassifications
- from Acct 219 to Net Income ( 290,263)
8 Current Quarter/Year to Date Changes in
Fair Value - 323,478 ( 1,096,549)
9 Total (lines 7 and 8) 33,215 ( 1,096,549)
10 Balance of Account 219 at End of Current
- Quarter/Year 167,261 ( 6,867,421)
FERC FORM NO. 1 (NEW 06-02) Page 122a
Name of Respondent
Avista Corporation
-
This Report Is:
(1)An Original
(2)EA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
STATEMENTS OF ACCUMULATED COMPREHENSIVE INCOME, COMPREHENSIVE INCOME, AND HEDGING ACTIVITIES
Line
No.
-
Other Cash Flow
Hedges
Interest Rate Swaps
(f)
Other Cash Flow
Hedges
[Specify]
(g)
Totals for each
category of items
recorded in
Account 219
(h)
Net Income (Carried
Forward from
Page 117, Line 78)
(i)
Total
Comprehensive
Income
(1)
( 4,325,953)
2
3 ( 1,310,873)
4 ( 1,310,873) 100,223,872 98,912,999
5 ( 5,636,826)
6 ( 5,636,826)
7 ( 290,263)
8 ( 773,071)
9 ( 1,063,334) I 78,210,066 77,146,73
10 ( 6,700,160)
FERC FORM NO. I (NEW 06-02) Page 122b
Name of Respondent
Avista Corporation
I This Re ort Is: I
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
I 04/12/2013
Year/Period of Report
End of 20121Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
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.
Line
No
Classification
(a)
Total Company for the
Current Year/Quarter Ended
(b)
Electric
(c)
1 Utility Plant
2 Pn Service
3 Plant in Service (Classified) I 4,032,753,211 3,0330136601
4 Property Under Capital Leases 6,442,348
5 Plant Purchased or Sold
6 Completed Construction not Classified
7 1 Experimental Plant Unclassified
8 Total (3 thru 7) 4,039,195,559 3,033,013,660
9 Leased to Others
10 Held for Future Use 4,989,371 4,773,791
11 Construction Work in Progress 139,513,892 80,205,686
12 Acquisition Adjustments
13 Total Utility Plant (8 thru 12) 4,183,698,822 3,117,993,137
14 Accum Prov for Depr, Amort, & Depl 1,408,153,972 1,075,820,044
15 Net Utility Plant (13 less 14) 2,775,544,850 2,042,173,093
16 Detail of Accum Prov for Depr, Amort & DepI
17 In Service
18 Depreciation 1,375,661 ,341 1,065,032,018
19 Amort & DepI of Producing Nat Gas Land/Land Right
10,788,026
20 Amort of Underground Storage Land/Land Rights
21 Amort of Other Utility Plant 32,492,6311
22 Total In Service (18 thru 21) 1,408,153,972 1,075,820,044
23 Leased to Others
24 Depreciation
25 Amortization and Depletion
26 Total Leased to Others (24 & 25)
27 Held for Future Use
28 Depreciation
29 Amortization
30 Total Held for Future Use (28 & 29)
31 Abandonment of Leases (Natural Gas)
32 lAmort of Plant Acquisition Adj
33 Total Accum Prov (equals 14) (22,26,30,31,32) 1,408,153,972 1,075,820,044
FERC FORM NO. I (ED. 12-89) Page 200
Name of Respondent This Report Is: Date of Report Year/Period of Report
Avista Corporation (1)jAn Original (Mo, Da, Yr) End of 2012/Q4
(2)EA Resubmission 04/12/2013
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS
FOR DEPRECIATION. AMORTIZATION AND DEPLETION
Gas Other (Specify) Other (Specify) Other (Specify) Common Line
(d) (e) (f) (g) (h) No.
2
777,1113521 I
222628,1991 3
858,865 5,583,483 4
5
6
7
777,970,217 228,211,682 8
9
215,580 10
18,296,122 41,012,084 11
12
796,481,919 269,223,766 13
269,742,834 62,591,094 14
526,739,0851 206,632,672 15
16
17
268,498,7751 42,130,548 18
19
20
1,244,059' 20,460,5461 21
269,742,834 62,591,094 22
23
24
25
26
27
28
29
30
31
32
269,742,834 62,591,094 33
FERC FORM NO. I (ED. 12-89) Page 201
Name of Respondent
Avista Corporation
ep I This Rort Is: I (1) An Original

(2) flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106)
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)
Line
No
Account
(a)
Balance Beginning of Year
(b)
Additions
(c)
1 1. INTANGIBLE PLANT
2 (301) Organization
3 ,(302) Franchises and Consents 44,651,922
4 (303) Miscellaneous Intangible Plant 4,288,270 1,241,064
5 TOTAL Intangible Plant (Enter Total of lines 2, 3, and 4) I 48,940,1921 1,241,0641
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 (310) Land and Land Rights 2,230,395 1,257,9061
9 (311) Structures and Improvements 125,680,440 543,106
Boiler Plant Equipment 162,508,052 2,464,583
(313) Engines and Engine-Driven Generators
E
6,770
(314)Turbogenerator Units
13
(312)
51,256,394 1,093,319
(315) Accessory Electric Equipment 670,237

27,093,815
(316) Misc. Power Plant Equipment 15,902,0211 42,254
15 (317) Asset Retirement Costs for Steam Production 585,275
16 TOTAL Steam Production Plant (Enter Total of lines 8 thru 15) 385,263,162 6,071,405
17 B. Nuclear Production Plant
18 (320) Land and Land Rights 7 19 (321) Structures and Improvements
20 (322) Reactor Plant Equipment
21 (323) Turbogenerator Units
22 (324) Accessory Electric Equipment
23 (325) Misc. Power Plant Equipment
24 (326) Asset Retirement Costs for Nuclear Production
25 TOTAL Nuclear Production Plant (Enter Total of lines 18 thru 24)
26 C. Hydraulic Production Plant
27 (330) Land and Land Rights 57,332,232 1,251,728
28 (331) Structures and Improvements 43,273,610 1,011,269
29 (332) Reservoirs, Dams, and Waterways 122,714,977 786,507
30 (333) Water Wheels, Turbines, and Generators 155,527,371 7,791,074
31 (334) Accessory Electric Equipment 33,962,255 49,35
32 (335) Misc. Power PLant Equipment 8,036,326 91,016
33 (336) Roads, Railroads, and Bridges 1,999,563 21,193
34 (337) Asset Retirement Costs for Hydraulic Production
35 TOTAL Hydraulic Production Plant (Enter Total of lines 27 thru 34) 422,846,334 11,002.138
36 D. Other Production Plant
37 (340) Land and Land Rights 905,167
38 (3 1) Structures and Improvements 16,487,922 93,638
39 (342) Fuel Holders, Products, and Accessories 21,163,536 5,442
40 (343) Prime Movers 21,876,781 1,843,247
41 (344) Generators 196,822,105 4,289,082
42 (345) Accessory Electric Equipment 16,928,460 205,367
43 (346) Misc. Power Plant Equipment 1,625,721 138,176
44 (347) Asset Retirement Costs for Other Production 351,683
45 TOTAL Other Prod. Plant (Enter Total of lines 37 thru 44) 276161,375 6,574,952
46 TOTAL Prod. Plant (Enter Total of lines 16, 25, 35, and 45) 1,084,270,871 . 23,648,495
FERC FORM NO. I (REV. 12-05) Page 204
Name of Respondent
Avista Corporation
This Report Is:
[]A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
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 comprisirtg 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
Retirements
(d)
Adjustments
(e)
Transfers Balance at
End r)Year
Line
44,651,922 3
519,618 5,009,7161 4
519,6181 im 0 I
1 M I
1 49,661,6381 M
I 3,488,301
.
6
7
8
2,539 126,221,007 9
936,177 164,036,458 10
6,770 11
22,114 52,327,599 12
1,601 ,785 26,162,267 13
2,914 15,941,361 14
585,275 15
2,565,529
___
388,769,038
______________________
16
17
18
___ ______________________ 19
___ ________________________ 20
21
22
23
24
-632,879 57,951,081
25
26
27
16,405 44,268,474 28
632,879 124,134,363 29
266,410 -7,554 163,044,481 30
6,648 7,554 34,012,512 31
8,127,342 32
2,020,756 33
34
289,463 ' 433,559,009
905,167
35
36
37
16,581,560 38
21,168,978 39
31,469 23,688,559 40
2,248,555 198,862,632 41
21,829 17,111,998 42
44,370 1,719,527 43
351,683 44
2,346,223 280,390,104 45
5,201,215 1,102,718,151 46
FERC FORM NO. 1 (REV. 12-05) Page 205
Name of Respondent
Avista Corporation
This Re ort Is:
AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 20121Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102,1)3 and 106) (Continued) -
No
in e,
(a)
Balance
Beginning of Year
(b)
Additions
(C)
47 3. TRANSMISSION PLANT
48 (350) Land and Land Rights 19,251651 -520,364
49 ,(352) Structures and Improvements 16,777,512 388,452
50 (353) Station Equipment 203,280,704 10,655,521
51 (354) Towers and Fixtures 17,120,820 2,11
52 355) Poles and Fixtures 145,612,293 9,529,78
53 356) Overhead Conductors and Devices 112,615,430 4,196,717
54 (357) Underground Conduit 2,605,488
55 (358) Underground Conductors and Devices 2,330,072
56 59) Roads and Trails 1,872,246
57 (359.1) Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Enter Total of lines 48 thru 57) 521,466,216 24,252,22
59 4. DISTRIBUTION PLANT
60 (36 0) Land and Land Rights 6,437,090 297,9
61 (361) Structures and Improvements 17,668,762 420,7
62 (362) Station Equipment 105,536,110 7,751,957
63 (363) Storage Battery Equipment
64 (364) Poles, Towers, and Fixtures 244,062,954 18,823,738
65 (365) Overhead Conductors and Devices 163,385,669 11,104,061
66 (366) Underground Conduit 82,309,152 3,487,069
67 (367) Underground Conductors and Devices 136,552,448 5,826,387
68 (368) Line Transformers 191,749,400 10,579,855
69 (369) Services 123,632,342 9,205,427
70 (37 0) Meters 47,867798 704,058
71 (371) Installations on Customer Premises
72 (372) Leased Property on Customer Premises
73 (373) Street Lighting and Signal Systems 34,636,469 1,882,383
74 (374) Asset Retirement Costs for Distribution Plant 129,707
75 TOTAL Distribution Plant (Enter Total of lines 60 thru 74) 1,153,967,901 70,083,662
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 (380) Land and Land Rights
78 (381) Structures and Improvements
79 (382)Computer Hardware
(383)Computer Software r (384)Communication Equipment

83
(385)Miscellaneous Regional Transmission and Market Operation Plant
(386)Asset Retirement Costs for Regional Transmission and Market Oper
TOTAL Transmission and Market Operation Plant (Total lines 77 thru 83)
8516. GENERAL PLANT
86 389) Land and Land Rights 385,053
87 390) Structures and Improvements 5,729,823 507,001
88 391) Office Furniture and Equipment 3,250,957 4,985,599
89 (392) Transportation Equipment 16,507,978 1,870,394
90 (3 3) Stores Equipment 395,329
91 (394) Tools, Shop and Garage Equipment 3,198,301 96,267
92 (395) Laboratory Equipment 1,047,345
93 (396) Power Operated Equipment 34,614,512 4,132,769
94 (397) Communication Equipment 43,997,759 4,963,790
95 (398) Miscellaneous Equipment 13,156 17,355
96 SUBTOTAL (Enter Total of lines 86 thru 95) 109,140,213 16573,175
97 (399) Other Tangible Property
98 (399.1) Asset Retirement Costs for General Plant
99 TOTAL General Plant (Enter Total of lines 96, 97 and 98) 109,140,213 16,573,175
100 TOTAL (Accounts 101 and 106) 2,917,785,393 135,798,621
101 (102) Electric Plant Purchased (See Instr. 8)
102 (Less) (102) Electric Plant Sold (See lnstr. 8)
103 (103) Experimental Plant Unclassified
104 TOTAL Electric Plant in Service (Enter Total of lines 100 thru 103) 2,917,785,393 135,798,621
FERC FORM NO. 1 (REV. 12-05) Page 206
Name of Respondent
Avista Corporation
This Re oiL Is: (1)An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04112/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC PLANT IN SERVICE (Account 101, 102,103 and 106) (Continued)
Retirements
(d)
Adjustments
(e)
Transfers
f)
Balance at
End r)Year
18,731,287
Line
47
48
61,592 17,104,372 49
714,052 213,222,173 50
17,122,931 51
364,024 19,819 154,797,876 52
48,436 3,905 116,767,616 53
2,605,488 54
2,330,072 55
1,872,246 56
57
1,188,104 23,724 544,554,061
6,735,049
58
59
60
119,427 17,970,103 61
1,949,860 111,338,207 62
63
1,551,487 261,335,205 64
738,288 173,751,442 65
118,111 85,678,110 66
730,080 141,648,755 67
3,356,824 198,972,431 68
189,219 132,648,550 69
606,236 47,965,620 70
71
72
133,382 36,385,470 73
129,707 74
9,492,9141 1 1,214,558,649 75
76
77
78
79
80
81
82
83
385,053
84
85
86
387 -7,034 6,229,403 87
366,554 7,870,002 88
769,988 17,608,384 89
395,329 90
108,629 3,185,939 91
127,321 920,024 92
2,705,607 36,041,674 93
106,707 48,854,842 94
30,511 95
4,185,193 -7,034 121,521,161 96
97
98
4,185,193 -7,034 121,521,161 99
20,587,044 16,690 3,033,013,660 100
101
102
103
20,587,044 16,690 3,033,013,660 104
FERC FORM NO. I (REV. 12-05) Page 207
Name of Respondent
Avista Corporation
This Re ort Is: Date of Report
AResubmission 04/12/2013
Year/Period of Report
End of 20121Q4
ELECTRIC PLANT HELD FOR FUTURE USE (Account 105)
1.Report separately each property held for future use at end of the year having an original cost of $250,000 or more. Group other items of property held
for future use.
2.For property having an original cost of $250,000 or more previously used in utility operations, now held for future use, give in column (a), in addition to
other required information, the date that utility use of such property was discontinued, and the date the original cost was transferred to Account 105.
Line No.
-
Description and Location
Of Property (a)
Date Originally Included
in This Account (b)
Date Expected to be used
in Utility Service (c)
Balance at End of Year (d)
1 Land and Rights:
2
3
4 Distribution Plant Land, Spokane, Washington Oct 2008 Unknown 1,623,321
5 Distribution UG Plant Land, Spokane, Washington Dec 2010 Unknown 216,314
6 Transmission Plant Land, Spokane, Washington Dec 2010 Unknown 193,587
7 Transmission Plant Land, Moscow, Idaho March 2011 Unknown 126,640
8 Distribution Plant Land, Spokane, Washington March 2011 Unknown 540,307
9 Distribution Plant Land, Spokane, Washington Oct 2011 Unknown 414,073
10 Transmission Plant Land, Spokane, Washington Dec 2011 Unknown 1,143,033
11 Distribution Plant Land, Spokane, Washington Dec 2011 Unknown 250,489
12 Other Production Plant Land, Spokane, Washington Dec 2011 Unknown 40,896
13 Distribution Plant Land, Deary, Idaho June 2012 Unknown 72,367
14 Transmission Plant Land, Thornton, Washington Aug 2012 Unknown 1,383
15 Distribution Plant Land, Spokane, Washington Oct 2012 Unknown 151,381
16
17
18
19
20
21 Other Property:
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
471 Total 4,773,791
FERC FORM NO. 1 (ED. 12-96) Page 214
Name of Respondent
Avista Corporation
This Re ort Is:
[]A Resubmission
I Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
CONSTRUCTION WORK IN PROGRESS - - 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.
Line
No
Description of Project
(a)
Construction work in progress -
Electric (Account 107)
(b)
1 Clark Fork Implementation PME Agreement 11,710,072
2 Nine Mile Redevelopment 10,630,643
3 Moscow 230kV Sub - Rebuild 230kV Yard 7,976,641
4 Transportation Equipment 5,832,360
5 CS2 LISA Capital Add 5,033,681
6 Post Falls Intake Gare Replacement 4,519,054
7 Spokane River Implementation PME Agreement 4,281,265
8 Little Falls Powerhouse Redevelopment 3,294,285
9 Regulating Hydro 2,699,572
10 High Voltage Protection Upgrade 2,117,502
11 Productivity Initiative 1,917,613
12 Wood Pole Management Program 1,782,756
13 Spokane Smart Circuit 1,780,637
14 Blue Creek ll5kVRebuild 1,140,231
15 Line Ratings Mitigation Project 1,105,744
16 Minor Projects Under $1,000,000 13,322,506
17
18 Research Development and Demonstration:
19 SGDP Pullman Smard Grid Demonstration Project 1,061,124
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43 TOTAL 80,205,686
FERC FORM NO. I (ED. 12-87) Page 216
Name of Respondent
Avista Corporation
This Report Is:
(2) AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
ACCUMULATED PROVISION FOR DEPRECIATION OF ELECTRIC UTILITY PLANT (Account 108)
1.Explain in a footnote any important adjustments during year.
2.Explain in a footnote any difference between the amount for book cost of plant retired, Line 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.
Section A. Balances and Changes During Year
i:iiie
N
item
(a)
Total (c+d+e)
(b)

4ectrtc iant in Service
(C) I Electric i-'iant held for Future Use (d)
Electfic Fnt Leased to utners
(e)
1 Balance Beginning of Year 1,012,217,392 l 1,012,217,3921i
2
3
Depreciation Provisions for Year, Charged to
(403) Depreciation Expense
4
-
(403.1) Depreciation Expense for Asset
Retirement Costs
74,527,789 74,527,789
5 (413) Exp. of Elec. Pit. Leas. to Others
1,106,87 _6 Transportation Expenses-Clearing 1,106,873
1
7 Other Clearing Accounts
_8 Other Accounts (Specify, details in footnote): -275,172 -275,172
9
10 TOTAL Deprec. Prov for Year (Enter Total of
lines 3 thru 9)
75,359,490 75,359,490
11 Net Charges for Plant Retired:
20,061843 20,061,843 12 Book Cost of Plant Retired
13 Cost of Removal 1,075,876 1,075,876
14 Salvage (Credit) 972,119 972,119
15 TOTAL Net Chrgs. for Plant Ret. (Enter Total
of lines 12 thru 14)
20,165,600 20,165,600
16 Other Debit or Cr. Items (Describe, details in
footnote):
-2,379,264 -2,379,264
17
18 Book Cost or Asset Retirement Costs Retired
19 Balance End of Year (Enter Totals of lines 1,
10, 15, 16, and 18)
1,065,032,018 1,065,032,018
- Section B. Balances at End of Year According to Functional Classification
20 Steam Production 272,295,483 272,295,483
21 Nuclear Production
22 Hydraulic Production-Conventional 115,896,200 115,896,200
23 Hydraulic Production-Pumped Storage
24 Other Production 76,241,054 76,241054
25 Transmission 183,292,936 183,292,936
26 Distribution 368,105,672 368,105,672
27 Regional Transmission and Market Operation
28 General 49,200,673 49,200,673
29 TOTAL (Enter Total of lines 20 thru 28) 1,065,032,018 1,065,032,018
FERC FORM NO. I (REV. 12-05) Page 219
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Rort Is: ep
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1)
1. Report below investments in Accounts 123. 1, investments in Subsidiary Companies.
2. Provide a subheading for each company and List there under the information called for below. Sub - TOTAL by company and give a TOTAL in
columns (e),(f),(g) and (h)
(a)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.
Line
No
Description of Investment
(a)
Date Acquired
(b)
Date Of MaLrity
Amount of Jnvestment at
Beginning of Year
2 Avista Capital - Common Stock 1997 170,053,827
3 Avista Capital - Equity in Earnings -101,447,380
4 OCI Investment in Subs 134,045
5 Avista Capital - Other Changes in Net Investment 3,230,876
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 1 ITotal Cost of Account 123.1 $ O TOTAL 71,971,368
FERC FORM NO. 1 (ED. 12-89) Page 224
Name of Respondent
Avista Corporation
This Re ort Is:
(2) E] A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
INVESTMENTS IN SUBSIDIARY COMPANIES (Account 123.1) (Continued)
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
Equity in Subsidiary
EarninsDf Year
Revenues for Year
f)
Amount of Investment at
End r)Year
Gain or Loss from Investment
DisPsd of Line
46,675,006 216,728,833 2
-1,206,861 -102,654,241 3
33,216 167,261 4
1,241,694 4,472,570 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
-1,206,861 47,949916 118,714,423
FERC FORM NO. I (ED. 12-89) Page 226
Name of Respondent
Avista Corporation
This Re ort Is:
(2) [:]A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
MATERIALS AND SUPPLIES
1.For Account 154, report the amount of plant materials and operating supplies under the primary functional classifications as indicated in column (a);
estimates of amounts by 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.
Line
No.
-
Account
(a)
Balance
Beginning of Year
(b)
Balance
End of Year
(c)
Department or
Departments which
Use Material (d)
1 Fuel Stock (Account 151) 4,248,389 4120 767 (1)
2 Fuel Stock Expenses Undistributed (Account 152)
3 Residuals and Extracted Products (Account 153)
4 Plant Materials and Operating Supplies (Account 154)
5 Assigned to Construction (Estimated) 15450 514 16046 143 (1)
6 Assigned to - Operations and Maintenance
7 Production Plant (Estimated) 2,354,732 2,645,483 (1)
8 Transmission Plant (Estimated) 48,245 54,922 (1)
9 Distribution Plant (Estimated) 216,491 264,561 (1)
10 Regional Transmission and Market Operation Plant
(Estimated)
11 Assigned to Other (provide details in footnote) 3,676,223 4 864288 (1),(2)
12 TOTAL Account 154 (Enter Total of lines Sthru 11) 21746,205 23,875,397
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
20 TOTAL Materials and Supplies (Per Balance Sheet) 25,994,594 27,996,164
FERC FORM NO. I (REV. 12-05) Page 227
Schedule Page: 227 Line No.: I Column: d
(1)Electric
(2)Gas
Schedule Page: 227 Line No.: 5 Column: d
Footnote Linked. See note on 227, Row: 1, col/item:
ISchedule Page: 227 Line No.: 7 Column: d I
Footnote Linked. See note on 227, Row: 1, col/item:
Schedule Page: 227 Line No.: 8 Column: d I
Footnote Linked. See note on 227, Row: 1, col/item:
ISchedule Page: 227 Line No.: 9 Column: d I
Footnote Linked. See note on 227, Row: 1, col/item:
lSchedule Page: 227 Line No.: II Column: d I
Footnote Linked. See note on 227, Row: 1, cal/item:
Name of Respondent
Avista Corporation
This Re ort Is:
(2)E] A Resubmission
Date of Report
(M 3
04/12/201
Year/Period of Report
End of 2012/Q4
Transmission Service and Generation Interconnection Study Costs
1.Report the particulars (details) called for concerning the costs incurred and the reimbursements received for performing transmission service and
generator interconnection studies.
2.List each study separately.
3.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.
Line
N0.
-
Description
(a)
Costs Incurred During
Period
(b)
Account Charged
(c)
Reimbursements
Received During the Period
(d)
Account Credited
With Reimbursement
(e)
1 Transmission Studies
186200 2 Lancaster L&L Interconnect 24,709
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21 Generation Studies
AVA Noxon Upgrade 40,214 186200 22
23 AVA Nine Mile Upgrade 209 186200
24 Rattlesnake Flat Interconnect 9,347 186200
25 Horizon Wind Interconnect 61,845 186200
26 Nighthawk LLC Interconnect 3,914 186200
27 Palouse Wind Phase II 110 186200
28 Deep Creek Hydro Interconnect 327 186200
29
30
31
32
33
34
35
36
37
38
39
40
FERC FORM NO. 1/1-F13-Q (NEW. 03-07) Page 231
Schedule Page: 231 Line No.: 2 Column: a I
Total charges incurred life to date.
[Schedule Page: 231 Line No.: 22 Column: a
Total charges incurred life to date.
[Schedule Page: 231 Line No.: 23 Column: a I
Total charges incurred life to date.
lSchedule Page: 231 Line No.: 24 Column: a I
Total charges incurred life to date.
[Schedule Page: 231 Line No.: 25 Column: a I
Total charges incurred life to date.
[Schedule Page: 231 Line No.: 26 Column: a
Total charges incurred life to date.
[Schedule Page: 231 Line No.: 27 Column: a I
Total charges incurred life to date.
lSchedule Page: 231 Line No.: 28 Column: a I
Total charqes incurred life to date.
Name of Respondent
Avista Corporation
This Re ort Is:
(2) F]A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
OTHER REGULATORY ASSETS (Account 182.3)
1.Report below the particulars (details) called for concerning other regulatory assets, including rate order docket number, if applicable.
2.Minor items (5% of the Balance in Account 182.3 at end of period, or amounts less than $100,000 which ever is less), may be grouped
by classes.
3.For Regulatory Assets being amortized, show period of amortization.
Line
No.
Description and Purpose of
Other Regulatory Assets
(a)
Balance at Beginning
of Current
QuarterfYear
(b)
Debits
(c)
CREDITS Balance at end of
Current QuarterlYear
(f)
Written off During the
Quarter !Year Account
Charged (d)
Written off During
the Period Amount
(e)
1 Regulatory Asset FAS 106 472,752 407 472,752
2 Reg Asset Post Ret Liab 260,358,633 46,049,036 306,407,669
3 Regulatory Asset FASI09 Utility Plant 70,616,515 283 5,151,910 65,464,605
4 Regulatory Asset Lancaster Generation 5,326,667 407 1,360,000 3966,667
5 Regulatory Asset FAS109 DSIT Non Plant 1,762,314 283 97,548 1,664,766
6 1 Regulatory Asset FAS109 DFIT State Tax Cr 6,669,689 794,495 7,464,184
7 Regulatory Asset FAS109 WNP3 5,653,819 283 737,482 4,916,337
8 Regulatory Asset Roseburg/Medford 142,470 122,541 265,011
9 Regulatory Asset- Spokane River Relicense 701,098 407 78,736 622,362
10 Regulatory Asset- Spokane River PM&E 649,198 557 73,312 575,886
111 Regulatory Asset- Lake CDA Fund 9,648,664 407 211,065 9,437,599
12 Regulatory Asset- Lake CDA IPA Fund 2,000,000 2,000,000
13 Reg Assets- Decouplings Surcharge 190,282 407 182,958 7,324
14 Regulatory Asset ID DSIT Amort 70,934 407 70,934
15 Regulatory Asset RIO Deposits- ID
161 Regulatory Asset BPA Residential Exchange 104,636 436,169 540,805
17 Regulatory Asset ERM Approved
18 Regulatory Asset- CNC Transmission 735,906 407 252,637 483,269
19 DEF CS2 & COLSIRIP 143,226 6,685,420 407 516,251 6,312,395
20 LiDAR O&M REG DEF 337,879 249,379 587,258
21 ID Wind Gen AFUDC 358,264 11,109 369,373
22 Regulatory Asset Wartsila Units 1,089,605 407 337,788 751,817
23 MTM St Regulatory Asset 69,684,643 244 34,603,118 35,081,525
24 MTM Lt Regulatory Asset 40,345,338 244 15,127,641 25,217,697
25 Regulatory Asset FAS143 Asset Retirement Obligation 2,717,489 230 318,644 2,398,845
26 Reg Asset AN- CDA Lake Settlement 39,186,540 407 1,559,332 37,627,208
27 Reg Asset WA-CDA Lake Settlement 1,356,388 407 152,118 1,204,270
28 Regulatory Asset Workers Comp 2,623,100 242 344,422 2,278,678
29 CS2 Lev Ret 1,250,099 407 340,600 909,499
30 Regulatory Asset ID PCA Deferral 2 2,017,929 557 2,017,929
31 1 Regulatory Asset ID PCA Deferral 3 ( 2,762,169) 2,762,168 -1
32 DSM Asset 798,418 2,578,599 242 798,418 2,578,599
33 SWAPS ON FMBS 40,697,807 254 40,697,807
34
35
36
37
38
39
40
41
42
43
44

TOTAL: 524,250,326 100,386,723 64,805,595 559,831,454
FERC FORM NO. 1!3-Q (REV. 02-04) Page 232
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Re ort Is: (1)An Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/1212013
Year/Period of Report
End of 2012/Q4
MISCELLANEOUS DEFFERED DEBITS (Account 186)
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) maybe grouped by
classes.
Line
No.
-
Description of Miscellaneous
Deferred Debits
(a)
Balance at
Beginning of Year
(b)
Debits
(c)
CREDITS Balance at
End of Year
(f)
--Account-
Chared
(d?
Amount
(e)
2 Colstrip Common Fac. 1,110,999 1,110,999
31 Regulatory Asset-Decoupling def -19,852 19,852
4
5 Regulatory Asset-Mt lease pym 1,713,249 540 360,684 1352,565
6 Regulatory Asset-Mt lease pymt 3,383,112 540 676,632 2,706,480
7 Colstrip Common Fac. 2,355,642 2,355,642
8 Prepaid airplane Lease LT 466,025 931 147,166 318,859
91 Misc DD- airplane lease 90,181 12,556 102,737
10 Plant Allocation of clearing jr 1,140,273 2,444,223 3,584,496
11 Misc DD- IR Swaps 18,895,143 245 18,895,143
12 Misc Error Suspense 5,225 var 342,205 -336,980
13 Renewable Energy-Cert Fees 174,000 557 9,156 164,844
14 Nez Perce Settlement 165,961 557 5,212 160,749
151 Long Term Note Rec acct 209,469 143 204,050 5,419
161 Reg Asset ID-Lake CdaI 271 ,030 506 30,974 240,056
17 Misc Deffered debits/WA REC DEF var 277,010 -277,010
18 ID Panhandle Forest Use Permit 181,017 181,017
19 Credit Union Labor and Exp 25,762 9,248 35,010
20 Outdoor Lghtng Greenbelt Pathwy 65,248 32,979 98,227
21 Horizon Wind Interco 61,845 61,845
221 Insurance Recvy CDA Lake 320,932 var 320,932
23 KF Water Rights Supply 1,179,357 310 1,178,588 769
24 Reclass Idaho CIk Fork Relic 452,846 537 265,896 186,950
25 Reclass misc def debits 357,784 357,784
26 Misc Work Orders <$50,000 -149,432 275,641 126,209
27 Subsidiary Billings 42,452 135,814 178,266
28 "Null" Projects directly to 186 15,197 15,197
29 Conservation
30 Regulatory Assets Consv -200 200
31 Regulatory Assets Consv 1,845,898 var 185,185 1,660,713
32
33 Optional Wind Power 909 186,231 -186,231
_4
36 Misc Deffered Debits/Res Acctg 1,577,531 1,577,531
37 Deff Palouse Wind %ThorntonSW 557 80,774 -80,774
38
39
40
4
42
43
44
45
46
L
47 Misc. Work in Progress
Deferred Regulatory Comm.
Expenses (See pages 350-351)
49 TOTAL 34,001 37A 15,701,369
FERC FORM NO. I (ED. 12-94) Page 233
Name of Respondent
Avista Corporation
This Rort Is: ep
(1)An Original
(2)A Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
ACCUMULATED DEFERRED INCOME TAXES (Account 190)
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.
Line
No
Description and Location
(a)
Balanceof Begining of Year
(b)
Balance at End of Year
(c)
1 Electric
2 9,302,194 6,261,068
3
4
5
6
7 Other
8 TOTAL Electric (Enter Total of lines 2 thru 7) 9,302,1941 6,261,068
9 Gas
10 1,056,690 2,161,932
11
12
13
14
15 Other -
16 TOTAL Gas (Enter Total of lines 10thru 15 1,056,690 2,161,932
17 Other 143,049,536 140,002,469
181 TOTAL (Acct 190) (Total of lines 8, 16 and 17) 153,408,420 148,425,469
Notes
FERC FORM NO. 1 (ED. 12-88) Page 234
Name of Respondent
Avista Corporation
This Report Is:
(2) AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
CAPITAL STOCKS (Account 201 and 204)
1.Report below the particulars (details) called for concerning common and preferred stock at end of year, distinguishing separate
series of any general class. Show separate totals for common and preferred stock. 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.
Line
No.
-
Class and Series of Stock and
Name of Stock Series
(a)
Number of shares
Authorized by Charter
(b)
Par or Stated
Value per share
(C)
Call Price at
End of Year
(d)
1 Account 201 - Common Stock Issued
2 No Par Value 200,000,000
3 Restricted shares
4 Total Common 200,000,000
6
7 Account 204 - Preferred Stock Issued 10,000,000
8
9
10 Cumulative
11
12
13 Total Preferred 10,000,000
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. I (ED. 12-91) Page 250
Name of Respondent
Avista Corporation
This Report Is:
(1)MAn Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
CAPITAL STOCKS (Account 201 and 204) (Continued)
3.Give particulars (details) concerning shares of any class and series of stock authorized to be issued by a regulatory commission
which have not yet been issued.
4.The identification of each class of preferred stock should show the dividend rate and whether the dividends are cumulative or
non-cumulative.
5.State in a footnote if any capital stock which has been nominally issued is nominally outstanding at end of year.
Give particulars (details) in column (a) of any nominally issued capital stock, reacquired stock, or stock in sinking and other funds which
is pledged, stating name of pledgee and purposes of pledge.
OUTSTANDING PER BALANCE SHEET (Total amount outstanding without reduction
for amounts held by respondent)
HELD BY RESPONDENT Line
No. AS REACQUIRED STOCK (Account 217) IN SINKING AND OTHER FUNDS
Shares (e) Amount (f) Shares
(g)
Cost (h) Shares (i) Amount
0) -
59,812,796 863,316,222 117,118 3,025,158 2
3
59,812 ,796 863,316,222 117,118 3,025,158 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. I (ED. 12-88) Page 251
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Report Is:
[]A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 20121Q4
OTHER PAID-IN CAPITAL (Accounts 208-211, inc.)
Report below the balance at the end of the year and the information specified below for the respective other paid-in capital accounts. Provide a
subheading for each account and show a total for the account, as well as total of all accounts for reconciliation with balance sheet, Page 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.
Llne lejn Arunt
1 Equity transactions of subsidiaries 10,942,942
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 TOTAL 10,942,942
FERC FORM NO. I (ED. 12-87) Page 253
Name of Respondent
Avista Corporation
This Re ort Is: On Original
(2) E]A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
CAPITAL STOCK EXPENSE (Account 214)
1.Report the balance at end of the year of discount on capital stock for each class and series of capital stock.
2.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.
Line
No.
Class and Series of Stock
(a)
Balance at End of Year
(b)
1 Common Stock - no par -14977,565
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22 TOTAL -14,977565
FERC FORM NO. I (ED. 12-87) Page 254b
IcheduIe Page: 254 Line No.: I Column: b
Capital Stock expense activity, 2012
Beginning Balance: $(11,086,811)
Issuance of Common Stock: 558,210
Tax Benefit - Options Exercised: 34,614
Excess Tax Benefits on Stock Comp: 1,230,724
Stock compensation accrual: (5,714,302)
Ending Balance: $(14,977,565)
Name of Respondent
Avista Corporation
This Re ort Is:
AResubmission
Date of Report Year/Period of Report
End of 2012/04
LONG-TERM DEBT (Account 221, 222, 223 and 224)
1.Report by balance sheet account the particulars (details) concerning long-term debt included in Accounts 221, Bonds, 222,
Reacquired Bonds, 223, Advances from Associated Companies, and 224, Other long-Term Debt.
2.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 (0). The expenses, premium or discount should not be netted.
9.Furnish in a footnote particulars (details) regarding the treatment of unamortized debt expense, premium or discount associated with
issues redeemed during the year. Also, give in a footnote the date of the Commission's authorization of treatment other than as
specified by the Uniform System of Accounts.
Line
No.
-
Class and Series of Obligation, Coupon Rate
(For new issue, give commission Authorization numbers and dates)
(a)
Principal Amount
Of Debt issued
(b)
Total expense,
Premium or Discount
(c)
1 FMBS - SERIES A - 7.53% DUE 05/05/2023 5,500,000 42,712
2 FMBS - SERIES A - 7.54% DUE 5/05/2023 1,000,000 7,766
3 FMBS - SERIES A - 7.39% DUE 5/11/2018 7,000,000 54,364
4 FMBS - SERIES A - 7.45% DUE 6/11/2018 15,500,000 170,597
5 FMBS - SERIES A - 7.18% DUE 8/11/2023 7,000,000 54,364
6 ADVANCE ASSOCIATED AVISTA CAPITAL II (T0PRS) 51,547,000 1,296,086
7 FMBS - 6.37% SERIES C 25,000000 158,304
8 FMBS - 5.45% SERIES 90,000,000 1,432,081
9 FMBS - 6.25% SERIES 150,000,000 2,180,435
10 FMBS - 5.70% SERIES, 150,000,000 4,924,304
11 FMBS - 5.95% SERIES 250,000,000 3,081,419
12 FMBS - 5.125% SERIES 250,000,000 2,859,788
13 COLSTRIP 2010A PCRBs DUE 2032 66,700,000
14 COLSTRIP 2010B PCRBs DUE 2034 17000 000
15 FMBS - 1.68% SERIES 50,000,000 305,790
16 FMBS - 3.89% SERIES 52,000,000 383,338
17 FMBS - 5.55% SERIES 35,000,000 258,834
18
19 SERIES C SET UP 666,169
20 4.45% SERIES DUE 12-14-2041 85,000,000 692,722
21 4.23% SERIES DUE 11-29-2047 80,000,000 725,635
22 KETTLE FALLS P C REV BONDS DUE 14 4,100,000
23 FMBS - SERIES A - 7.37% DUE 5/10/2012 7,000,000
24
25
26
27
28
29
30
31
32
33 TOTAL 1,399,347,000 19,294,708
FERC FORM NO. 1 (ED. 12-96) Page 256
Name of Respondent
Avista Corporation
This Re oil Is:
2ssion
Date of Report Year/Period of Report
End of 201 2/Q4
LONG-TERM DEBT (Account 221, 222, 223 and 224) (Continued)
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.
Nominal Date
of Issue
(d)
Date of
Maturity
(e)
AMORTIZATION PERIOD Outstanding (Total amount outstanding without
reductIono;pam:eus held by r
?)
Interest for Year
Amount
(i)
Line
N
-
Date From
(f)
Date To
(9)
05-06-1993 05-05-2023 05-06-1993 05-05-2023 5,500,000 414,150 1
05-07-1993 05-05-2023 05-07-1993 05-05-2023 1,000,000 75,400 2
05-11-1993 05-11-2018 05-11-1993 05-11-2018 7,000,000 517,300 3
06-09-1993 06-11-2018 06-09-1993 06-11-2018 15,500,000 1,154,750 4
08-12-1993 08-11-2023 08-12-1993 08-11-2023 7,000,000 502,600 5
06-03-1997 06-01-2037 06-03-1997 06-01-2037 51547,000 541,503 6
06-19-1998 06-19-2028 06-19-1998 06-19-2028 25,000,000 1,592,500 7
11-18-2004 12-01-2019 11-18-2004 12-01-2019 90,000,000 4,905,000 8
11-17-2005 12-01-2035 11-17-2005 12-01-2035 150,000,000 9,375,000 9
12-15-2006 07-01-2037 12-15-2006 07-01-2037 150,000,000 8,550,000 10
04-02-2008 06-01-2018 04-02-2008 06-01-2018 250,000,000 14,875000 11
09-22-2009 04-01-2022 09-22-2009 04-01-2022 250,000,000 12,812,500 12
12-15-2010 10-1-2032 12-15-2010 10-1-2032 66,700,000 309,043 13
12-15-2010 3-1-2034 12-15-2010 3-1-2034 17,000,000 78,766 14
12-30-2010 12-30-2013 12-30-2010 12-30-2013 50,000,000 840,000 15
12-20-2010 12-20-2020 12-20-2010 12-20-2020 52,000,000 2,022,800 16
12-20-2010 12-20-2040 12-20-2010 12-20-2040 35,000,000 1,942,500 17
18
6-15-1998 6-15-2013 6-15-1998 6-15-2013 19
12-14-2011 12-14-2041 12-14-2011 12-14-2041 85,000,000 3,782,500 20
11-30-2012 11-29-2047 11-30-2012 11-29-2047 80,000,000 291,400 21
7-29-1993 12-01-2023 7-29-1993 12-01-2023 120,950 22
5-10-1993 5-10-2012 05-10-1993 05-10-2012 214,958 23
24
25
26
27
28
29
30
31
32
1,388,247,000 64,918,620 33
FERC FORM NO. I (ED. 12-96) Page 257
ISchedule Page: 256 Line No.: 6 Column: a I
Upon issuance Avista Capital II isued $1.5 million of Common Trust Securities to the Company. In December
2000, the Company purchased $10.0 million of these Preferred Trust Securities. The interest for the year
disclosed in column (i)reflects the net amount of interest owed to third parties.
ISchedule Page: 256 Line No.: 13 Column: b
The Company reacquired this debt in 2010. These bonds have not been retired or canceled; the Company plans, based on
liquidity needs and market conditions, to remarket these bonds at a future date.
Schedule Page: 256 Line No.: 13 Column: c
The Company reaquired these bonds in 2010.
ISchedule Page: 256 Line No.: 14 Column: b I
The Company reacquired this debt in 2010. These bonds have not been retired or canceled; the Company plans, based on
liquidity needs and market conditions, to remarket these bonds at a future date.
chedule Page: 256 Line No.: 14 Column: c I
The Company reaquired these bonds in 2010.
[Schedule Page: 256 Line No.: 21 Column: a I
The new issuance is based on the followinq state commission orders:
1.Order of the Washington Utilities and Transportation Commission entered July 13, 2011, as
amended on August 24, 2011 in Docket No. U-Ill 176;
2.Order of the Idaho Public Utilities Commission, Order No. 32338, entered August 25, 2011;
3.Order of the Public Utility Commission of Oregon, Order No. 11334, entered August 26, 2011;
Order of the Public Service Commission of the State of Montana, Default Order No. 4535
ISchedule Page: 256 Line No.: 21 Column: c
Expenses may change as invoices related to this issuance become known.
Name of Respondent
Avista Corporation
This Report Is: (1)MAn Original
(2)flA Resubmission
Date of Report
(MO, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
RECONCILIATION OF REPORTED NET INCOME WITH TAXABLE INCOME FOR FEDERAL INCOME TAXES
1.Report the reconciliation of reported net income for the year with taxable income used in computing Federal income tax accruals and show
computation of such tax accruals. 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.
Line
No.
Particulars (Details)
(a)
Amount
(b)
1 Net Income for the Year (Page 117) 78,210,066
2
3
4 Taxable Income Not Reported on Books
3,398,971
6
7
8
9 Deductions Recorded on Books Not Deducted for Return
124,136,767
11
12
13
14 Income Recorded on Books Not Included in Return
14,239,687
16
17
18
19 Deductions on Return Not Charged Against Book Income
20 -205,058,564
21
22
23
24
25
26
27 Federal Tax Net Income 61,262,765
28 Show Computation of Tax:
29 State Tax 379,911
30 Federal Tax Net Income less state tax 61,642,676
31
32 Federal Tax @ 35% 21,574,937
33
34 Prior Year & Misc True Ups -8,077,924
35 Cabinet Gorge Tax Credits -200,441
36 Total Federal Expense 13,311,067
37
38
39
40
41
42
43
44
FERC FORM NO. 1 (ED. 12-96) Page 261
Name of Respondent
Avista Corporation
This Re ort Is:
(1)An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1.Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. 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.
Line
No.
-
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR Charged Dtirit-j Year (d)
I PdS
Durinn Year
(e)
Adjust-
ments
(f)
Taxes Accrued (Account 236) (b)
Prepaid Taxes (Include in Account 165)
(c)
1 FEDERAL:
2 Income Tax 2009 -118,190 -118,190
3 Income Tax 2010 142,150 6,913,541 1,370,785 -6,552,932
4 Income Tax 20ll -9,963,974 -2,571,551 -11,352,573 5,321,340
5 Income Tax (Current) 16,441,880 15012,803
6 Retained Earnings
7 Prior Retained Earnings -1,392,676
8 Prior Retained Earnings -3,302,066 1,231,592
9 Current Retained Earnings -1994,624
10 Total Federal -14,634,756 18,789,246 4,912,825
11
12 STATE OF WASHINGTON:
13 Property Tax (2010) -3,193 -8 660 3,861
14 Property Tax (2011) 9,704,000 171,510 9,871,649 -3,861
15 Property Tax (2012) 10,622,012
16 Excise Tax (2010) -22,495
17 Excise Tax (2011) 2,585,031 -17,932 2,567,100
18 Excise Tax (2012) 24,039,256 21,712,032
19 Natural Gas Use Tax 12,729 10,947 14,885 -8,181
20 Municipal Occupation Tax 3,123,004 22,227,744 22,808,413
21 Sales & Use Tax (2006) -8,173
221 Sales & Use Tax (2011) 186,525 186,514
23 Sales & Use Tax (2012) 566,682 511,779
24 Motor Vehicle Tax (2012) 5,473 5,473
25 Total Washington 15,577,428 57,625,684 57,678,505 8,181
26
271 STATE OF IDAHO:
28 Income Tax (2010) -4,633
29 Income Tax (2011) 258,945 -129,632 -6,327
30 Income Tax (2012) 377,042 400,000
31 Property Tax (2009) 1,647 -1,640 7
32 Property Tax (2010) -3,870 3,870
33 Property Tax (2011) 2,631,938 -36,462 2,595,476
34 Property Tax (2012) 6,179,245 2,902,249
35 Motor Vehicle Tax (2012) 570 570
36 Sales & Use Tax (2005) 436
371 Sales & Use Tax (2011) 42,032 42,032
38 Sales& Use Tax (2012) 134,186 132,017
39 Irrigation Credits (2011)
40 KWH Tax (2010) 1 1 2
41 TOTAL 8,292,344 103,605,888 89,588,591 -1
FERC FORM NO I (ED. 12-96) Page 262
Name of Respondent
Avista Corporation
This Re ort Is:
AResubrnission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
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 (I) 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 (I) 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 (I) the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued
Account 236) (g)
Prepaid Taxes
(Incl. in Account 165) (h)
Electric (Account 408.1, 409.1)
(i)
Extraordinary Items
(Account 409.3) (j)
Adjustments to Ret.
Earnings (Account 439)
(k)
Other
(I)
No.
-
2
-868,026 -73,728 6,987,269 3
4,138,388 -1,292,964 -1,278,587 4
1,429,077 19,284,594 -2,842,713 5
6
-1,392,676 7
-2,070,474 8
-1,994,624 -1,994,624 9
-758,335 17,917,902 871,345 10
11
12
-8 13
145,116 26,394 14
10,622,012 8,493,012 2,129,000 15
-22,495 16
-20,384 2,452 17
2,327,224 18,386,314 5,652942 18
610 3,578 7,369 19
2,542,334 16,405,423 5,822,321 20
-8,173 21
12 22
54,903 566,682 23
5,473 24
15,516,427 43,413,059 14,212,625 25
26
27
-4,633 28
135,640 -103,706 -25,926 29
-22,958 388,842 -11,800 30
-1,640 31
4,316 -446 32
-76,485 40,023 33
3,276,997 5,064,040 1,115,205 34
570 35
436 36
37
2,169 134,186 38
39
1
22,309642 80567,923 23,037,967 41
FERC FORM NO. I (ED. 12-96) Page 263
Name of Respondent
Avista Corporation
This Re ort Is: On Original
(2) LIA Resubmission
Date of Report
- 04/12/2013
Year/Period of Report
End of 2012/04
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1.Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. 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.
Line
No.
-
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR Charged fliirjicI Year (d)
Il )(S aid Durinci Year (e)
Adjust-
ments
(f)
Taxes Accrued (Account 236)
(b)
Prepaid Taxes (Include in Account 165)
(c)
1 KWH Tax (2011) 20,705 264 20,969
2 KWH Tax (2012) 399,680 364,000
3 Franchise Tax (2010) -15,507 15,507
4 Franchise Tax (2011) 1,629,882 1,614,375 -15,507
5 Franchise Tax (2012) 4318,446 2,837,684
6 Total Idaho 4,561,576 11,245,570 10,903054
7
8 STATE OF MONTANA:
9 Income Tax (2010) -171,969 -179,683
10 Income Tax (2011) 489,040 -99,269
11 Income Tax (2012) 252,779 225,000
12 Property Tax (2011) 3,454,233 965 3,455,198
13 Property Tax (2012) . 7,219,743 3,619,369
14 Colstrip Generation Tax 3,048 3,048
15 KWH Tax (2011) 267,607 267,608
16 KWH Tax (2012) 1,137,780 858,252
171 Motor Vehicle Tax (2012) 1,819 1,819
18 Consumer Council Tax 6 50 21
19 Public Commission Tax 10 138 35
20 Total Montana 4,038,927 8,517,053 8,250,667
21
221 STATE OF OREGON:
23 Income Tax (2007) -230,262 230,262
24 Income Tax (2010) 91,318 -230,262
25 Income Tax (2011) 386,749 -379,351
26 Income Tax (2012) 356,742 125,000
27 Property Tax (2010) -1,791,031 1,894,942 -103,911
2 Property Tax (2011) -95,501 1,973,371 1,927,159 49,289
29 Property Tax (2012) 2,030,655 54,622
30 Motor Vehicle Tax (2012) 2,057 2,057
31 BETC Credit (2010 and Prior) 1,448
32 BETC Credit (2011) -365,909
331 BETC Credit (2012) 18,696
34 Glendale Regulatory Cr. 2008 -210,889
35 Glendate Regulatory Cr. 2009 70,289
36 Franchise Tax (2010) 25,602 24,921
37 Franchise Tax (2011) 903,082 876,166
381 Franchise Tax (2012) 3,672,794 2,924,589
39 Total Oregon -1,215,104 7,501,859 7,910,547
40
41 TOTAL 8292,344 103,605888 89,588,591 -1
FERC FORM NO. 1 (ED. 12-96) Page 262.1
Name of Respondent
Avista Corporation
This Re ort Is:
AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
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 (I) 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 (I) 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 (I) the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued
Account 236) (g)
Prepaid Taxes
(Incl. in Account 165)
(h)
Electric (Account 408.1, 409.1)
(I)
Extraordinary Items
(Account 409.3) U)
Adjustments to Ret. Earnings (Account 439)
(k)
Other No
264 1
35,680 399,680 2
3
4
1,480,762 3,150,983 1,167,463 5
4,904,093 8,826,295 2,419,275 6
7
8
7,714 9
389,771 - -99,269 10
27,779 252,779 11
965 12
3,600,374 7,219,743 13
3,048 14
15
279,528 1,137,780 16
1,819 17
34 50 18
113 - 138 19
4,305,313 8,515,234 1,819 20
21
22
23
-138,944 24
7,398 -94,838 -284,513 25
231,742 89,184 267,558 26
1,004,911 890,031 27
896,176 1,077,196 28
-1,976,033 29
2,057 30
1,448 - 31
-365,909 - 32
-18,696 -18,696 33
-210889 34
70,289 35
681 36
26,916 - 37
748,205 - 3,672,794 38
-1,623,792 1,895,433 5,606427 39
40
22,309,642 80,567,923 23,037,967 41
FERC FORM NO. 1 (ED. 12-96) Page -263i
Name of Respondent
Avista Corporation
This Re ort Is: (1)An Original
(2)EJA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR
1.Give particulars (details) of the combined prepaid and accrued tax accounts and show the total taxes charged to operations and other accounts during
the year. Do not include gasoline and other sales taxes which have been charged to the accounts to which the taxed material was charged. 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.
Line
No.
-
Kind of Tax
(See instruction 5)
(a)
BALANCE AT BEGINNING OF YEAR Charged Durn Year (d)
IIxS aid During Year (e)
Adjust-
ments
(f)
Taxes Accrued (Account 236)
(b)
Prepaid Taxes (Include in Account 165)
(c)
1 STATE OF CALIFORNIA:
2 Income Tax (2010) -800 -800
3 Income Tax (2011) -7,925 1,600
4 Income Tax (2012) 1,600
5 Total California -8,725 1,600 800
6
7 MISCELLANEOUS STATES:
81 Income Tax (2011)
9 Income Tax (2012) -1
10 Total Misc States -1
11
12 COUNTY & MUNICIPAL
13 WA Renewable Energy -561 -103,659 -103,659
14 Misc. -26,441 28,535 35,852 8,181
15 Total County -27,002 -75,124 -67,807 8,181
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 8,292,344 103,605,888 89,588,591 -1
FERC FORM NO. I (ED. 12-96) Page 262.2
Name of Respondent
Avista Corporation
This Re ort Is:
(1)An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
TAXES ACCRUED, PREPAID AND CHARGED DURING YEAR (Continued)
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 (I) 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 (I) 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 (I) the taxes charged to utility plant or other balance sheet accounts.
9.For any tax apportioned to more than one utility department or account, state in a footnote the basis (necessity) of apportioning such tax.
BALANCE AT END OF YEAR DISTRIBUTION OF TAXES CHARGED Line
(Taxes accrued
Accotjnt 236) (g)
Prepaid Taxes
(Incl. in Account 165)
(h)
Electric (Account 408.1, 409.1)
(r)
Extraordinary Items
(Account 409.3) G)
Adjustments to Ret.
Earnings (Account 439)
(k)
Other No.
2
-6,325 1,600 3
-1,600 4
-7,925 1,600 5
6
7
8
9
11
12
-561 -103,659 13
-25,577 28,535 14
-26,138 -75,124 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
22,309,642 80,567,923 23,037,967 41
FERC FORM NO. I (ED. 12-96) 1 Page 263.2
Name of Respondent
Avista Corporation
I This Report Is:
I (1) An Original

(2) EA Resubmission
I Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
ACCUMULATED DEFERRED INVESTMENT TAX CREDITS (Account 255)
Report below information applicable to Account 255. Where appropriate, segregate the balances and transactions by utility and
nonutility operations. Explain by footnote any correction adjustments to the account balance shown in column (g).lnclude in column (i)
the average period over which the tax credits are amortized.
O•
Line
v i n
Balance at Beginning of Year
(b)
Deferred for Year Allocations to Current Years Income Adjustments
(g) Account No.
(c)
Amount
(d)
Account No.
(e)
Amount (f)
1
23%
Electric Utility
34%
47%
510%
6 10,166,4061 411 2,254,232
7
:8
9
10
TOTAL
Other (List separately
and show 3%, 4%, 79,
10% and TOTAL)
Gas Propertry (100%
10,166,4061
' 234,4801
1 2,254,232
' 411
I
42,06
11
12 TOTAL PROPERTY 234,480 42,060
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. I (ED. 12-89) Page 266
Name of Respondent
Avista Corporation
I This Report Is: Date of Report
(1)MAn Original (Mo, Da, Yr)
(2)flA Resubmission I 04/12/2013
Year/Period of Report
End of 2012/Q4
ACCUMULATED DFERRED INVESTMENT TAX CRED(TS (Account 255) (continued)
Balance at End Averar Period
to Income
(h)
ADJUSTMENT EXPLANATION Line
0.
2
3
4
5
12,420,638 6
7
12,420,638 8
9
192,4201 10
11
192,420 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
Avista Corporation
This Re ort Is:
(2) AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
OTHER DEFFERED CREDITS (Account 253)
1.Report below the particulars (details) called for concerning other deferred credits.
2.For any deferred credit being amortized, show the period of amortization.
3.Minor items (5% of the Balance End of Year for Account 253 or amounts less than $100000, whichever is greater) may be grouped by classes.
Line
No.
Description and Other
Deferred Credits
(a)
Balance at
Beginning of Year
(b)
___DEBITS
Credits
(e)
Balance at
End of Year
(f)
Contra
Account (c)
Amount
(d)
1 Defer Gas Exchange (253028) 1500,000 495 10 1,499,990
2 Rathdrum Refund (253120) 273,398 550 33,822 239,576
31 NE Tank Spil (253130) 70,367 186 53,570 16,797
4 Bills Pole Rentals (253140) 257,105 23,855 280,960
5 CR-CS2 GE LTSA (253150) 2,999,302 2,999,302
6 CR-Credit Resource Actg 1,577,531 1577,531
7 DOC EECE Grant (253155) 850,255 136 97,705 752,550
8 Defer Comp Retired Execs (253900) 79,658 431 20,409 59,249
9 Defer Comp Active Execs (253910) 8,652,744 153,406 8,806,150
10 Executive Incent Plan (253920) 140,000 140,000
11 Unbilled Revenue (253990) 1,812,993 908 1,129,552 683,441
12 WA Energy Recovery Mechanism 12,947,627 186 12,947,628 8,756,639 8,756,638
13 Misc Deferred Credits 357,782 357,782
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
47 TOTAL 26,584,147 14,282,696 13,868,515 1 26,169,966
FERC FORM NO. 1 (ED. 12-94) Page 269
This Page Intentionally Left Blank
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)An Original (Mo, Da, Yr) End of 2012/Q4
(2)flA Resubmission 04/12/2013
ACCUMULATED DEFFERED INCOME TAXES - OTHER PROPERTY (Account 282)
1.Report the information called for below concerning the respondent's accounting for deferred income taxes rating to property not
subject to accelerated amortization
2.For other (Specify),include deferrals relating to other income and deductions.
- CHANGES DURING YEAR
Line
No.
Account Balance at
Beginning of Year Amounts Debited Amounts Credited
to Account 410.1 to Account 411.1
(a) (b) (C) (d)
I Account 282
Electric 269,492,281 7435,394 2
3 Gas 96,448,805 5,665,663
4 Other 32,559,207 7,690,353
5 TOTAL (Enter Total of lines 2 thru 4) 398,500,293 20,791,410
6
7
8
9 TOTAL Account 282 (Enter Total of lines 5 thru 398,500,293 20,791,410
10 Classification of TOTAL
11 Federal Income Tax 387,433,970 20,791,410
12 State Income Tax 11,066,323
13 Local Income Tax
NOTES
FERC FORM NO. I (ED. 12-96) Page 274
Name of Respondent
Avista Corporation
This Report Is:
(1)JAn Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
ACCUMULATED DEFERRED INCOME TAXES - OTHER PROPERTY (Account 282) (Continued)
3. Use footnotes as required.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
276,927,67
-
Line
No.
2
Amounts Debited
to Account 410.2
(e)
Amounts Credited
to Account 411.2
(f
Debits Credits
Account
Credited
Amount
(h)
Account
Debited
Amount
U)
102,114,461 3
-75,09C 40,174,47( 4
-75,09C 419,216,61 5
6
7
8
-75,090
-75,090
419,216,61
408,150,29C
9
10
11
11,066,323 12
13
NOTES (Continued)
FERC FORM NO.1 (ED. 12-96) Page 276
Name of Respondent
Avista Corporation
This Re ort Is: 11 An Original
(2) A Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
ACCUMULATED DEFFERED INCOME TAXES - OTHER (Account 283)
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.
-
Line
No.
-
Account
(a)
CHANGES DURING YEAR
Balance at Amounts Debited Amounts Credited Beginning of Year to Account 410.1 to AccouXit 411.1 (b) (C) (a)
I Account 283
28,652,9091 -8,327,674 512,0381
2 Electric
3 Electric
4
5
6
7
8
9 TOTAL Electric (Total of lines 3 thru 8) 28,652,909 -8327,674 512,038
10 Gas
-3,884,914 1,801,980 11 Gas
12
13
14
15
16
17 TOTAL Gas (Total of lines 11 thru 16) -3,884,914 1,801,980
18 Other 234,876,525 4,169,890
19 TOTAL (Acct 283) (Enter Total of lines 9, 17 and 18) 259,644,520 -2,355,804 512,038
20 Classification of TOTAL
255,410,714 -2,355,804 512,038 21 Federal Income Tax
22 State Income Tax 4,233,806
23 Local Income Tax
NOTES
FERC FORM NO. I (ED. 12-96) Page 276
Name of Respondent
Avista Corporation
This Report Is:
(1)EjAn Original
(2)A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
ACCUMULATED DEFERRED INCOME TAXES - OTHER (Account 283) (Continued)
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.
CHANGES DURING YEAR ADJUSTMENTS
Balance at
End of Year
(k)
17,538,524
-
Line
No.
2
3
Amounts Debited
to Account 410.2
(e)
1,537,191l
Amounts Credited Debits
to Account 411.2 Account
Cr d ted (f)
Credits
Amount
(h)
Account Debited (i)
Amount
Ci)
-737,482
4
5
6
7
8
-1,537,191 -737,482
279,708
17,538,524
-1,803,226
9
10
11
12
13
14
15
16
279,708 -1,803,226 17
4,818,267 4,281,489 229,946,659 18
-1,537,191
-1,537,191
1 4,818,2671
4,818,267
1 4,281,489
4,281,489
-457,7741
-457,774
245,681,957
241,448,151
19
20
21
4,233,806 22
23
NOTES (Continued)
FERC FORM NO. 1 (ED. 12-96) Page 277
Name of Respondent
Avista Corporation
This Report Is:
2Resubmission
Date of Report
(Mo, Da, Yr)
Year/Period of Report
End of 2012/Q4
OTHER REGULATORY LIABILITIES (Account 254)
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.
Line
No.
-
Description and Purpose of
Other Regulatory Liabilities
(a)
Balance at Begining
of Current
Quarter/Year
(b)
DEBITS
Credits
(e)
Balance at End
of Current
Quarter/Year
(f)
Account
Credited
(c)
Amount _
(d)
I Idaho Investment Tax Credit (254005) 12,316,743 190 8,670 12,308,073
2 Oregon BETC Credit (254010) 69,822 1,484,162 1,553,984
3 Noxon, ITC (254025) 2737,108 606,909 3,344,017
4 Defer Gas Exchange (254028)
5 Oregon Commercial Fee (254120) ( 655) 805 1,288 -1,943
61 FAS 109 Invest Credit (254180) 126,252 190 22,644 103,608
7 Nez Perce (254220) 704,372 557 22,008 682,364
8 Oregon Senate Bill (254250) 771,592 407 842,062 -70,470
9 Reg liability CCX CR ID (254300)
10 Accrue Lake CDA IPA int (254325)
11 Decoupling Rebate (254328) 5,531 5,531
12 Idaho DSIT Amort (254335) 3,483,474 407 3,483474
13 BPA Res Exch Regulatory Liab (254345) 178,328 186 178,328
14 Reg Liability WA Reds 93,222 93,222
15 Unrealized Currency Exchange (254399) 11,097 143 7,495 3,602
161 Reg Liability Other (254700)
17 Mark to Market ST (254740) 25,468 176 25,467 1
18 Mark to Market FA5133 (254750)
19 Colstrip/CS2 516,251 186 516,250 1
20 Idaho PCA 18,566,192 18,566,192
21 SWAPS on FMBS 18,656,780 18,656,780
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41 TOTAL 20,939,852 5,107,686 39,412,796 55,244,962
FERC FORM NO. 113-Q (REV 02-04) Page 278
This Page Intentionally Left Blank
I Name of Respondent I This Report Is: I bate of Report I Year/Period of Report
Avista Corporation (1)An Original (Mo, Da, Yr) I End of 2012/Q4 I F (2)E Resubmission ,L113
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 fiat 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.
Title of Account
No. to Date Quarterly/Annual I Previous year (no Quarterly)
11 Sales of Electricity
2 (440) Residential Sales 315,137,034 324,834,634
3 (442) Commercial and Industrial Sales
4 Small (or Comm.) (See lnstr. 4) 286,567,954 280,139,238
5 Large (or Ind.) (See lnstr. 4) 119,588,721 122,559,992
6 (444) Public Street and Highway Lighting 7,240,388 6,940,809
7 (445) Other Sales to Public Authorities
8 (446) Sales to Railroads and Railways
9 (448) Interdepartmental Sales 1,025,713 1,037,295
10 TOTAL Sales to Ultimate Consumers 729,559,810 735,511,968
11 (447) Sales for Resale 148,004,414 118,011,777
12 TOTAL Sales of Electricity 877564,224 853,523,745
13 (Less) (449.1) Provision for Rate Refunds
14 TOTAL Revenues Net of Prov. for Refunds 877,564,224 853,523,745
15 Other Operating Revenues
16 (450) Forfeited Discounts
17 (451) Miscellaneous Service Revenues 559,797 572,046
18 (453) Sales of Water and Water Power 468,800 506,582
19 (454) Rent from Electric Property 2,971,731 2,880,894
20 (455) Interdepartmental Rents
21 (456) Other Electric Revenues 124,709,799 183,611,801
22 (456.1) Revenues from Transmission of Electricity of Others 11,641,754 12,755,612
23 (457.1) Regional Control Service Revenues
24 (457.2) Miscellaneous Revenues
25
26 TOTAL Other Operating Revenues 140,351,881 200,326,935
27 TOTAL Electric Operating Revenues 1,017,916,105 1,053,850,680
FERC FORM NO. 113-0 (REV. 12-05) Page 300
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation End of 2012/Q4
AResubmission 04/12/2013
ELECTRIC OPERATING REVENUES (Account 400)
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.
MEGAWATT HOURS SOLD AVG.NO . CUSTOMERS PER MONTH Line
Year to Date Quarterly/Annual Amount Previous year (no Quarterly) Current Year (no Quarterly) Previous Year (no Quarterly) No.
(d) (e) (f) (g) -
3,608,626 3,728,029 318,692 316,763 2
3
3,127,158 3,122,058 39,869 39,618 4
2,099,648 7 2,147,014 1,395 1,380 5
25,878 25828 503 455 6
7
8
11,695 12,204 94 87 9
8,873,005 9,035,133 360,553 358,303 10
5,634,398 4,084,890 11
- 14,507403 13,120,023 360,553 358,303 12
13
14,507,403 13,120,023 360,553 358,303 14
Line 12, column (b) includes $ -799,381 of unbilled revenues.
Line 12, column (d) includes -15,142 MWH relating to unbilled revenues
FERC FORM NO. 113-Q (REV. 12-05) Page 301
Name of Respondent
Avista Corporation
This Re ort Is:
(1)An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012104
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. 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.
Line
No.
Number and I we ot Kate schedule
(a)
MWh sold
(b)
Revenue
(C)
Average Number
of CLsomers
KWh of sales
Per Customer
KtW re (bOd
1 RESIDENTIAL SALES (440)
_2 1 Residential Service 3,484,858 291,806,496 303,699 11,475 0.0837
3 2 Residential Service
4 3 Residential Service
5 12 Res. & Farm Gen. Service 75,161 9,446,488 13,168 5,708 0.1257
_6 15 MOPS II Residential
7 22 Res. & Farm Lg. Gen. Service 50,650 4,107,894 92 550,543 0.0811
8130 Pumping-Special
9 32 Res. & Farm Pumping Service 10,198 1,010,209 1,733 5,885 0.0991
10 48 Res. & Farm Area Lighting 4,430 1094,345 0.2470
11 49 Area Lighting-High-Press. 251 75,691 0.3016
12 56 Centralia Refund
13195 Wind Power 160,823
14 72 Residential Service
15 73 Residential Service
16 74 Residential Service
17 76 Residential Service
18.77 Residential Service
19 58A Tax Adjustment -47,048
20 58 Tax Adjustment 8,615,208
21 SubTotal 3,625,548 316,270,106 318,692 11,376 0.0872
22 Residential-Unbilled -16,922 -1,133,072 0.0670
23 Total Residential Sales 3,608,626 315,137,034 318,692 11,323 0.0873
24
25 COMMERCIAL SALES (442)
26 2 General Service
27 3 General Service
28 11 General Service 772,355 83,803,542 35,386 21,827 0.1085
29 12 Res. & Farm Gen. Service
30 16 MOPS II Commercial
3119 Contract-General Service
32 21 Large General Service 1,908,187 162,246,489 3,377 565,054 0.0850
33,25 Extra Lg. Gen. Service 348,081 20,748,315 13 26,775,462 0.0596
34 28 Contract-Extra Large Setv
35 31 Pumping Service 89,861 7,275,014 1,093 82,215 0.0810
36 47 Area Lighting-Sod. Vap 6,276 1,393,223 0.2220
37 49 Area Lighting-High-Press. 2,452 564,944 0.2304
38,56 Centralia Refune
39 95 Wind Power 79,231
40 74 Large General Service
TOTAL Billed 14,522,545 878,363,605 360,553 40,27 0.060
42 Total Unbilled Rev.(See Instr. 6) -15,14 -799,381 _( I 0.0521
43 TOTAL 14,507,40 877,564,224 360,55 40,2371 0,060
FERC FORM NO. 1 (ED. 12-95) Page 304
Name of Respondent
Avista Corporation
This Report Is:
(1)An Original
(2)E A Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues,' Page
300-301. 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.
Line
No.
Number and title ot Kate scnedule
(a)
MWri Sold
(b)
Kevenue
(c)
Average Number
of Ciomers
KWh of sates
Per etomer
KpVg L1 or Sod
1 75 Large General Service
_2 76 Large General Service
3 77 General Service
4 58A Tax Adjustment -48,098
5 58 Tax Adjustment 10,339,542
6 SubTotal 3,127,212 286,402,202 39,869 78,437 0.0916
7 Commercial-Unbilled -54 165,752 -3.0695
8 Total Commercial 3,127,158 286,567,954 39,869 78,436 0.0916
9
10 INDUSTRIAL SALES (442)
11 2 General Service
12 3 General Service
131 8 Lg Gen Time of Use
1411 General Service 8,606 962,379 250 34,424 0.1118
15 12 Res. & Farm Gen. Service
16 21 Large General Service 200,418 16,508,790 174 1,151,828 0.0824
17 25 Extra Lg. Gen. Service 1,806,952 94,575,610 18 100,386,222 0.0523
18 28 Contract - Extra Large Service 19,250
19,29 Contract Lg. Gen. Service
20 30 Pumping Service - Special 20,821 1,422,369 32 650,656 0.0683
21 31 Pumping Service 57,284 4,798,691 774 74,010 0.0838
22 32 Pumping Svc Res & Firm 3,407 283,556 147 23,177 0.0832
23 47 Area Lighting-Sod. Vap. 232 49,905 0.2151
24,49 Area Lighting - High-Press 57 12,024 0.2109
25 95 Wind Power 1,728
26 72 General Service
27 73 General Service
28 74 Large General Service
29,75 Large General Service
30176 Pumping Service
31 77 General Service
32 58A Tax Adjustment -1,027
33 58 Tax Adjustment 791,207
34 SubTotal 2,097,777 119,424,482 1,395 1,503,783 0.0569
351 Industrial-Unbilled 1,871 164,239 0.0878
36 Total Industrial 2,099,648 119,588,721 1,395 1,505,124 0.0570
37
38 STREET AND HWY LIGHTING (444)
39 6 Mercury Vapor St. Ltg.
401 7 HP Sodium yap. St. Ltg
TOTAL Billed 14,522,5451 878,363,605 360,55 40,271 0.0605
42 Total Unbilled Rev.(See lnstr. 6) -15,14 -799,381 ( C 0.0521
43 TOTAL 14,507,401 877,564,224 360,55 40,23 0.060f
FERC FORM NO. 1 (ED. 12-95) Page 304.1
Name of Respondent
Avista Corporation
This Re ort Is:
2nRssion
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
SALES OF ELECTRICITY BY RATE SCHEDULES
1.Report below for each rate schedule in effect during the year the MWH of electricity sold, revenue, average number of customer, average Kwh per
customer, and average revenue per Kwh, excluding date for Sales for Resale which is reported on Pages 310-311.
2.Provide a subheading and total for each prescribed operating revenue account in the sequence followed in "Electric Operating Revenues," Page
300-301. 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.
Line
No.
Number and I itle ot Kate Schedule
(a)
MWh Sold
(b)
Revenue
(c)
Average Number
of CLjomers
KWh of saies Per cstomer KLJ re o d
ill General Service 93 10,825 3 31,000 0.1164
2 41 Co-Owned St. Lt. Service 219 42,131 20 10,950 0.1924
3,42 Co-Owned St. Lt. Service 20,709 6,499,743 386 53,650 0.3139
4 High-Press. Sod. yap.
543 Gust-Owned St. Lt. Energy 9 911 2 4,500 0.1012
6 and Maint. Service
7 44 Gust-Owned St. Lt. Energy 855 131,590 30 28,500 0.1539
8 and Maint. Svce - High-Pres
9 Sodium Vapor
10 45 Gust. Owned St. Lt. Energy Svc 1,356 95,578 12 113,000 0.0705
11 46 Gust. Owned St. Lt. Energy Svc 2,674 250,832 50 53,480 0.0938
121 58A Tax Adjustment -691
13 58 Tax Adjustment 205,769
14 SubTotal 25,915 7236,688 503 51,521 0.2792
15 Street & Hwy Lighting-Unbilled -37 3,700 -0.1000
16 Total Street & Hwy Lighting 25,878 7,240,388 503 51,447 0.2798
17
18 OTHER SALES TO PUBLIC
19 (445)
20 None
21
22 INTERDEPARTMENTAL SALES 11,695 1,025,713 94 124,415 0.0877
23 58 Tax Adjustment
24 Total Interdepartmental 11,695 1,025,713 94 124,415 0.0877
25
26 SALES FOR RESALE (447) 5,634,398 148,004,414 0.0263
27,61 Sales to Other Utilities (NDA)
28
29
30 Total Sales for Resale 5,634,398 148,004,414 0.0263
31
32
33
34
35
36
37
38
39
40
41 TOTAL Billed 14,522,54! 878,363,605 360,55Z 40,271 0.0605
421 Total Unbilled Rev.(See lnstr. 6) -15,14 -799,381 0.0528
43 TOTAL 14,507,401 877,564,224 360,55: 40,23 0.0601
FERC FORM NO. 1 (ED. 12-95) Page 304.2
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)UA Resubmission 04/12/2013
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.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.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Averag
Monthly Billing
Actual Demand (MW)
Average Averaae No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number Demand (MW) Monthly NCP Demand Monthly CP"bemand
- (a) (b) (C) (d) (e) (f)
1 BP Energy Company SF ISDA
2 BP Energy Company SF Tariff 9
3 Barclays Bank PLC SF Tariff 9
4 Black Hills Power, Inc. SF Tariff 9
5 Bonneville Power Administration LF Tariff B
6 Bonneville Power Administration LF ACS-06
7 Bonneville Power Administration SF Tariff 9
8 Bonneville Power Administration LF Tariff 12
9 British Columbia Hydro and Power Author LF Tariff 12
10 Brookfield Energy Marketing LP SF Tariff 9
11 Burbank, City of SF Tariff 9
12 Calpine Energy Services LP SF Tariff 9
13 Cargill Power Markets, LLC SF Tariff 9
14 Cargill Power Markets, LLC SF ISDA
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO I (ED 12-90) Page 310
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/Q4 (2)EJ A Resubmission 04/12/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or 'true-ups' for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter 'Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.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 (t) 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.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k) -
3,390,228 3,390,228 1
113,231 2,426,058 2,426,058 2
3,000 79,050 79,051 3
5,232 27,546 27,546 4
16,377 326,932 326,932 5
3,208 48,972 48,972 6
165,964 4,781,908 4,781,908 7
12 328 328 8
42 506 506 9
1,800 39,600 39,600 10
800 18,000 18,000 11
256,448 7,177,948 7,177,948 12
475,617 8,328,494 8,328,494 13
185,242 185,242 14
0 0 0 0 0
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
FERC FORM NO. 1 (ED. 12-90) Page 311
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original
(2)flA Resubmission
(Mo, Da, Yr)
04/12/2013 End of 20121Q4
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.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.
Line Name of Company or Public Authority Statistical
Classifi-
FERC Rate
Schedule or
Ave raq Monthly Billing
Actual Demand (MW)
Averacie Avera e No. (Footnote Affiliations) cation Tariff Number Demand (MW) Monthly NCP Demand Monthly
- (a) (b) (c) (d) (e) (t)
1 Chelan County PUD No. 1 SF Tariff 9
2 Chelan County PUD No. I IF Tariff 12
3 Citigroup Energy, Inc. SF Tariff 9
4 Clark County PUD No. 1 SF Tariff 9
5 Clatskanie Peoples PUD SF Tariff 9
6 Conoco Phillips SF Tariff 9
7 Conoco Phillips SF Tariff 9
8 Constellation Energy Commodities Group SF Tariff 9
9 DB Energy Trading, LLC SF Tariff 9
10 Douglas County PUD No. I SF Tariff 9
11 EDF Trading North America SF Tariff 9
12 Eugene Water & Electric Board SF Tariff 9
13 Exelon Generation Company, LLC SF Tariff 9
14 Grant County PUD No. 2 SF Tariff 9
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/04
(2)A Resubmission 04/12/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.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.
Megawatt Hours REVENUE Total ($) Line
Demand charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) U) (k) -
13,016 324,890 324,890 1
6 314 3142
151,169 2,965,764 2,965,764 3
12,283 328,437 328,437 4
4,429 115,516 115,516 5
3 60 606
122,976 122,976 7
45,200 575,600 575,600 8
117,600 2,709,771 2,709,771 9
10,440 251,040 251,040 10
227,272 4,516,189 4,516,189 11
15,010 431,861 431,861 12
3,600 95,780 95,780 13
13,660 336,785 336,785 14
0 0 0 0 0
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414
FERC FORM NO. I (ED. 12-90) Page 311.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original
(2)1JA Resubmission
(Mo, Da, Yr)
04/12/2013 End of 2012/04
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.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.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average
Monthly Billing
Actual Demand (MW)
Averaqe Avera e No. (Footnote Affiliations) Classifi-
cation
Schedule or Tariff Number Demand (MW) Monthly NCP Demand Monthly CFI-Demand
- (a) (b) (c) (d) (e) (f)
1 Grant County PUD No. 2 IF Tariff 12
2 Grant County PUD No. 2 SF Tariff 9
3 lberdrola Renewables, LLC SF Tariff 9
4 lberdrola Renewables, LLC SF Tariff 9
5 lberdrolà Renewables, LLC SF Tariff 9
6 Idaho Power Company SF Tariff 9
7 Idaho Power Company LF Tariff 12
8 Idaho Power Balancing SF Tariff 9
9 J. Aron & Company SF Tariff 9
10 J. Aron & Company SF ISDA
11 JP Morgan Ventures Energy SF Tariff 9
12 JP Morgan Ventures Energy SF ISDA
13 Macquarie Energy, LLC SF Tariff 9
14 Modesto Irrigation District SF Tariff 9
Subtotal RQ o 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90) Page 310.2
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/04
(2)jA Resubmission 04/12/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.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 U). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
Megawatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) U) (k) -
24 420 420 1
5,450 5,450 2
649,215 12,891,335 12,891,335 3
213,100 213,1004
150 1505
63,858 1,103,030 1,103,030 6
51 1,127 1,127 7
78,131 1,253,347 1,253,347 8
2,600 71,900 71,900 9
373,354 373,354 10
73,235 1,270,923 1,270,923 11
74,686 74,686 12
217,256 5,176,604 5,176,604 13
144 1,296 1,296 14
0 0 0 0 0
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
FERC FORM NO. I (ED. 12-90) Page 311.2
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original
(2)flA Resubmission
(Mo, Da, Yr)
04112/2013 End of - 20121Q4
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.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.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that 'intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical FERC Rate Average
Monthly Billing
Actual Demand (MW)
Averaqe Averaae No. (Footnote Affiliations) Classifi- cation Schedule, or Tariff Number Demand (MW) Monthly NC P Demand Monthly CPlJemand
(a) (b) (c) (d) (e) (f)
1 Morgan Stanley Capital Group, Inc. SF ISDA
2 Morgan Stanley Capital Group, Inc. SF ISDA
3 NaturEner Power Watch, LLC SF Tariff 9
4 NaturEner Power Watch, LLC LF Tariff 12
5 NaturEner Power Watch, LLC SF Tariff 9
6 NaturEner Power Watch, LLC SF Tariff 9
7 NaturEner Power Watch, LLC SF Tariff 9
8 Newedge USA, LLC SF ISDA
9 NextEra Energy Power Market SF Tariff 9
10 Noble America Gas & Power SF Tariff 9
11 NorthWestern Energy LLC SF Tariff 10
12 NorthWestern Energy LLC SF Tariff 10
13 NorthWestern Energy LLC SF Tariff 9
14 NorthWestern Energy LLC SF Tariff 9
Subtotal RQ o 0 0
Subtotal non-RQ 01 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/04
(2)EA Resubmission 04/12/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.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.
B. 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.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) U) (k) -
303,760 7,396,782 7,396,782 1
1,805,094 1,805,094 2
5,852 116,165 116,1653
7 174 1744
176,410 176,410 5
285,479 285,479 6
1,520 1,5207
14,144,512 14,144,512 8
400 9,600 9,600 9
2,800 76,700 76,700 10
335,017 335,017 11
89,074 89,074 12
16,533 276,443 276,443 13
94,379 2,069,628 2,069,628 14
0 0 0 0 0
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
FERC FORM NO. 1 (ED. 12-90) Page 311.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original
(2)JA Resubmission
(Mo, Da, Yr)
04/12/2013 End of 20121Q4
SALES FOR RESALE (Account 447)
1.Report a14 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.
Line Name of Company or Public Authority Statistical
Classifi-
FERC Rate
Schedule or
Average Monthly Billing
Actual Demand (MW)
Averaae Avera e No. (Footnote Affiliations) cation Tariff Number Demand (MW) Monthly NC Demand Monthly CP9Demand
- (a) (b) (c) (d) (e) (f)
1 NorthWestern Energy LLC LF Tariff 12
2 NorthWestern Energy LLC LF Tariff 9
3 NorthWestern Energy LLC SF Tariff 10
4 Okanogan County PUD SF Tariff 9
5 PacifiCorp SF Tariff 9
6 PacifiCorp LF Tariff 12
7 PacifiCorp LF Tariff 9
8 Peaker LLC LF Tariff 9
9 Pend Oreille Public Utility District LF Tariff 9
10 Pend Oreille Public Utility District LF Tariff 9
11 Pend Oreille Public Utility District SF Tariff 9
12 Pend Oreille Public Utility District LF 290 (PNCA)
13 Portland General Electric Company SF Tariff 9
14 Portland General Electric Company LF Tariff 12
Subtotal RQ 0 0 0
Subtotal non-RQ 01 01 0
Total 0 01 o
FERC FORM NO. 1 (ED. 12-90) Page 310.4
Name of Respondent This Re oil Is: Date of Report Year/Period of Report
Avista Corporation p (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)EA Resubmission 04/12/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote
AD -for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.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.
Megawatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (j) (k)
36 806 806 1
7,657 139,740 139,740 2
938,790 938,790 3
4,010 94,763 94,763 4
71,026 1,858,816 1,858,816 5
195 4,308 4,308 6
4,875 88,925 88,925 7
1,748,921 1,748,921 8
421,348 421,3489
18,697 312,353 312,353 10
66,903 829,908 829,908 11
16,696 16,696 12
229,965 3,599,607 3,599,607 13
73 1,919 1,919 14
0 0 0 0 0_
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
FERC FORM NO. 1 (ED. 12-90) Page 311.4
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)x An Original
(2)EA Resubmission
(Mo, Da, Yr)
04/12/2013 End of 2012/Q4
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.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.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical
Classifi-
FERC Rate
Schedule or
Average Monthly Billing
Actual Demand (MW)
Averaqe Average No. (Footnote Affiliations) cation Tariff Number Demand (MW) Monthly NCR Demand Monthly CPbemand
- (a) (b) (C) (d) (e) (f)
I Powerex SF Tariff 9
2 Powerex SF Tariff 9
3 PPL EnergyPlus, LLC SF Tariff 9
4 PPL EnergyPlus, LLC SF Tariff 9
5 PPL EnergyPlus, LLC LF Tariff 9
6 Puget Sound Energy LF Tariff 9
7 Puget Sound Energy SF Tariff 9
8 Puget Sound Energy LF Tariff 12
9 Rainbow Energy Marketing SF Tariff 9
10 Redding, City of SF Tariff 9
11 Sacramento Municipal Utility District SF Tariff 9
12 Sacramento Municipal Utility District LF Tariff 12
13 Sacramento Municipal Utility District LF Tariff 9
14 San Diego Gas & Electric Company SF Tariff 9
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90) Page 310.5
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original
(2)LJA Resubmission
(Mo, Da, Yr)
04/12/2013 End of 2012/Q4
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) a 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 U). Report in column (k)
the total charge shown on bills rendered to the purchaser.
9.The data in column (g) through (k) must be subtotaled based on the RQ/Non-RQ grouping (see instruction 4), and then totaled on
the Last -line of the schedule. The "Subtotal - RQ" amount in column (g) must be reported as Requirements Sales For Resale on Page
401, line 23. The "Subtotal - Non-RQ" amount in column (g) must be reported as Non-Requirements Sales For Resale on Page
401 ,iine 24.
10.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours REVENUE Total ($) Line ____________________
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (i) (I) (k) -
232,936 4,997,478 4,997,478 1
580 580 2
200 200 3
74,125 1,866,240 1,866,240 4
17,400 317,590 317,590 5
22,275 406,516 406,516 6
101,119 2,770,411 2,770,411 7
29 683 683 8
128,301 1,702,326 1,702326 9
1,520 24,320 24,320 10
17,110 421,061 421,061 11
4 33 3312
573,915 17,875,745 17,875,745 13
11,972 139,235 139,235 14
0 0 0 0 011
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
FERC FORM NO. I (ED. 12-90) Page 311.5
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original
(2)JA Resubmission
(Mo, Da, Yr)
04/12/2013 End of 2012/Q4
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.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.
lU - for intermediate-term service from a designated generating unit. The same as LU service except that "intermediate-term" means
Longer than one year but Less than five years.
Line Name of Company or Public Authority Statistical
Classifi-
FERC Rate
Schedule or
Averaqe
Monthly Billing
Actual Demand (MW)
Averaoe Average No. (Footnote Affiliations) cation Tariff Number Demand (MW) Monthly NCI5 Demand Monthly
- (a) (b) (c) (d) (e) (f)
I Seattle City Light SF Tariff 9
2 Seattle City Light LF Tariff 12
3 Shell Energy N.A. SF Tariff 9
4 Shell Energy N.A. SF ISDA
5 Shell Energy N.A. SF Tariff 9
6 Sierra Pacific Power Company SF Tariff 9
71 Sierra Pacific Power Company LF Tariff 12
8 Snohomish County PUD SF Tariff 9
9 Southern California Edison Company SF Tariff 9
10 Sovereign Power LF Tariff 10
11 Sovereign Power LF Tariff 9
12 Tacoma Power SF Tariff 9
13 Tacoma Power SF Tariff 9
14 Tenaska Power Services Co. SF Tariff 9
Subtotal RQ 0 0 0
Subtotal non-RQ 0 0 0
Total 0 0 0
FERC FORM NO. 1 (ED. 12-90) Page 310.6
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr) End of 2012/Q4 (2) flA Resubmission 04/12/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ"
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.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.
MegaWatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold No.
(g) (h) (i) (j) (k) -
14,272 243,614 243,614 1
35 564 564 2
476,337 8,085,026 8,085,026 3
1,498,757 1,498,757 4
1,000 1,000
20,628 605,143 605,143 6
90 2,086 2,086 7
5,997 147,826 147,826 8
72 729
78,800 78,800 10
13,957 241,125 241,125 11
8,928 148,702 148,702 12
9,600 9,600 13
2,267 41,688 41,688 14
0 0 0 0 0
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
FERC FORM NO. 1 (ED. 12-90) Page 311.6
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)EJA Resubmission 04/12/2013
SALES FOR RESALE (Account 447)
1.Report all sales for resale (i.e., sales to purchasers other than ultimate consumers) transacted on a settlement basis other than
power exchanges during the year. Do not report exchanges of electricity (i.e., transactions involving a balancing of debits and credits
for energy, capacity, etc.) and any settlements for imbalanced exchanges on this schedule. Power exchanges must be reported on the
Purchased Power schedule (Page 326-327).
2.Enter the name of the purchaser in column (a). Do note abbreviate or truncate the name or use acronyms. Explain in a footnote any
ownership interest or affiliation the respondent has with the purchaser.
3.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.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Averaae Monthly NCP Demand Average Monthly CP Demand No. (Footnote Affiliations) Classifi- cation Schedule or Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 The Energy Authority SF Tariff 9
2 TransAlta Energy Marketing SF Tariff 9
3 Tri-State Generation & Transmission As SF Tariff 9
4 Turlock Irrigation District SF Tariff 9
5 IntraCompany Wheeling LF
6 IntraCompany Generation LF
7 Revenue Adjustment AD
8
9
10
11
12
13
14
- Subtotal RQ 0 0 0
Subtotal non-RQ 01 0 0
Total 0 0 0
FERC FORM NO. I (ED. 12-90) Page 310.7
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)EIA Resubmission 04/12/2013
SALES FOR RESALE (Account 447) (Continued)
OS - for other service, use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote.
AD - for Out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Provide an explanation in a footnote for each adjustment.
4.Group requirements RQ sales together and report them starting at line number one. After listing all RQ sales, enter "Subtotal - RQ'
in column (a). The remaining sales may then be listed in any order. Enter "Subtotal-Non-RQ" in column (a) after this Listing. Enter
"Total" in column (a) as the Last Line of the schedule. Report subtotals and total for columns (9) through (k)
5.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.
Megawatt Hours REVENUE Total ($) Line
Demand Charges Energy Charges Other Charges Sold (h+i+j) No.
(g) (h) (I) (j) (k) -
29,338 718,629 718,629 1
268,795 5,630,907 5,630,907 2
44,746 522,965 522,965 3
1,200 -1,640 -1,640 4
-17,834,609 17,834,609 5
625,117 625,117 6
-3 7
8
9
10
11
12
13
14
0 0 0 0 0_
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414 -
5,634,398 4,356,037 103,627,704 40,020,673 148,004,414
FERC FORM NO. I (ED. 12-90) Page 311.7
ISchedule Page: 310 Line No.: I Column: b I
SWAP
ISchedule Page: 310 Line No.: 5 Column: b
BPA Contract Terminates September 30, 2028.
ISchedule Page: 310 Line No.: 6 Column: b I
BPA Contract Terminates January 1, 2036.
Schedule Page: 310 Line No.: 8 Column: b I
NWPP Reserve Sharing Sales
lSchedule Page: 310 Line No.: 9 Column: b
NWPP Reserve Sharing Sales
ISchedule Paqe: 310 Line No.: 14 Column: b -- I
SWAP
Schedule Page: 310.1 Line No.: 2 Column: b
NWPP Reserve Sharing Sales
ISchedule Page: 310.2 Line No.: I Column: b
NWPP Reserve Sharing Sales
ISchedule Page: 310.2 Line No.: 4 Column: b
Capacity
lSchedule Page: 310.2 Line No.: 7 Column: b I
NWPP Reserve Sharing Sales
ISchedule Page: 310.2 Line No.: 10 Column: b I
SWAP
ISchedule Paae: 310.2 Line No.: 12 Column: b -
lSchedule Page: 310.3 Line No.: 2 Column: b
SWAP
NWPP Reserve
Capacity
lSchedule Page: 310.3 Line No.: 8 Column: b
SWAP
ISchedule Paqe: 310.3 Line No.: II Column: b - _I
lSchedule Page: 310.3 Line No.: 12 Column: b
Bundled Transmission
lSchedule Page: 310.4 Line No.: I Column: b
NWPP Reserve Sharing Sales
Schedule Page: 310.4 Line No.: 2 Column: b
NorthWestern Energy LLC sale expires October 31, 2013.
ISchedule Page: 310.4 Line No.: 6 Column:b
NWPP Reserve Sharing Sales
ISchedule Page: 310.4 Line No.: 7 Column: b
PacifiCorp sale terminates October 31, 2013.
ISchedule Page: 310.4 Line No.: 8 Column: b
TTj' ,-'4t-xr -ri- t- rniri.t rmhr 31. 2016.
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 5 Column: b
PPL sale terminates October 31, 2013.
NWPP Reserve Sharing Sales
ISchedule Page: 310.5 Line No.: 12 Column: b I
NWPP Reserve Sharing Sales
Schedule Page: 310.5 Line No.: 13 Column: b I
Contract expires 2014.
Schedule Page: 310.6 Line No.: 2 Column: b I
NWPP Reserve Sharing Sales
ISchedule Page: 310.6 Line No.: 4 Column: b I SWAP
Schedule Page: 310.6 Line No.: 7 Column: b I
NWPP Reserve Sharing Sales
ISchedule Page: 310.6 Line No.: 10 Column: b I
Sovereign Power contract terminates 1-31-2015
lSchedule Page: 310.6 Line No.: 11 Column: b I
Sovereign Power Contract terminates 1-31-2015
lSchedule Page: 310.7 Line No.: 5 Column: a
intracompany Wheeling
lSchedule Page: 310.7 Line No.: 5 Column: b
IntraCompany Wheeling terminates 09/30/2023.
ISchedule Page: 310.7 Line No.: 6 Column: a I
Intracpany Generation - Sale of Ancillary Services
Schedule Page: 310.7 Line No.: 6 Column: b
IntraCompany Generation - Sale of Ancillary Services.
ISchedule Page: 310.7 Line No.: 7 Column: b I
Estimated revenues - true up in later periods.
Name of Respondent
Avista Corporation
This Re ort Is:
AResubmission
Date of Report
041/2013
Year/Period of Report
End of 20121Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
No.
Account
(a)
-Amount for .
Current Year
(b)
Anountfpr Previous year
(C)
1 1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 Operation
4 (500) Operation Supervision and Engineering 405,853 1 502,678
5 (501) Fuel 27,965,080 31,254,162
6 (502) Steam Expenses 4,007,068 4,303,460
7 (503) Steam from Other Sources
8 (Less) (504) Steam Transferred-Cr.
9 (505) Electric Expenses 903,817 910,212
10 (506) Miscellaneous Steam Power Expenses 2,366,646 2,398,191
11 (507) Rents 21,917 32,398
12 (509) Allowances
13 TOTAL Operation (Enter Total of Lines 4 thru 12) 35,670,381 39,401,101
14 Maintenance
15 (510) Maintenance Supervision and Engineering 496,860 587,143
16 (511) Maintenance of Structures 607,138 723,510
17 (512) Maintenance of Boiler Plant 4,845,432 6,088,972
18 (513) Maintenance of Electric Plant 584,214 1,401,570
19 (514) Maintenance of Miscellaneous Steam Plant 565,141 852,347
20 TOTAL Maintenance (Enter Total of Lines 15 thru 19) 7,098,7851 9,653,542
21 TOTAL Power Production Expenses-Steam Power (Entr Tot lines 13 & 20) 42,769,1661 49,054,6431
22 B. Nuclear Power Generation
23 Operation
24 (517) Operation Supervision and Engineering
25 (518) Fuel
26 (519) Coolants and Water
27 (520) Steam Expenses
28 (521) Steam from Other Sources
29 (Less) (522) Steam Transferred-Cr.
30 (523) Electric Expenses
31 (524) Miscellaneous Nuclear Power Expenses
32 (525) Rents
33 TOTAL Operation (Enter Total of lines 24 thru 32)
34 Maintenance
35 (528) Maintenance Supervision and Engineering
36 (529) Maintenance of Structures
37 (530) Maintenance of Reactor Plant Equipment
38 (531) Maintenance of Electric Plant
39 (532) Maintenance of Miscellaneous Nuclear Plant
40 TOTAL Maintenance (Enter Total of lines 35 thru 39)
41 TOTAL Power Production Expenses-Nuc. Power (Entr tot lines 33 & 40)
42 1 C. Hydraulic Power Generation
43 1 Operation
44 (535) Operation Supervision and Engineering I 2,403,1661 2,576,301
45 (536) Water for Power 1,177,037 1,118,184
46 (5 7) Hydraulic Expenses 7,432,593 7,340,213
47 (538) Electric Expenses 6,299,3361 5,780,431
48 (539) Miscellaneous Hydraulic Power Generation Expenses 620,3141 703,631
49 (540) Rents 6,810,5971 6,605,536
50 TOTAL Operation (Enter Total of Lines 44 thru 49) 24,743,0431 24,124,296
51 C. Hydraulic Power Generation (Continued)
52 Maintenance
53 (541) Mainentance Supervision and Engineering 583,198 557,119
54 (542) Maintenance of Structures 606,145 420,759
55 (543) Maintenance of Reservoirs, Dams, and Waterways 1,355,754 2,953,754
56 (544) Maintenance of Electric Plant 2,804,743 2,343,586
57 (545) Maintenance of Miscellaneous Hydraulic Plant 485,261L_ 503,926
58 TOTAL Maintenance (Enter Total of lines 53 thru 57) 5,835,1011 6,779,144
59 TOTAL Power Production Expenses-Hydraulic Power (tot of lines 50 & 58) 30,578,144 30,903,440
FERC FORM NO. 1 (ED. 12-93) Page 320
Name of Respondent
Avista Corporation
This Report Is: (1)An Original
(2)flA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
0.
Account
(a) Current urrent Year .Amount for
(b)
Amount for Previous Year
(C)
60 D. Other Power Generation
61 Operation
62 (546) Operation Supervision and Engineering 1 1,289,906 1438,316
63 (547) Fuel 64,054,801 54,982,069
64 (548) Generation Expenses 1,693,501 1,077,281
65 (549) Miscellaneous Other Power Generation Expenses 619,292 570,980
66 (550) Rents 50,652 -31,837
67 TOTAL Operation (Enter Total of lines 62 thru 66) 67,708,1521 58,036,809
68 1 Maintenance
69 (551) Maintenance Supervision and Engineering 1,867,043 680,635
70 (552) Maintenance of Structures 12,412 12,248
71 (553) Maintenance of Generating and Electric Plant 7,706,560 1,480,762
72 (554) Maintenance of Miscellaneous Other Power Generation Plant 161,209 154,760
73 TOTAL Maintenance (Enter Total of lines 69 thru 72) 9,747,224 2,328,405
74 1 TOTAL Power Production Expenses-Other Power (Enter Tot of 67 & 73) 77,455,376 60,365,214
75 E. Other Power Supply Expenses
76 (555) Purchased Power 239,356,429 209,550,746
77 (556) System Control and Load Dispatching 864,537 714,621
78 (557) Other Expenses 145,305,655 228,635,614
79 TOTAL Other Power Supply Exp (Enter Total of lines 76 thru 78) 385,526,6211 438,900,981
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74 & 79) 536,329,3071 579,224,278
2. TRANSMISSION EXPENSES
Operation
r
(560) Operation Supervision and Engineering 2,165.264' 2,091,494'
84
(561.1) Load Dispatch-Reliability 14,379 16,630
86 (561,.2) Load Dispatch-Monitor and Operate Transmission System 1,175,921 1,247,742
87 (561.3) Load Dispatch-Transmission Service and Scheduling 962,648 965,661
88 (561.4) Scheduling, System Control and Dispatch Services
89 (561.5) Reliability, Planning and Standards Development
90 (561.6) Transmission Service Studies
91 (561.7) Generation Interconnection Studies
92 (561.8) Reliability, Planning and Standards Development Services
93 (562) Station Expenses 419,664 318,511
94 (563) Overhead Lines Expenses 468,930 518,176
95 (564) Underground Lines Expenses ________
96 (565) Transmission of Electricity by Others 17,551,614 17,489,619
97 (566) Miscellaneous Transmission Expenses 1,787,287 1,679,342
98 (567) Rents 115,925 127,552
99 TOTAL Operation (Enter Total of lines 83 thru 98) 24,661,632 24,454,727
100 Maintenance
101 (568) Maintenance Supervision and Engineering 2,123,807 1,313,699
102 (569) Maintenance of Structures 451,661 426,540
103 (569.1) Maintenance of Computer Hardware
104 (569.2) Maintenance of Computer Software
105 (569.3) Maintenance of Communication Equipment
106 (569.4) Maintenance of Miscellaneous Regional Transmission Plant
107 (570) Maintenance of Station Equipment 1,139,396 1,146,932
108 (571) Maintenance of Overhead Lines 1,750,864 2,405,427
109 (572) Maintenance of Underground Lines 8,377 1,731
110 (573) Maintenance of Miscellaneous Transmission Plant 96,193 28,956
111 TOTAL Maintenance (Total of lines 101 thru 110) 5,570,298 5,323,285
112 TOTAL Transmission Expenses (Total of lines 99 and 111) 30,231,930 29,778,012
FERC FORM NO. I (ED. 12-93) Page 321
Name of Respondent
Avista Corporation
This Re ort Is:
AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
i'iO.
Account
(a)
Amount for Current Year
(b)
Arrkount fpr Previous iear
(C)
113 3. REGIONAL MARKET EXPENSES
114 Operation
115 (575.1) Operation Supervision
16 (575.2) Day-Ahead and Real-Time Market Facilitation
17 (575.3) Transmission Rights Market Facilitation
18 V (575.4) Capacity Market Facilitation
119 (575.5) Ancillary Services Market Facilitation
120 (575.6) Market Monitoring and Compliance
121 (575.7) Market Facilitation, Monitoring and Compliance Services
122 (575.8) Rents
123 Total Operation (Lines 115 thru 122)
124 Maintenance
125 (576.1) Maintenance of Structures and Improvements
126 (576.2) Maintenance of Computer Hardware
127 (576.3) Maintenance of Computer Software
128 (576.4) Maintenance of Communication Equipment
129 (576.5) Maintenance of Miscellaneous Market Operation Plant
130 Total Maintenance (Lines 125 thru 129)
131 TOTAL Regional Transmission and Market Op Expns (Total 123 and 130) I
132 4. DISTRIBUTION EXPENSES
133 Operation
134 (580) Operation Supervision and Engineering 2,195,6321 1,845,3761
135 (581) Load Dispatching
136 (582) Station Expenses 631,080 697,949
137 (583) Overhead Line Expenses 2,900,414 1,798,684
138 (584) Underground Line Expenses 1,054,524 -183,983
139 ,(585) Street Lighting and Signal System Expenses 166,256 . 273,778
140 (586) Meter Expenses 2,249,211 1,873,149
141 (587) Customer Installations Expenses 676,051 740,863
142 (588) Miscellaneous Expenses 7,563,8011 7,032,031
143 (589) Rents 352,1081 262,304
144 TOTAL Operation (Enter Total of lines 134 thru 143) 17,789,0771 14,340,151
145 Maintenance
146 (590) Maintenance Supervision and Engineering 1,720,093 1,148,214
147 (591) Maintenance of Structures 370,675 343,805
148 (592) Maintenance of Station Equipment 886,849 833,760
149 (593) Maintenance of Overhead Lines 8,225,646 8,049,756
150 (594) Maintenance of Underground Lines 1,007,658 1,021,119
151 (595) Maintenance of Line Transformers 972,946 2,832,509
152 (596) Maintenance of Street Lighting and Signal Systems 674,264 598,658
153 (597) Maintenance of Meters 62,373 102,477
154 (598) Maintenance of Miscellaneous Distribution Plant 495,770 493,719
155 TOTAL Maintenance (Total of lines 146 thru 154) 14,416,274 15424,017
156 TOTAL Distribution Expenses (Total of lines 144 and 155) 32,205,3511 29,764,168
15715. CUSTOMER ACCOUNTS EXPENSES
158 Operation
159 (901) Supervision 577,883 633,265
160 (902) Meter Reading Expenses 2,905,712 2,827,145
161 (903) Customer Records and Collection Expenses 8,191,471 8,056,519
162 (904) Uncollectible Accounts 2,129,547 2,631,760
163 (905) Miscellaneous Customer Accounts Expenses 229,446 138,558
164 1 TOTAL Customer Accounts Expenses (Total of lines 159 thru 163) 14,034,059 14,287,247
FERC FORM NO. I (ED. 12-93) Page 322
Name of Respondent
Avista Corporation
This Re ort Is: (1)An Original
(2)A Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES (Continued)
If the amount for previous year is not derived from previously reported figures, explain in footnote.
Line
N0.
Account
(a)
Amount for Current Year (b)
Anount fpr Previous Year
(c)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
167 (907) Supervision
168 (908) Customer Assistance Expenses 24,468,409 28,480,145
169 (909) Informational and Instructional Expenses 1,111,618 919,411
170 (910) Miscellaneous Customer Service and Informational Expenses 176,221 133,783
171 TOTAL Customer Service and Information Expenses (Total 167 thru 170) 25,756,248 29,533,339
172 7. SALES EXPENSES
173 Operation
174 (911) Supervision I
175 (912) Demonstrating and Selling Expenses 7,948 12,086
176 (913) Advertising Expenses 154
177 (916) Miscellaneous Sales Expenses -3,913
178 TOTAL Sales Expenses (Enter Total of lines 174 thru 177) 7,948 8,327
17918. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation
181 (920) Administrative and General Salaries 36,662,334 24,938,251
182 (921) Office Supplies and Expenses 4,136,952 4,059,668
133 (Less) (922) Administrative Expenses Transferred-Credit 65,805 61,444
184 (923) Outside Services Employed 11,659,879 14,466,792
185 (924) Property Insurance 1.325,546 1223,344
186 (925) Injuries and Damages 2,428,175 4,400,051
187 (926) Employee Pensions and Benefits 1,364,064 1,258,918
188 (927) Franchise Requirements 5,747 5,738
189 (928) Regulatory Commission Expenses 6,659,471 5,675,735
190 (929) (Less) Duplicate Charges-Cr.
191 (930.1) General Advertising Expenses 2,3941 1,087
192 (930.2) Miscellaneous General Expenses 3,255,3381 2,747,891
193 (931) Rents 1,032,6651 883,149
194 TOTAL Operation (Enter Total of lines 181 thru 193) 68,466,7601 59,599,180
195 Maintenance
196 (935) Maintenance of General Plant 7,813,751 8,015,884
197 TOTAL Administrative & General Expenses (Total of lines 194 and 196) 76,280,511 67,615,064
198 TOTAL Elec Op and Maint Expns (Total 80,112,131,156,164,171,178,197) 714,845,354 750,210,435
FERC FORM NO. 1 (ED. 12-93) Page 323
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)EA Resubmission 04/12/2013
PURCHASED POWER (Account 555) (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.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand I.! 0. . . (Footnote ,i,iadons Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (C) (d) (e) (f)
1 BP Corporation NA SF ISDA
2 BP Energy Comp SF WSPP
3 Barclays Bank PLC SF ISDA
4 Black Hills Power, Inc. SF WSPP
5 Bonneville Power Administration LF WNP#3 Agr.
6 Bonneville Power Administration SF WSPP
71 Bonneville Power Administration SF - Tariff #8
5 Bonneville Power Administration OS BPA OATT
9 Bonneville Power Administration SF BPA OATT
10 Brookfield Energy Marketing LP SF WSPP
11 Calpine Energy Services LP SF WSPP
12 1 Cargill Power Markets SF WSPP
13 Cargill Power Markets SF ISDA
14 City of Redding SF WSPP
Total
FERC FORM NO. I (ED. 12-90) Page 326
Name of Respondent This Report Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)flA Resubmission 04/12/2013
PUCHA PQWER(Accoupt 555) (Continued) (Including power exchanges)
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 (I). Explain in a footnote all components of the amount shown in column (I). 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 (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) No. Received Delivered ($) ($) ($) of Settlement ($)
(g) (h) (i) (j) (k) (I) (m)
15,837,095 15,837,095 1
219,559 10,235,099 10,235,099 2
2,543,595 2,543,595 3
10,075 298,187 298,187 4
400,152 15,306,06 15,306,064 5
229,831 3,651,694 3,651,694 6
19,570 375,448 375,448 7
-3,251 31,794 28,537 8
2,461 47,531 -85,033 -37,497 9
1,200 20,901 20,900 10
217,57 5,480,20 5,480,202 11
118,032 1,303,411 1,303,411 12
-2,964 -2,964 13
43 131 138 14
8,188,382 548,640 547,803 15,727,976 181,867,301 41761,152 239,356,421
FERC FORM NO. 1 (ED. 12-90) Page 327
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)A Resubmission 04/12/2013
PURCI'(ASED POWER Accout 555) (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. 'tong-term" means five years or longer. The availability and reliability of
service, aside from transmission constraints, must match the availability and reliability of the designated unit.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand 1.1 0. . (Footnote ,IliIIaLions) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
(a) (b) (c) (d) (e) (f)
1 City of Spokane LU PURPA
2 City of Spokane IU PURPA
3 Chelan County PUD IU Rocky Reach
4 Chelan County PUD SF WSPP
5 Chelan County PUD lU Chelan Sys
6 Citigroup Energy SF WSPP
7 Clark County PUD No. 1 SF WSPP
8 Clatskanie PUD SF WSPP
9 Constellation Energy Commodities Group SF WSPP
10 Douglas County PUD No. 1 LU Wells
11 Douglas County PUD No. 1 LU Wells Settlement
12 Douglas County PUD No. 1 IF Wells
13 Douglas County PUD No. 1 SF WSPP
14 Douglas County PUD No. I EX 305
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.1
Name of Respondent This Report Is: Date of Report Year/Period of Report
Avista Corporation (1)[X An Original (Mo, Da, Yr) End of 2012/Q4
(2)flA Resubmission 04/12/2013
PUkCHASEQ PQWER(Accoupt 555) (Continued) (Including power exchanges)
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 (I). Explain in a footnote all components of the amount shown in column (I). 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 (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) No. Received Delivered ($) of Settlement($)
(g) (h) (I) a) (k) (I) (m)
51,735 2,295,16C 2,295,160 1
140301 6,297,071 6,297,071 2
-15,02 3,194 3,194 3
5,82 34,444 34,444 4
332,941 11,383,976 11,383,976 5
147,151 2,916,118 2,916,118 6
10,741 147,657 147,657 7
7,991 65, 1 OC 65,100 8
4,151 27,597 27,597 9
139,651 1,578,461 1,578461 10
44,50 1, 1 37,85C 1,137,850 11
188,17 4,344,000 4,344,000 12
17,451 166,972 166,972 13
102,330 102,296 1,435,50C 667 1,436,167 14
8,188,382 548,640 547,803 15,727,976 181,867,301 41,761,152 239,356,421
FERC FORM NO. I (ED. 12-90) Page 327.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)x An Original
(2)flA Resubmission
(Mo, Da, Yr)
04112/2013 End of 2012/Q4
PURCHASED POWER (Account 555) (Including power excrianges)
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.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority StatLstical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (f)
1 DB Energy Trading LLC SF WSPP
2 DB Energy Trading LLC SF ISDA
3 EDF Trading No America SF WSPP
4 Eugene Water & Electric Board SF WSPP
5 Exelon Generation Company, LLC SF WSPP
6 Ford Hydro Limited Partnership LU PURPA
7 Grant County PUD No. 2 LU Priest Rapids
8 Grant County PUD No. 2 SF WSPP
9 Grant County PUD No 2 EX FERC #104
10 Hydro Technology Systems LU PURPA
11 lberdrola Renewables LLC SF WSPP
12 Idaho County Power & Light LU PURPA
13 Idaho Power Company SF WSPP
14 Idaho Power Company - Balancing SF WSPP
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.2
Name of Respondent I This Report Is: Date of Report Year/Period of Report
Avista Corporation End of 2012/04 L
AResubmission 04/12/2013
PU CHASED PQWER(Accoupt 555) (Continued) (Including power excnanges)
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 (I). Explain in a footnote all components of the amount shown in column (I). 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 (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
MegaWatt Hours MegaWatt Hours _____________ Demand Charges Energy Charges Other Charges Total (j+k+l) Purchased No. Received Delivered ($) of Settlement ($)
(g) (h) (i) (j) (k) (I) (m) -
79,37E 510,25C 510,250 1
-48,724 -48,724 2
194,544 4,090,834 4,090,839 3
9,044 112,57 112,578 4
400 9,80 9,800 5
3,23E 233,82E 233,826 6
332,137 5,716,927 5,716,927 7
26,03C 344,64E 344,648 8
12,864 12,864 9
11,14' 564,88( 564,880 10
368,841 3,744,374 3,744,374 11
2,22d 99,09! 99,095 12
32,41' 639,68l 639,689 13
88C 21,721 21,720 14
8,188,382 548,640 547,803 15,727,976 181,867,301 41,761,152 239,356,42
FERC FORM NO. 1 (ED. 12-90) Page 327.2
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original
(2)flA Resubmission
(Mo, Da, Yr)
04/12/2013 End of 2012/Q4
PURCHASED POWER (Account 5 5) (Including power excflanges)
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.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical
Classifi-
FERC Rate
Schedule or
Average
Monthly Billing
Actual Demand (MW)
Average Average
0. (Footnote r%I,I,laLlOns, cation Tariff Number Demand (MW) Monthly NCP Demand Monthly CP Demand
- (a) (b) (c) (d) (e) (f)
1 Inland Power & Light Company RQ 208
2 Jim White LU 1PURPA
3 J P Morgan Ventures Energy LLC SF WSPP
4 J P MorganVentures Energy LLC LU PPM Energy
5 J P Morgan Ventures Energy LLC SF ISDA
6 Kootenai Electric Cooperative lU PURPA
7 Macquarie Energy LLC SF WSPP
8 Modesto Irrigation District SF WSPP
9 Morgan Stanley Capital Group SF WSPP
10 Morgan Stanley Capital Group SF ISDA
11 Newedge USA LLC SF ISDA
12 NextEra Energy Power Marketing LLC SF WSPP
13 Noble America Gas & Power Corp. SF WSPP
14 NorthWestern Energy LLC SF WSPP
Total
FERC FORM NO. I (ED. 12-90) Page 326.3
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1) X An Original (Mo, Da, Yr) End of 20121Q4
I (2) [--JA Resubmission 04/12/2013
PUkCHAED PQWER(Account 555) (Continued) (Inc'udIng power exchanges)
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 repoñ 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 (I). 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 (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
Megawatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line MegaWatt Hours MegaWatt Hours Demand Charges Energy Charges Other Charges Total U+k+l) Purchased No. Received Delivered ($) ($) of Settlement ($)
(g) (h) (i) (j) (k) (I) (m)
92 5,78C 5,780 1
1,142 110,943 110,943 2
488,93E 10,975,404 10,975,404 3
80,35C 3,454,792 3,454,792 4
-3,357 -3,357 5
136,038 136,038 6
136,564 3,351,51 E 3,351,516 7
67E 6758
264,761 6,276,07E 6,276,079 9
2,540,145 2,540,145 10
16,639,357 16,639,357 11
11,64C 18,12C 18,120 12
6,20C 65,70C 65,70013
95,13 2,652,684 2,652,684 14
8,188,382 548,640 547,803 15,727,976 181,867,301 41,761,152 239,356,421
FERC FORM NO.1 (ED. 12-90) Page 3273
Name of Respondent This Re ort Is: Date of Repot Year/Period of Report
Avista Corporation (1)X An Original
(2)EA Resubmission
(Mo,Da, Yr)
04112/2013 End of 2012/Q4
PURCHA$ED POWER (Account 555) (Including power excflanges)
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.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical
Classifi-
FERC Rate
Schedule or
Average
Monthly Billing
Actual Demand (MW)
Average Average
0. (Footnote Affiliations) cation Tariff Number Demand (MW) Monthly NCP Deman Monthly CP Demand
- (a) (b) (c) (d) (e) (f)
1 Okanogan County PUD No. 1 SF WSPP
2 PPL Energy Plus SF WSPP
3 PacifiCorp SF WSPP
4 Palouse Wind LLC LU PPA
5 Pend Oreille County PUD No. 1 SF Pend 0'
6 Pend Oreille County PUD No I SF Pend 0
7 Phillips Ranch LU PURPA
8 Portland General Electric Company EX 304
9 Portland General Electric Company EX 178
10 Portland General Electric Company SF WSPP
11 Potlatch Corporation LU PURPA
12 Powerex Corp SF WSPP
13 Powerex Corp SF ISDA
14 Puget Sound Energy SF WSPP
Total
FERC FORM NO. I (ED. 12-90) Page 326.4
Name of Respondent I This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1) x An Original
i .
(Mo, Da, Yr) End of 2012/Q4
I (2) A Resubmission 04/12/2013
PUkCHAE POWER(Accoujit 555) (Continued) (Including power exchanges)
AD - for out-of-period adjustment. Use this code for any accounting adjustments or "true-ups" for service provided in prior reporting
years. Pro4dé 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 (I). Explain in a footnote all components of the amount shown in column (I). 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 (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
Megawatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Megawatt Hours Megawatt Hours Demand Charges _______________ Energy Charges Other Charges Total (j+k+I) Purchased No.
Received Delivered ($) ($) of Settlement ($)
(9) (h) (i) (j) (k) (I) (m) -
3,25 30,893 30,893 1
1,034,36 21,297,776 21,297,776 2
57,264 932,601 932,603 3
61,45( 1,779,691 1,779,694 4
20,83' 356,19 356,190 5
106,34A 4,849 4,493 2,146,75 -4,091 2,142,668 6
47 2,33 2,333 7
431,507 431,057 8
9,954 9,743 42,035 42,035 9
16,707 284,869 284,869 10
421,680 18,098,506 18,098,506 11
39,424 611,644 611,644 12
411,624 411,624 13
37,12E 516,995 516,995 14
8,188,382 548,640 547,803 15,727,976 181,867,301 41,761,1521 239,356,42
FERC FORM NO. 1 (ED. 12-90) Page 327.4
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original
(2)A Resubmission
(Mo, Da, Yr)
04/1212013 End of 2012/04
PURCHASED POWER (Account 5 5) (Including power excrianges)
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.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (c) (d) (e) (U
1 Rainbow Energy Marketing Corp SF WSPP
2 Pacramento Municipal Utility District SF WSPP
3 San Diego Gas & Electric SF WSPP
4 Seattle City Light SF WSPP
5 Sheep Creek Hydro LU PURPA
6 Shell Energy SF ISDA
7 Shell Energy SF WSPP
8 Sierra Pacific Power Company SF WSPP
9 Snohomish County PUD No. 1 SF WSPP
10 Southern California Edison Co. SF WSPP
11 Sovereign Power IF Sovereign
12 Spokane County LU PURPA
13 Stimson Lumber lU PURPA
14 Tacoma Power SF WSPP
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.5
Name of Respondent I This Report Is: Date of Report Year/Period of Report
Avista Corporation rpora i (1)x An Original
(2)EA Resubmission
(Mo, Da, Yr)
04/12/2013 End of 2012/04
PUkCHASED PQWER(Account 555) (Continued) (Including power excnanges)
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 (I). Explain in a footnote all components of the amount shown in column (I). 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 (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
B. The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (I) must be reported as Exchange Delivered on Page 401, line 13.
9. Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased Megawatt Hours MegaWatt Hours Demand Charges ______________ Energy Charges Other Charges Total (jlk+l) No.
Received Delivered ($) ($) ($) of Settlement($)
(g) (h) (i) (j) (k) (I) (m)
29,939 663,683 663,683 1
1,40 28,050 28,050 2
49', 10,385 3
49,79 866,90 866,905 4
7,241 288,30; 288,303 5
3,221,028 3,221,028 6
321,87E 4,404,33; 4,404,333 7
62 14,02' 14,026 8
31,561 360,02' 360,020 9
101 loi
7,29; 113,58' 113,58611
1,35 82,26; 82,262 12
35,38; 1,759,42 1,759,425 13
7957 2,682,815 2,682,815 14
8,188,382 548,640 547,803 15,727,976 181,867,301 41,761,152 239,358,42
FERC FORM NO. I (ED. 12-90) Page 327.5
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original
(2)LJA Resubmission
(Mo, Da, Yr)
04/12/2013 End of 2012/Q4
PURCHASED POWER Account 555) (Incluciing power excrianges)
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.
lU - for intermediate-term service from a designated generating unit. The same as LU service expect that "intermediate-term" means
longer than one year but less than five years.
EX - For exchanges of electricity. Use this category for transactions involving a balancing of debits and credits for energy, capacity, etc.
and any settlements for imbalanced exchanges.
OS - for other service. Use this category only for those services which cannot be placed in the above-defined categories, such as all
non-firm service regardless of the Length of the contract and service from designated units of Less than one year. Describe the nature
of the service in a footnote for each adjustment.
Line Name of Company or Public Authority Statistical FERC Rate Average Actual Demand (MW)
Average
Monthly NCP Demand
Average
Monthly CP Demand No. (Footnote Affiliations) Classifi-
cation
Schedule or
Tariff Number
Monthly Billing
Demand (MW)
- (a) (b) (C) (d) (e) (f)
1 Tenaska Power Services Company SF WSPP
2 The Energy Authority SF JWSPP
3 TransAlta Energy Marketing SF WSPP
4 Tri-State Generation & Transmission As SF WSPP
5 IntraCompany Generation Services OS OATT
6 Rathdrum Power LLC LF Lancaster
7 Other -Inadvertent Interchange EX
8
9
10
11
12
13
14
Total
FERC FORM NO. 1 (ED. 12-90) Page 326.6
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation (1)X An Original (Mo, Da, Yr) End of 2012/Q4
(2)[-]A Resubmission 04/12/2013
PUCKASED PQWER(Account 555) (Continued) (Including power exchanges)
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 (1. 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 (I). Explain in a footnote all components of the amount shown in column (I). 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 (I)
include credits or charges other than incremental generation expenses, or (2) excludes certain credits or charges covered by the
agreement, provide an explanatory footnote.
8.The data in column (g) through (m) must be totalled on the last line of the schedule. The total amount in column (g) must be
reported as Purchases on Page 401, line 10. The total amount in column (h) must be reported as Exchange Received on Page 401,
line 12. The total amount in column (i) must be reported as Exchange Delivered on Page 401, line 13.
9.Footnote entries as required and provide explanations following all required data.
MegaWatt Hours POWER EXCHANGES COST/SETTLEMENT OF POWER Line
Purchased Megawatt Hours Megawatt Hours Demand Charges Energy Charges Other Charges Total (j+k+l) No Received Delivered ($) M of Settlement ($)
(g) (h) (1) (j) (k) (I) (m)
10,640 289,466 289,466 1
37,948 309,082 309,082 2
125,421 3,786,59: 3,786,592 3
2,090 25,101 25,109 4
625,117 625,117 5
1,208,441 24,167,99 24,167,993 6
214 7
8
9
10
11
12
13
14
8,188,382 548,640 547,803 15,727,976 181,867,301 41,761,152 239,356,42
FERC FORM NO. I (ED. 12-90) Page 327.6
Schedule Page: 326 Line No.: I Column: a
Fianncial SWAP
ISchedule Page: 326 Line No.: 3 Column: a
Financial SWAP
ISchedule Page: 326 Line No.: 8 Column: a
Ancillary Services - Spinning & Supplemental
ISchedule Pace: 326 Line No.: 9 Column: a
Non Moneta
fSchedule Page: 326 Line No.: 13 Column: a I
Financial SWAP
lSchedule Page: 326.1 Line No.: 14 Column: a I
Non Monetary
lSchedule Page: 326.2 Line No.: 2 Column: a I
Financial SWAP
lSchedule Page: 326.2 Line No.: 9 Column: a I
Non Monetary
Schedule Page: 326.3 Line No.: I Column: a I
Service to Deer Lake from Inland Power and Light. No demand charges associated with the
agreement.
Schedule Pace: 326.3 Line No.: 5 Column: a
Financial SWAP
ISchedule Page: 326.3 Line No.: 10 Column: a
Financial SWAP
ISchedule Page: 326.3 Line No.: 11 Column: a I
Financial SWAP
lSchedule Page: 326.4 Line No.: 6 Column: a
Non Monetary
lSchedule Page: 326.4 Line No.: 9 Column: a I
Non Monetary
Schedule Page: 326.4 Line No.: 13 Column: a I
Financial SWAP
ISchedule Pace: 326.5 Line No.: 6 Column: a
Financial Swap
ISchedule Page: 326.6 Line No.: 5 Column: a
Ancillary Services
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
I This Re ort Is:
(1)X An Original
(2)flA Resubmission
I Date of Report (Mo, Da, Yr)
I 04/1212013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OThEkS (Account 456.1) (Including transactions referred to as 'wheeling')
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.
Line
N °.
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 PacifiCorp PacifiCorp PacifiCorp LFP
2 Seattle City Light Seattle City Light Grant County PUD LFP
3 Tacoma City Light Tacoma City Light Grant County PUD LFP
4 Grant County Public Utility District Grant County Public Utility Distr Grant County Public Utility Distr LFP
5 Spokane Indian Tribes Bonneville Power Administration Spokane Indian Tribes LFP
6 USBR Bonneville Power Administration East Greenacres LFP
7 Consolidated Irrigation District Bonneville Power Administration Consolidated Irrigation District LFP
8 Bonneville Power Administration Bonneville Power Administration Bonneville Power Administration FNO
9 City of Spokane City of Spokane Avista Corporation OS
10 Stimpson Plummet Avista Corporation OS
11 Hydro Tech Industries Meyers Falls Avista Corporation OS
12 Palouse Wind Palouse Wind Avista Corporation OS
13 Kootenai Electric Cooperative Kootenai Electric Cooperative Avista Corporation OS
14 Coral Power Bonneville Power Administration Northwestern Montana SFP
15 Cargill Power Markets Bonneville Power Administration Idaho Power Company SFP
16 Cargill Power Markets Northwestern Montana Avista Corporation SFP
17 Cargill Power Markets Northwestern Montana Bonneville Power Administration SEP
18 Cargill Power Markets Northwestern Montana Chelan County PUD SFP
19 Cargill Power Markets Northwestern Montana PacifiCorp SFP
20 Morgan Stanley Capital Group Bonneville Power Administration Northwestern Montana SFP
21 Morgan Stanley Capital Group Northwestern Montana Bonneville Power Administration SEP
22 Norgan Stanley Capital Group Northwestern Montana Chelan County PUD SFP
23 Morgan Stanley Capital Group Northwestern Montana Grant County PUD SFP
24 Morgan Stanley Capital Group Puget Sound Energy Northwestern Montana SFP
25 Morgan Stanley Capital Group Grant County PUD Northwestern Montana SEP
26 Morgan Stanley Capital Group Chelan County PUD Idaho Power Company SFP
27 Morgan Stanley Capital Group Chelan County PUD Northwestern Montana SEP
28 Bonneville Power Administration Bonneville Power Administration Idaho Power Company SEP
29 Portland General Electric Northwestern Montana Bonneville Power Administration SFP
30 Idaho Power Company Bonneville Power Administration Idaho Power Company SFP
31 Idaho Power Company Idaho Power Company Bonneville Power Administration SFP
32 Idaho Power Company LSE Bonneville Power Administration Idaho Power Company SEP
33 Idaho Power Company LSE Bonneville Power Administration PacifiCorp SEP
34 Idaho Power Company LSE Northwestern Montana Bonneville Power Administration SFP
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328
Name of Respondent
Avista Corporation
I This Report Is:
(1)Original
(2)DA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as wheeling')
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 Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.
-
MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered U)
FERC No. 182 Dry Creek Walla Wall Dry Gulch 20 56,261 56,261 1
FERC Trf No. 8 Chelan-Stratford 115 Stratford 115kV SS 238,208 238,208 2
FERC Trf No. 8 Chelan-Stratford 115 Stratford 11 5k SS 238,208 238,208 3
FERC No. 104 Stratford Substation Coulee Cy/Wilson Crk 25 88,595 88,595 4
FERC Trf No. 8 Westside Little Falls 1 3,035 3,03f 5
FERC Trf No. 8 Bell Substation Post Falls 3 3,210 3,21 6
FERC Trf No. 8 Bell Substation BKRIOPT/EFM/LIB 3 5,840 5,84 7
FERCTrINo. 8 1,814,455 1,814,451 8
FERC No. 155 Sunset-Westside 115k Westside
FERC Trf No. 8 AVA Syst AVA Syst 10
FERCTrf No. 8 11
FERC Trf No. 8 12
FERCTrf No. 8
FERCTrf No.8 4,108 4,101 14
FERC Trf No. 8 9,777 9,777 15
FERC Trf No. 8 400 40( 16
FERC Trf No. 8 8,840 8,84( 17
FERC Trf No. 8 3,288 3,281 18
FERC Trf No. 8 800 80( 19
FERCTrI No. 8 10 11 20
FERC Trf No. 8 55 51 21
FERC Trf No. 8 5,752 5,75 22
FERC Trf No. 8 175 171 23
FERCTrf No. 8 10 11 24
FERC Trf No. 8 5,540 5,541 25
FERC Trf No. 8 162 16 26
FERC Trf No. 8 22 Z 27
FERCTrfNo. 8 21,941 21,941 28
FERCTrf No. 8 12,105 12,101 29
FERC Tnt No. 8 57,240 57,241 30
FERC Tnt nO. 6,400 6,401 31
FERC Trf No. 8 279,786 279,781 32
FERC Trf No. 8 800 801 33
FERCTrf No. 8 15 11 34
1 1 i 52 3,191,975 3,191,971 -
FERC FORM NO. 1 (ED. 12-90) Page 329
Name of Respondent
Avista Corporation
This Re ort Is:
(1)X An Original
(2)QA Resubmission
Date of Report
(Mo, Da, Yr)
04/1212013
Year/Period of Report
End of 20121Q4
TRANSMISSION OF ELtL; FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as Wheeling')
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.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
214,489 214,489 1
150,992 30,930 181,922 2
150,992 30,930 181,922 3
26,707 26,707 4
23,746 23,746 5
16,517 16,517 6
38,837 38,837 7
6992,205 6,992,205 8
27,973 27,973 9
9,480 9,480 10
6,120 6,120 11
200,000 200,000 12
6,073 6,073 13
42,458 42,458 14
100,607 100,607 15
1,538 1,538 16
33,386 33,386 17
13,225 13,225 18
3,077 3,077 19
9,230 9,230 20
883 88321
50,629 50,629 22
2,431 2,431 23
4,615 4,615 24
45,183 45,183 25
2,894 2,894 26
393 393 27
258,163 258,163 28
69,225 69,225 29
304,590 304,590 30
27,690 27,690 31
1,073,182 1,073,182 32
2,492 2,492 33
50 5034
11,330,248 0 311,506 11,641,754
FERC FORM NO. I (ED. 12-90) Page 330
Name of Respondent
Avista Corporation
I This Report Is:
(1)X An Original
(2)flA Resubmission
I Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as wheeling)
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, OLE - Other Long-Term Firm Transmission Service, SFP - Short-Term Firm Point to Point Transmission
Reservation, NE - 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.
Line
No
-
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Idaho Power Company LSE PacifiCorp Idaho Power Company SFP
2 Idaho Power Company LSE PacifiCorp Northwestern Montana SEP
3 Idaho Power Company LSE Idaho Power Company Bonneville Power Administration SEP
4 Powerex Bonneville Power Administration Idaho Power Company SEP
5 Powerex Bonneville Power Administration Northwestern Montana SEP
6 Rainbow Energy Marketing Corporation Avista Corporation Bonneville Power Administration SFP
7 Rainbow Energy Marketing Corporation Bonneville Power Administration Idaho Power Company SEP
8 Rainbow Energy Marketing Corporation Douglas County PUD Idaho Power Company SEP
9 PacifiCorp PacifiCorp Bonneville Power Administration SEP
10 Coral Power Bonneville Power Administration Northwestern Montana NE
11 Coral Power Northwestern Montana Bonneville Power Administration NF
12 Coral Power Northwestern Montana Chelan County PUD NF
13 Coral Power Northwestern Montana Grant County PUD NE
14 Coral Power Grant County PUD Northwestern Montana NF
15 Coral Power Chelan County PUD Idaho Power Company NF
16 Coral Power Chelan County PUD Northwestern Montana NF
17 Cargill Power Markets Avista Corporation Northwestern Montana NE
18 Cargill Power Markets Bonneville Power Administration Idaho Power Company NF
19 Cargill Power Markets Bonneville Power Administration Northwestern Montana NF
20 Cargill Power Markets Northwestern Montana Bonneville Power Administration NE
21 Cargill Power Markets Northwestern Montana Chelan County PUD NE
22 Cargill Power Markets Northwestern Montana Idaho Power Company NE
23 Cargill Power Markets Northwestern Montana Avista Corporation NE
24 PPL Energy Plus Bonneville Power Administration Idaho Power Company NE
25 PPL Energy Plus Bonneville Power Administration Northwestern Montana NE
26 PPL Energy Plus Northwestern Montana Bonneville Power Administration NE
27 PPL Energy Plus Northwestern Montana Chelan County PUD - NE
28 PPL Energy Plus Northwestern Montana Idaho Power Company - NE
29 PPL Energy Plus Northwestern Montana Grant County PUD NE
30 Morgan Stanley Capital Group Bonneville Power Administration Chelan County PUD NE
31 Morgan Stanley Capital Group Bonneville Power Administration Idaho Power Company NE
32 Morgan Stanley Capital Group Bonneville Power Administration Northwestern Montana NE
33 Morgan Stanley Capital Group Northwestern Montana Bonneville Power Administration NF
34 Morgan Stanley Capital Group Northwestern Montana Chelan County PUD NE
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.1
Name of Respondent
Avista Corporation I
I This Re ort Is:
(1)X An Original
(2)Q Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/04
TRANSMISSIONOF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as 'wheeling')
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 Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.
-
MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered
(j)
FERC Trf No. 8 34,751 34,751 1
FERC Trf No. 8 192 192 2
FERC Trf No. 8 174 174 3
FERCTrf No. 8 8,158 8,158 4
FERC Trf No. 8 204 204 5
FERC Trf No. 8 1,275 1,275 6
FERC Trf No. 8 33,764 33,764 7
FERC Trf No. 8 704 70 8
FERC Trf No. 8 1,301 1,301 9
FERCTrfNo. 8 12,450 12,45 10
FERC Trf No. 8 2,579 2,57 11
FERCTrf No. 8 4,134 4,13 12
FERC Trf No. 8 1,273 1,27 13
FERC Trf No. 8 20 2' 14
FERCTrf No. 8 6 15
FERCTrf No. 8 113 11 16
FERC Trf No. 8 273 271 17
FERCTrfNo. 8 14,687 14,68 18
FERC Trf No. 8 1,843 1,84 19
FERC Trf No. 8 1,000 1,00 20
FERC Trt No. 8 440 44 21
FERC Tnt No. 8 367 36 22
FERC Trf No. 8 800 80( 23
FERC Trf No. 8 25 2 24
FERC Trf No. 8 3,871 3,871 25
FERCTrfNo. 8 1,510 1,51( 26
FERC Tnt No. 8 30 3( 27
FERC Trf No. 8 985 98 28
FERC Tnt No. 8 50 5( 29
FERC Trf No. 8 50 5( 30
FERCTrf No. 8 143 14 31
FERC Trf No. 8 824 82 32
FERC Tnt No. 8 18,001 18,001 33
FERC Trf No. 8 1,681 1,681 34
52 3,191,9751 3,191 ,97l
FERC FORM NO.1 (ED. 12-90) Page 329.1
Name of Respondent
Avista Corporation
This Re ort Is:
2:ssion
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions reffered to as wheeling)
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 U) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
Line
No.
-
147,137 147,137 1
640 640 2
580 580 3
89,908 89,908 4
1,561 1,561 5
6,606 6,606 6
146,584 146,584 7
3,720 3,720 8
73,840 73,840 9
43,983 43,983 10
16,075 16,075 11
24,922 24,922 12
7,960 7,960 13
57 5714
42 4215
735 735 16
733 733 17
37,735 37,735 18
7,163 7,163 19
8,623 8,623 20
4,441 4,441 21
10,000 10,000
2,613 2,613 23
147 147 24
22,901 22,901 25
9,274 9,274 26
173 . 173 27
5,710 5,710 28
362 362 29
251 251 30
902 902 31
5,116 5,116 32
109,523 109,523 33
10,455 10,455 34
11,330,248 0 311,506 11,641,754
FERC FORM NO. 1 (ED. 12-90) Page 330.1
Name of Respondent
Avista Corporation
This Re ort Is:
I (1) X An Original

(2) flA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION ELECTRICITY FOR OTHERS (Account 456.1) (Including transactions referred to as wheeling')
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.
Line
No
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(C)
Statistical
Classifi-
cation
(d)
I Morgan Stanley Capital Group Northwestern Montana Idaho Power Company NF
2 Morgan Stanley Capital Group Northwestern Montana Grant County PUD NF
3 Morgan Stanley Capital Group Chelan County PUD Bonneville Power Administration NF
4 Morgan Stanley Capital Group Chelan County PUD Idaho Power Company NF
5 Morgan Stanley Capital Group Chelan County PUD Northwestern Montana NF
6 Naturener Bonneville Power Administration Northwestern Montana NF
7 Northwestern Energy Bonneville Power Administration Northwestern Montana NF
8 Norwestern Energy Northwestern Montana Bonneville Power Administration NF
9 Powerex Bonneville Power Administration Idaho Power Company NF
10 Powerex Bonneville Power Administration Northwestern Montana NF
11 Powerex Bonneville Power Administration Puget Sound Energy NF
12 Powerex Northwest Montana Bonneville Power Administration NF
13 Powerex Puget Sound Energy Idaho Power Company NF
14 Powerex Grant County PUD Idaho Power Company NF
15. Powerex Chelan County PUD Northwestern Montana NF
16 Bonneville Power Administration Bonneville Power Administration Idaho Power Company NF
17 Bonneville Power Administration Idaho Power Company Bonneville Power Administration NF
18 Portland General Electric Northwestern Montana Bonneville Power Administration NF
19 Portland General Electric Northwestern Montana Portland General Electric NF
20 PPM Energy Bonneville Power Administration Idaho Power Company NF
21 Puget Sound Energy Northwestern Montana Bonneville Power Administration NF
22 Puget Sound Energy Idaho Power Company Bonneville Power Administration NF
23 Idaho Power Company Avista Corporation Bonneville Power Administration NF
24 Idaho Power Company Bonneville Power Company Idaho Power Company NF
25 Idaho Power Company PacifiCorp Idaho Power Company NF
26 Idaho Power Company PacifiCorp Northwestern Montan NF
27 Idaho Power Company Idaho Power Company Bonneville Power Administration NF
28 Grant County PUD Avista Corporation Grant County PUD NF
29 Idaho Power Company LSE Bonneville Power Administration Idaho Power Company NF
30 Idaho Power Company LSE Pacif'iCorp Idaho Power Company NF
31 Idaho Power Company LSE PacifiCorp Northwestern Montana NF
32 1 The Energy Authority Bonneville Power Administration Northwestern Montana NF
33 The Energy Authority Northwestern Montana Bonneville Power Administration NF
34 TransAlta Energy Marketing Bonneville Power Administration Idaho Power Company NF
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.2
Name of Respondent
Avista Corporation
I This Report Is:
AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456)(Continued) (Including transactions reffered to as wheeling')
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 Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No. MegaWatt Hours
Received (i)
MegaWatt Hours
Delivered
FERC Trf No. 8 72 72 1
FERC Trf No. 8 277 277 2
FERC Trf No. 8 68 68 3
FERC Trf No. 8 81 81 4
FERCTrf No. 8 53 53 5
FERC Trf No. 8 24 21 6
FERC Trf No. 8 1,789 1,789 7
FERC Trf No. 8 459 459 8
FERC Trf No. 8 20,421 20,421 9
FERC Trf No. 8 4,407 4,407 10
FERC Trf No. 8 71 71 11
FERC Trf No. 8 81 81 12
FERCTif No. 8 101 10113
FERC Trf No. 8 35 35 14
FERC Trf No. 8 754 754 15
FERC Trf No. 8 60,832 60,832 16
FERC Trf No. 8 556 551 17
FERCTrf No. 8 1,014 1,014 18
FERC Trf No. 8 697 697 19
FERC Trf No. 8 174 174 20
FERC Trf No. 8
FERC Trf No. 8 325 32l 22
FERC Trf No. 8 2,256 2,251 23
FERC Trf No. 8 11,789 11,78 24
FERC T No. 8 3,399 3,39I 25
FERC Trf No. 8 150 1 5( 26
FERCTrI No.8 1,366 1,361 27
FERCTrf No. 8
FERCTrINo. 8 31,735 31,739 29
FERC Trf No. 8 400 401 30
FERC Trf No. 8 269 26 31
FERC Trf No. 81 90 91 32
FERCTrf No.8 180 181 33
FERCTrf No. 8 16 11 34
52 3,191,975 3,191,97'
FERC FORM NO. I (ED. 12-90) Page 329.2
Name of Respondent
Avista Corporation
This Re ort Is:
2rssion
Date of Report Year/Period of Report
End of 20121Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued) (Including transactions refiered to as 'wheeling')
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.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+l+m)
(n)
13i11
No.
-
482 482 1
2,386 2,386 2
442 442 3
588 588 4
385 385 5
138 138 6
10,323 10,323 7
2,966 2,966 8
97,794 97,794 9
21,735 21,735 10
142 142 11
943 943 12
806 806 13
356 356 14
6,016 6,016 15
208,090 208,090 16
1,996 1,996 17
6,532 6,532 18
4,143 4,143 19
3,225 3,225 20
144 144 21
1,875 1,875 22
6,716 6,716 23
79,968 79,968 24
20,902 20,902 25
922 922 26
8,143 8,143 27
2,423 2,423 28
130,602 130,602 29
2,337 2,337 30
2,122 2,122 31
664 66432
1,039 1,039 33
410 410 34
11,330,248 0 311,506 11,641,754
FERC FORM NO. 1 (ED. 12-90) Page 330.2
Name of Respondent
Avista Corporation
I This Re ort Is:
(1)x An Original
(2)flA Resubmission
I Date of Report
(Mo, Da, Yr)
04/1212013
Year/Period of Report
End of 2012/04
TRANSMISSION ELECTRICITY FOR OTHERS 456.1)
(Including transactions referred to as 'wheeling')
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, ENS - Firm Network Transmission Service for Self, LFP - "Long-Term Firm Point to Point
Transmission Service, OLE - Other Long-Term Firm Transmission Service, SEP - Short-Term Firm Point to Point Transmission
Reservation, NE - 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.
Line
No
Payment By
(Company of Public Authority)
(Footnote Affiliation)
(a)
Energy Received From
(Company of Public Authority)
(Footnote Affiliation)
(b)
Energy Delivered To
(Company of Public Authority)
(Footnote Affiliation)
(c)
Statistical
Classifi-
cation
(d)
1 Sierra Pacific Power Company Bonneville Power Administration Idaho Power Company NF
2 PacifiCorp PacifiCorp Idaho Power Company NF
3 j Tri-State G & T Avista Corporation Bonneville Power Administration NF
4 Tri-State G & T Bonneville Power Administration Northwestern Montana NF
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
34
TOTAL
FERC FORM NO. I (ED. 12-90) Page 328.3
Name of Respondent
Avista Corporation
This Re ort Is: Date of Report
V213
Year/Period of Report
End of 2012/Q4
TRANSMISSIO OF ELECTRICITY FOR OThERS (Account 456)(Contiriued) (Including transactions reffered to as 'wheeling')
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 Rate
Schedule of
Tariff Number
(e)
Point of Receipt
(Subsatation or Other
Designation)
(f)
Point of Delivery
(Substation or Other
Designation)
(g)
Billing
Demand
(MW)
(h)
TRANSFER OF ENERGY Line
No.
-
MegaWatt Hours
Received (I)
Megawatt Hours
Delivered 0)
FERC Trf No. 8 230 230 1
FERC Trf No. 8 33,822 33,822 2
FERC Trf No. 8 362 36 3
FERC Trf No. 8 904 904 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
52 3,191,975 3,191,97
FERC FORM NO. I (ED. 12-90) Page 329.3
Name of Respondent
Avista Corporation
This Report Is:
Original
Date of Report
04/12/2013
Year/Period of Report
End of 20121Q4
TRANSMISSION OF ELECTRICITY FOR OTHERS (Account 456) (Continued)
(Including transactions reffered to as 'wheeling)
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 U) must be reported as Transmission Received and Transmission Delivered for annual report
purposes only on Page 401, Lines 16 and 17, respectively.
11.Footnote entries and provide explanations following all required data.
REVENUE FROM TRANSMISSION OF ELECTRICITY FOR OTHERS
Demand Charges
($)
(k)
Energy Charges
($)
(I)
(Other Charges)
($)
(m)
Total Revenues ($)
(k+I+m)
(n)
Line
No.
-
1,327 1,327 1
232,473 232,473 2
2,229 2,229 3
5,566 5,566 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
11,330,248 0 311,506 11,641,754
FERC FORM NO. 1 (ED. 12-90) Page 330.3
ISchedule Page: 328 Line No.: 2 Column: m I
Use of facilities
ISchedule Page: 328 Line No.: 3 Column: m I
Use of facilities
ISchedule Page: 328 Line No.: 9 Column: m I
Use of facilities
lSchedule Page: 328 Line No.: 10 Column: m I
Use of facilities
lSchedule Page: 328 Line No.: 11 Column: m I
Use of facilities
Schedule Page: 328 Line No.: 12 Column: m I
Deferral fee for long-term firm agreement.
ISchedule Page: 328 Line No.: 13 Column: m I
Forfeited long term point to point transmission deposit.
This Page Intentionally Left Blank
Name of Respondent This Rort Is: ep I Date of Report Year/Period of Report
Avista Corporation (1)An Original (Mo, Da, Yr) End of 2012/04
(2)flA Resubmission 04/1212013
TRANSMISSION OF ELECTRICITY BY OTHES (Account 565)
(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, SEP - Short-Term Firm Point-to- Point Transmission Reservations, NE - 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.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No. Name of Company or Public
Authority (Footnote Affiliations)
Statistical
Classification
Mah9awatt
Received
Mg0 Vtt- urs
Delivered
ma ($?es

rgy
($?
cuther
($?
Total Cost of
lAission
(a) (b) (C) (d) (e) (t) (g) (h)
1 Bonneville Power Admin LFP 1,496,931 1,496,931
2 Bonneville Power Adniin LFP 11,076480 1,749,048 12,825,528
3 Bonneville Power Admin LFP 788,748 788,748
4 Bonneville Power Admin OS 24,360 24,360
5 Bonneville PowerAdmin ENS 1,030,177 131,833 1,162,010
6 Bonneville Power Admin NE 20,986 20,986 90,870 -25,842 65,028
7 1 Benton County PUD No. 1 NE 2,0031 2,003 2,169 2,169
8 Clark County PUD No. 1 NE 566 566 651 651
9 Grays Harbor County PUD NF 115 115 135 135
10 Klickitat PUD NF 45 45 45 45
11 Kootenai Electric Coop LEP 45,222 45,222
12 Northern Lights LEP 133,517 133,517
13 NorthWestern Energy SEP 179,362 12,713 192,075
14 NorthWestern Energy NE 17,731 17,731 76,775 76,775
15 Portland General Elec LFP 628,000 14,989 642,989
16 Portland General Elec NE 5,128 5,128 7,442 7,442
TOTAL 112,11 112,114 15,378,437 266,076 1,907,101 17,551,614
FERC FORM NO. 1/3-0 (REV. 02-04) Page 332
This Page Intentionally Left Blank
Name of Respondent I This Report Is: Date of Report Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr) End of 2012/04
I (2) pA Resubmission 04/12/2013
TRANSMISSION OF ELECTRICITY BY OTHERS (Account 565)
(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.
Line TRANSFER OF ENERGY EXPENSES FOR TRANSMISSION OF ELECTRICITY BY OTHER
No. Name of Company or Public Statistical
Classification
Maawatt
Received
Ma1,gawatt- ours
Delivered ($?es
Demand
($
rS r? jç Cost of
Authority (Footnote Affiliations)
- (a) (b) (c) (d) (e) (f) (g) (h)
1 Puget Sound Energy NF 22,085 22,085 29,169 29,169
2 Seattle City Light NF 43,113 43,113 58,298 58,298
3 Tacoma Power NF 342 342 522 522
4
5
6
7
8
9
10
11
12
13
14
15
16
TOTAL 112,11 112,114 15,378,437 266,076 1,907,101 17,551,614
FERC FORM NO. 113-Q (REV. 02-04) Page 332.1
Schedule Page: 332 Line No.: 2 Column: g I
Ancillary Services
ISchedule Page: 332 Line No.: 4 Column: g I
Use of Facilities
ISchedule Page: 332 Line No.: 5 Column: g I
Ancillary Services
Schedule Page: 332 Line No.: 6 Column: g
Out of Period Adjustments
ISchedule Page: 332 Line No.: 13 Column: g I
Ancillary Services
[Schedule Page: 332 Line No.: 15 Column: g I
Ancillary Services
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Rort Is: (1)LxJ An Original
(2)E A Resubmission
Date of Report (Mo, Da, YO
04/12/2013
Year/Period of Report
End of 2012/Q4
MISCELLANEOUS - GENERAL EXPENSES (Account 930.2) (ELECTRIC)
Line
No. Description (a
Amount
(b)
1 Industry Association Dues 769,943
2 Nuclear Power Research Expenses
3 Other Experimental and General Research Expenses
4 Pub & Dist Info to Stkhldrs ... expn servicing outstanding Securities 106,896
5 0th Expn —5,000 show purpose recipient amount Group if < $5,000 1 ,421,612
6 Community Relations 203,174
7 Other Misc & General Expenses 644
8 Directors Fees and Expenses 611,507
9 Education and Informational 141,562
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 TOTAL 3,255,339
FERC FORM NO. 1 (ED. 12-94) Page 335
Schedule Page: 335 Line No.: 5 Column: b I
Schedule Page: 335 Line No.: 5 I
Vendor Purpos Amount
e
Vendors Under $5000 132,017.11
ALDERBROOK RESORT & SPA Employee Lodging 4,019.44
AMEREN Professional Services 7,048.06
AMERICAN GAS ASSOCIATION Miscellaneous .00
AMERICAN STOCK TRANSFER & TRUST CO General Services 5,801.70
AZAR'S FOOD SERVICES Employee Business 8,076.95
Meals
BROADRIDGE ICS General Services 59,207.85
CITIBANK NA Miscellaneous 44,785.65
COATES KOKES Professional Services 5,298.42
COMPUTERSHARE SHAREOWNER Postage 75,420.89
SERVICES LLC
CORP CREDIT CARD Telecommunication Use 134,155.55
CORPORATE RISK SOLUTIONS INC Professional Services 18,342.40
CUTAWAY MEDIA Miscellaneous 5,043.08
DAVID D HOLMES Office Supplies 5,736.96
DAVIS HIBBITTS & MIDGHALL INC Professional Services 9,906.05
DAVIS WRIGHT TREMAINE LLP Miscellaneous 9,499.44
DENNIS P VERMILLION Employee Misc 5,953.48
Expenses
DESAUTEL HEGE COMMUNICATIONS Professional Services 31,277.23
DUFFY RESEARCH Miscellaneous 5,290.73
ENTERPRISE RENT A CAR Miscellaneous 5,646.22
HANNA & ASSOCIATES INC Printing 20,721.44
INLAND NORTHWEST PARTNERS Subscriptions 5,899.58
INNOVATE WASHINGTON FOUNDATION Professional Services 23,918.62
JASON R THACKSTON Employee Misc 13,137.46
Expenses
KAREN S FELTES Employee Misc 7,426.75
Expenses
KLUNDT HOSMER DESIGN Professional Services 18,790.70
MARK T THIES Employee Misc 6,372.49
Expenses
MDI MARKETING Advertising Expenses 9,832.63
MELLON INVESTOR SERVICES LLC Miscellaneous 16,389.60
MICHAEL G ANDREA Employee Misc 17,936.42
Expenses
MICHAEL J FAULKENBERRY Employee Misc .00
Expenses
MOODYS INVESTORS SERVICE Miscellaneous 97,259.40
NYSE MARKET INC General Services 39,143.67
RICOH USA INC Printing 7,654.42
ROCKY MOUNTAIN INSTITUTE Professional Services 18,011.00
SIXTH MAN MARKETING LLC Professional Services 7,924.84
STANDARD & POORS Miscellaneous 76,347.09
THE BANK OF NEW YORK MELLON Miscellaneous 8,499.75
THE DAVENPORT HOTEL Miscellaneous 14,087.66
UNION BANK OF CALIFORNIA Miscellaneous 25,215.40
VAN NESS FELDMAN Legal Services 16,427.75
Schedule Page: 335 Line No.: 8 Column: b
Directors 2012 Expense
S
Vendor Name
HEIDI B STANLEY
MARC F RACICOT
ERIK J ANDERSON
KRISTIANNE BLAKE
REBECCA A KLEIN
JOHN F KELLY
MICHAEL L NOEL
R JOHN TAYLOR
SCOTT L MORRIS
RICK R HOLLEY
DONALD C BURKE
$67,840
$61,053
$62,905
$63,017
$50,608
$79,492
$46,751
$53,925
$16,249
$58,304
$51,354
Name of Respondent This Rort Is: ep Date of Report Year/Period of Report
Avista Corporation (1)An Original (Mo, Da, Yr) End of 2012/Q4
(2)pA Resubmission 04/12/2013
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Account 403 404, 405)
(Except amortization of aquisition adjustments)
1.Report in section A for the year the amounts for: (b) Depreciation Expense (Account 403; (c) Depreciation Expense for Asset
Retirement Costs (Account 403.1; (d) Amortization of Limited-Term Electric Plant (Account 404); and (e) Amortization of Other Electric
Plant (Account 405).
2.Report in Section 8 the rates used to compute amortization charges for electric plant (Accounts 404 and 405). State the basis used to
compute charges and whether any changes have been made in the basis or rates used from the preceding report year.
3.Report all available information called for in Section C every fifth year beginning with report year 1971, reporting annually only changes
to columns (c) through (g) from the complete report of the preceding year.
Unless composite depreciation accounting for total depreciable plant is followed, list numerically in column (a) each plant subaccount,
account or functional classification, as appropriate, to which a rate is applied. 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.
A. Summary of Depreciation and Amortization Charges
- Depreciation Amortization of
Line Deoreciation Expense for Asset Limited Term Amortization of
Id Functional Classification Expense Retirement Costs Electric Plant Other Electric Total
0. (Account 403) (Account 403.1) (Account 404) Plant (Acc 405)
- (a) (b) (c) (d) (e) (0
I llntangible Plant 5,693,753 5,693,753
2 Steam Production Plant 10,710,230 10,710,230
3 Nuclear Production Plant
4 Hydraulic Production Plant-Conventional 8,975,915 8,975,915
5 Hydraulic Production Plant -Pumped Storage
6 Other Production Plant 8,366,040 2450,031 10,816,071
7 Transmission Plant 10,730,725 10,730,725
8 Distribution Plant 31842,769 31,842,769
9 Regional Transmission and Market Operation
10 General Plant 3,902,111 3,902,111
11 Common Plant-Electric 8,489,414 1,582,119 10,071,533
12 TOTAL 83017,204 7,275,872 2,450,031 92,743,107
- B. Basis for Amortization Charges
FERC FORM NO. I (REV. 12-03) Page 336
Name of Respondent
Avista Corporation
This Report Is:
AResubmission
Date of Report
2/20w
Year/Period of Report
End of 2012/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No
-
Account No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg. Service
Life
(c)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates
(Percent)
(e)
Mortality
Curve
Type
(f)
Average
Remaining Life
(g)
12 STEAM PLANT
13 Colstrip No.3
14 311 51,012 65.00 -5.00 2.28 S1.5 17.88
15 312 78,402 60.00 -10.00 2.70 RI 18.57
16 314 23,215 50.00 -10.00 3.39 01 28.07
17 315 9,550 55.00 -5.00 2.49 S1.5 20.78
18 316 9,030 50.00 2.26 R2 15.88
19 Subtotal 171,209
20
21 Colstrip No. 4
22 311 50,229 65.00 -5.00 2.35 S1.5 21:32
23 312 .50,571 60.00 -10.00 2.83 Ri 23.84
24 314 15,774 50.00 -10.00 3.5001 28.31
25 315 6,699 55.00 -5.00 2.59 S1.5 25.11
26 316 4,299 50.00 2.46 R3 19.98
27 Subtotal 127,572
28
29 Kettle Falls
30 310 148 35.00 2.19 SQ
31 311 24,982 65.00 -5.00 2.34 S1.5 20.59
32312, 42,375 60.00 -10.00 3.31 Ri 22.43
33 314 13,345 50.00 -10.00 3.18 01 16.35
34 315 9,913 55.00 -5.00 2.74 S1.5 17.61
35 316 2,612 50.00 2.68 R2 21.44
36 Subtotal 93,375
37
38 I-IYDRO PLANT
39 Cabinet Gorge
40 330 7,842 75.00 2.75 R3 67.57
41 331 10,943 110.00 -5.00 1.62 R0.5 56.19
42 332 31,785 100.00 1.79 R1.5 77.96
43 333 37,880 60.00 -5.00 2.59 R1.5 52.14
44 334 5,605 45.00 1.43 R2.5 16.54
45 335 3,416 65.00 0.13 Ri 1.20
46 336 1,099 60.00 2.05 S2.5 17.49
47 Subtotal 98,570
48
49 Noxon Rapids
50 330 30,389 75.00 2.83 R3 69.37
FERC FORM NO. 1 (REV. 12-03) Page 337
Name of Respondent
Avista Corporation
This Re oil Is:
(2) E] A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
0.
-
Account No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
hstimated
Avg. Service
Life
(C)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates (Percent)
(e)
Mortality
Curve
Type (f)
Average
Remaining
Life
(Q)
12 331 14,911 110.00 -5.00 1.77 R0.5 81.53
13 332 32,991 100.00 1.79 R1.5 75.35
14 333 88,323 60.00 -5.00 2.89 R1.5 56.01
15 334 14,223 45.00 2.53 R2.5 43.88
16 335 3,378 65.00 0.97 Ri 19.90
17 336 247 60.00 2.12 R2.5 39.60
18 Subtotal 184,462
19
20 Post Falls
21 330 199 75.00 3.79 R3 56.46
22 331 1,466 110.00 -5.00 0.36 R0.5 56.29
23 332 6,344 100.00 2.72 R1.5 92.62
24 333 2,234 60.00 -5.00 0.16 R1.5
25 334 716 45.00 0.14 R2.5 0.01
26 335 223 65.00 2.68 Ri 53.83
27 Subtotal 11,182
28
29 Long Lake
30 330 171 75.00 5.68 R3 45.63
31 331 2,429 110.00 -5.00 0.12 R0.5 15.32
32 332 16,673 100.00 1.10 R1.5 24.34
33 333 8,824 60.00 -5.00 1.29 R1.5 13.91
34 334 2,823 45.00 0.82 R2.5 30.46
35 335 529 65.00 1.58 Ri 30.46
36 Subtotal 31,449
37
38 Little Falls
39 330 4,214 75.00 7.03 R3 56.31
40 331 1,188 110.00 -5.00 0.12 R0.5 2.00
41 332 5,066 100.00 1.51 R1.5 51.95
42 333 3,940 60.00 -5.00 0.51 R1.5
43 334 2,056 45.00 0.93 R2.5 12.81
44 335 144 65.00 1.18 RI 19.46
45 Subtotal 16,608
46
47 Upper Falls
48 330 64 75.00 2.48 R4 37.64
49 331 936 110.00 -5.00 0.12 R0.5 9.42
50 332 7,677 100.00 1.20 R1.5 76.61
FERC FORM NO. I (REV. 12-03) Page 337.1
Name of Respondent
A vis a Corporation
This Re Is: p
(1)An Original
(2)EA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No
-
Account No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg. Service
Life
(c)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates (Percent)
(e)
Mortality
Curve
Type
(1)
Average
Remaining
Life (g)
12 333 1,186 60.00 -5.00 0.90 R1.5 6.67
13 334 4,268 45.00 1.85 R2.5 37.00
14 335 107 65.00 2.30 Ri 51.46
15 Subtotal 14,238
16
17 Nine Mile
18 330 10 75.00 4.59 R3 34.35
19 331 3,950 110.00 -5.00 2.35 R0.5 80.39
20 332 13,620 100.00 2.16 R1.5 72.53
21 333 9,627 60.00 -5.00 3.03 R1.5 56.34
22 334 2,637 45.00 2.57 R2.5 31.52
23 335 297 65.00 2.31 Ri 45.87
24 336 625 60.00 2.64 S2.5 56.50
25 Subtotal 30,766
26
27 Monroe Street
28 331 8,444 110.00 -5.00 1.82 R0.5 109.02
29 332 9,978 100.00 1.72 R1.5 99.22
30 333 11,030 60.00 -5.00 2.28 R1.5 60.23
31 334 1,685 45.00 2.97 R2.5 45.13
32 335 34 65.00 2.04 Ri 64.37
33 336 50 60.00 2.17 52.5 59.42
34 Subtotal 31,221
35
36 OTHER PRODUCTION
37 Northeast Turbine
38 341 745 0.98 SQ
39342 31 55.00 1.31 R3
40 343 9,058 50.00 7.83 S2.5 8.42
41 344 2,605 45.00 0.72 R3
42345 1,238 40.00 8.54 S1.5 11.83
43346 406 1.24 SQ
44 Subtotal 14,083
45
46 Rathdrum Turbine
47 341 3,258 3.95 SQ
48 342 1,696 55.00 4.10 R2.5 44.14
49 343 5,502 50.00 3.61 S2.5 33.50
50 344 48,858 45.00 3.37 R3 35.49
FERC FORM NO. I (REV. 12-03) Page 337.2
Name of Respondent
Avista Corporation
This Re ort Is:
(2) []A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating DepreciatiQo Charges
Line
No
-
Account No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg. Service
Life
(C)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates (Percent)
(e)
Mortality
Curve
Type
(I)
Average
Remaining Life
(Q)
12 345 2,567 40.00 3.56 S1.5
13 Subtotal 61,881
14
15 Kettle Falls CT
16 342 89 55.00 4.74 R3 39.59
17 343 9,071 50.00 4.71 S2.5 35.98
18 344 4 45.00 4.98 R3 36.77
19 345 14 40.00 4.48 S1.5 28.83
20 Subtotal 9,178
21
22 Boulder Park
23 341 1,205 2.63 SQ
24 342 116 55.00 2.71 R3 37.93
25 343 57 50.00 3.01 S2.5 40.21
26 344 30,611 45.00 2.84 R3 32.97
27 345 443 40.00 2.97 S1.5 31.24
28346 7 2.69 SQ
29 Subtotal 32,439
30
31 Coyote Springs 2
32 341 11,374 2.76 SQ
33 342 19,145 55.00 2.85 R3 44.23
34344 119,026 45.00 2.92 R3 41.58
35 345 12,818 40.00 3.10S1.5 32.07
36 346 1,306 2.76 SQ
37 Subtotal 163,669
38
39 Solar Power 183
40 Subtotal 183
41 TRANSMISSION PLANT
42 350 1,488 75.00 1.28 R4 53.27
43 352 17,104 60.00 -5.00 1.61 R4 44.73
44 353 213,222 47.00 -15.00 2.39 R3 31.13
45 354 17,123 70.00 -20.00 1.87 S3 43.89
46 355 154,798 60.00 -30.00 1.84 R3 37.27
47 356 116,768 60.00 -10.00 1.93 R3 43.30
48 357 2,605 60.00 1.58 R4 52.84
49 358 2,330 55.00 1.73 S3 41.27
50 359 1,872 65.00 1.65 R4 45.05
FERC FORM NO. I (REV. 12-03) Page 337.3
Name of Respondent
Avista Corporation
This Re ort Is:
AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 20121Q4
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No
-
Account No.
(a)
Depreciable
Plant Base
(In Thousands) (b)
Estimated
Avg. Service
Life
(C)
Net
Salvage
(Percent) (d)
Appliea
Depr. rates
(Percent)
(e)
Mortality
Curve
Type
(t)
Average
Remaining
Life (q)
12 Subtotal 527,310
13 PISTRIBUTION PLANT
14 360 75.00
15 361 17,970 55.00 -10.00 1.80 R3 35.51
16 362 111,338 42.00 -10.00 2.60 R1.5 28.26
17 364 261,335 50.00 -25.00 2.66 R2.5 34.66
18 365 173,752 50.00 -15.00 2.46 R2.5 35.35
19 366 85,678 45.00 -10.00 2.71 R3 36.09
20 367 141,650 28.00 -15.00 6.38 L4 23.05
21 368 198,972 44.00 -5.00 2.00 R2 27.21
22 369 132,648 60.00 -15.00 1.63 R3 38.01
23 370 47,965 38.00 2.39 Si 33.72
24 373 16,356 32.00 -15.00 1.08 R2.5 8.68
25373.4 20,029 32.00 -5.00 2.82 R2.5 18.79
26 Subtotal 1207,693
27
28 GENERAL PLANT
29390.1 6,229 55.00 -5.00 1.85 S2 20.91
30391.1 7,870 5.00 17.67 SQ 3.80
31 393 395 25.00 2.25 SQ 22.97
32 394 3,186 20.00 4.22 SQ 10.35
33 395 920 15.00 7.72 SQ 7.82
34 397 48,855 15.00 5.40 SQ 5.17
35 398 31 10.00 2.37 SQ 7.80
36 Subtotal 67,486
37
38 MISC POWER
39 392 3,742 11.00 10.00 3.70 S3
40 396 2,806 15.00 10.00 5.40 L2
41 Subtotal 6,548
42
43
44
45
46
471 1
48
49
50
FERC FORM NO. 1 (REV. 12-03) Page 337.4
Name of Respondent
Avista Corporation
This Report Is:
(1)An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/1212013
Year/Period of Report
End of 2012/04
DEPRECIATION AND AMORTIZATION OF ELECTRIC PLANT (Continued)
C. Factors Used in Estimating Depreciation Charges
Line
No
-
Account No.
(a)
Depreciable
Plant Base
(In Thousands)
(b)
Estimated
Avg. Service
Life
(C)
Net
Salvage
(Percent)
(d)
Applied
Depr. rates
(Percent)
(e)
Mortality
Curve
Type
(f)
Average
Remaining Life
(Q)
12 Lancaster
13 342 92 52.43
14 344 208 42.90
15 SUBTOTAL 300
16
17 TOTAL COMPANY 2,901,422
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
46
47
48
49
50
FERC FORM NO. I (REV. 12-03) Page 337.5
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Re ort Is:
(2) oA Resubmission
I Date of Report
04/1212013
Year/Period of Report
End of 2012/Q4
REGULATORY COMMISSION EXPENSES
1.Report particulars (details) of regulatory commission expenses incurred during the current year (or incurred in previous years, if
being amortized) relating to format cases before a regulatory body, or cases in which such a body was a party.
2.Report in columns (b) and (c), only the current year's expenses that are not deferred and the current years amortization of amounts
deferred in previous years.
Line
No.
-
Description
(Furnish name of regulatory commission or body the
docket or case number and a description of the case)
(a)
Assessed by Regulatory
Commission
(b)
Expenses
of
Utility
(C)
Total Expense for Current Year (b) + (C)
(d)
Deferred in Account
182.3 af Beginning of Year
(e)
1 Federal Energy Regulatory Commission
21 Charges include annual fee and license fees
3 for the Spokane River Project, the Cabinet
4 Gorge Project and the Noxon Rapids Project. 2,431,364 185,496 2616,860
5
6
7
8
9 Washington Utilities and Transportation
10 Commission: includes annual fee and various
11 other electric dockets 960,565 1,301,327 2,261,892
12
13 Includes annual fee and various other natural
14 gas dockets 320,188 495,445 815,633
15
16 Idaho Public Utilities Commission
17 Includes annual fee and various other electric
18 dockets 620,838 245,606 866,444
19
20 Includes annual fee and various other natural
21 gas dockets 172,199 111,074 283,273
22
23 Public Utility Commission of Oregon
24 Includes annual fees and various other natural
25 gas dockets 528,779 127,724 656,503
26
27 Not directly assigned electric 913,764 913,764
28 Not directly assigned natural gas 354,716 354,716
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
46 TOTAL 5,033,933 3,735,152j 8,769,085
FERC FORM NO. I (ED. 12-96) Page 360
Name of Respondent
Avista Corporation
This Report Is: Date of Report
[]A Resubmission 04/12/2013
Year/Period of Report
End of 2012/04
REGULATORY COMMISSION EXPENSES (Continued)
3.Show in column (k) any expenses incurred in prior years which are being amortized. List in column (a) the period of amortization.
4.List in column (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.
EXPENSES INCURRED DURING YEAR AMORTIZED DURING YEAR
CURRENTLY CHARGED TO Deferred to
Account 182.3
(i)
Contra
Account
)
Amount
(k)
Deferred in Account 182.3 Line
No. Department
(f)
icunt 0.
(g)
Amount
(h)
2
3
Electric 928 2,616,860 4
5
6
7
8
9
10
Electric 928 2,261,892 11
12
13
Gas 928 815,633 14
15
16
17
Electric 928 866,444 18
19
20
Gas 928 283,273 21
22
23
24
Gas 928 656,503 25
26
Electric 928 913,764 27
Gas 928 354,716 28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
45
8,769,0851 1 46
FERC FORM NO. 1 (ED. 12-96) Page 361
Name of Respondent
Avista Corporation
This Re ort Is:
(1)An Original
(2)flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES
1.Describe and show below costs incurred and accounts charged during the year for technological research, development, and demonstration (R, D &
D) project initiated, continued or concluded during the year. 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 respondents 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, 0 & 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
Line
No.
Classification
(a)
Description
(b)
1 A 3 Electric - Distribution Smart Grid Demonstration Grant (Meters)
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
FERC FORM NO. 1 (ED. 12-87) Page 352
Name of Respondent
Avista Corporation
This Re ort Is:
(1)On Original
(2)UA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
RESEARCH, DEVELOPMENT, AND DEMONSTRATION ACTIVITIES (Continued)
(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, 0 &
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
7.Report separately research and related testing facilities operated by the respondent.
Costs Incurred Internally
Current
Costs Incurred Externally
Current Year
(d)
AMOUNTS CHARGED IN CURRENT YEAR Unamortized
Accumulation
(g)
Line
No. Account
(e)
Amount
(U
2,206,824 1,052,379 107 3,259,203 1
25,640 217 108 25,857 2
53,577 31 580 53,608 3
12,395 107,877 587 120,272 4
-1,800 261,141 588 259,341 5
100,719 920 100,719 6
376 28,997 921 29,373 7
2,881 42,820 923 45,701 8
50 926 50 9
85 930 85 10
109,684 935 109,684 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
FERC FORM NO. I (ED. 12-87) Page 363
Name of Respondent
Avista Corporation
This Re ort Is:
(1)An Original
(2)A Resubmission
I Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012104
DISTRIBUTION OF SALARIES AND WAGES
Report below the distribution of total salaries and wages for the year. Segregate amounts originally charged to clearing accounts to
Utility Departments, Construction, Plant Removals, and Other Accounts, and enter such amounts in the appropriate lines and columns
provided. In determining this segregation of salaries and wages originally charged to clearing accounts, a method of approximation
giving substantially correct results may be used.
Line
No.
-
Classification
(a)
Direct Payroll
(b)
Pa e.i for Total
Clearing Accounts
Ic) (d)
1
2
3
Electric
Operation
Production I 10,264,200
4 Transmission 2,656,676
5 Regional Market
6 Distribution 7,508,530
7 Customer Accounts 6924,109
8 Customer Service and Informational 711,342
9 Sales 5,487
10 Administrative and General 16,143,773
11 TOTAL Operation (Enter Total of lines 3thru 10) 44,214,117
12
13
Maintenance
Production 3,410,007
14 Transmission 985,166
15 Regional Market
16 Distribution 4,058,266
17 Administrative and General
18
19
20
TOTAL Maintenance (Total of lines 13 thru 17)
Total Operation and Maintenance
Production (Enter Total of lines 3 and 13)
I 8,453,439
I 13,674,207
21 Transmission (Enter Total of lines 4 and 14) 3,641,842
22 Regional Market (Enter Total of Lines 5 and 15)
23 Distribution (Enter Total of lines 6 and 16) 11,566,796
6,924,109 24 Customer Accounts (Transcribe from line 7)
251 Customer Service and Informational (Transcribe from line 8) 711,342
26 Sales (Transcribe from line 9) 5,487
27 Administrative and General (Enter Total of lines 10 and 17) 16,143,773
28 TOTAL Oper. and Maint. (Total of lines 20 thru 27) I 52,667556f 10,330,4711 62,998,0271
29
30
31
Gas
Operation
Production-Manufactured Gas I
32 Production-Nat. Gas (Including ExpI. and Dev.)
33 Other Gas Supply 828,785
34 Storage, LNG Terminaling and Processing 8,363
35 Transmission
36 Distribution 3,578,184
37 Customer Accounts 2,710,084
38 Customer Service and Informational 349,486
39 Sales 1,488
40 Administrative and General 5,910,809
41 TOTAL Operation (Enter Total of lines 31 thru 40) 13,387,199
42
43
Maintenance
Production-Manufactured Gas I
44 Production-Natural Gas (Including Exploration and Development)
45 Other Gas Supply
46 Storage, LNG Terminaling and Processing
47 Transmission 866,735
FRC FORM NO. 1 (ED. 12-88) Page 354
Name of Respondent
Avista Corporation
I This Re ort Is:

(1) IAn Original
I (2) flA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012104
DISTIIBUTION OF SALARIES AND WAGES (Continued)
Line
No.
Classification Direct Payroll Allocation of for Total
Clearing Accounts (ci)
48 Distribution 2,641,810
49 Administrative and General
50
51
TOTAL Maint. (Enter Total of lines 43 thru 49)
Total Operation and Maintenance
3508,545
52 Production-Manufactured Gas (Enter Total of lines 31 and 43)
53 Production-Natural Gas (Including ExpI. and Dev.) (Total lines 32,
54 Other Gas Supply (Enter Total of lines 33 and 45) 828,785
55 Storage, LNG Terminaling and Processing (Total of lines 31 thru 8,363
56 Transmission (Lines 35 and 47) 866,735
57 Distribution (Lines 36 and 48) 6,219,994
2,710,084 58 Customer Accounts (Line 37)
59 Customer Service and Informational (Line 38) 349,486
60 Sales (Line 39) 1,488
5,910,809 611 Administrative and General (Lines 40 and 49)
62 TOTAL Operation and Maint. (Total of lines 52 thru 61) 16,895,744 3,381,1091 20,276,853'
63 Other Utility Departments
64 Operation and Maintenance
65 TOTAL All Utility Dept. (Total of lines 28, 62, and 64) 69,563,300 13,711,5801 83,274,880
66
67
68
Utility Plant
Construction (By Utility Departments)
Electric Plant 29,696,4851 9,212,974 38,909,459
69 Gas Plant 8,275,7271 2,948,976 11,224,703
70 Other (provide details in footnote):
71 TOTAL Construction (Total of lines 68 thru 70) 37,972,2121 12,161,9501 50,134,162
72
73
Plant Removal (By Utility Departments)
Electric Plant 1,508,765 290,831 1,799,596
74 Gas Plant 124,325 23,965 148,290
75 Other (provide details in footnote):
76 TOTAL Plant Removal (Total of lines 73 thru 75) 1,633,090 314,796 1,947,886
771 Other Accounts (Specify, provide details in footnote):
78
79 Stores (163) 1,901,710 -1,901,710
80
81
82 Preliminary Survey and Investigation (183) 71,274 71,274
83 Small Tool Expense (184) 3,296,582 -3,296,582
84 Miscellaneous Deferred Debits (186) 1,349,092 1,349,092
85
86
87 Non-operating Expenses (417) 747,089 747,089
88 Exp. of Certain Civic, Political and Related Activities (426) 620,960 620,960
89 Employee Incentive Plan (232380) 4,843,441 -4,843,441
90 DSM Tarnf Rider and Payrool Equalization Liab. (242600, 242 18,112,648 -16,199,994 1,912,654
91 Incentive / Stock Compensation (238000) 81,070 81,070
92
93
94
95 TOTAL Other Accounts 31,023,866 -26,241,727 20,982,133
96 TOTAL SALARIES AND WAGES 140,192,468 -53,401 156,339,061
FERC FORM NO. 1 (ED. 12-88) Page 355
Name of Respondent This Report Is: Date of Report Year/Period of Report
Avista Corporation (1) LXI An Original (Mo, Da, Yr)
(2) 0 A Resubmission End of 2012/Q4
COMMON UTILITY PLANT AND EXPENSES
1.Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant 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 45,144,377
389 Land and Land Rights 5,145,059
390 Structures and Improvements 79,806,317
391 Office Furniture and Equipment 43,816,402
392 Transportation Equipment 10,012,212
393 Stores Equipment 2,090,919
394 Tools, Shop & Garage Equipment 8,961,605
395 Laboratory Equipment 518,893
396 Power Operated Equipment 2,089,948
397 Communications Equipment 29, 859, 394
398 Miscellaneous Equipment 395,531
399 Asset Retirement Cost 371,024
Total Common Plant 228,211,683
Const. Work in Progress 41,012,084
Total Utility Plant 269,223,767
Acc. Prov. for Dep. & Pmort. 62,591,095
Net Utility Plant 206,632,672
3. Common Expenses allocated to Electric and Gas departments:
Allocation to Allocated to Basis of
Acct. No. Description Total Electric Dept Gas Dept Allocation
901 Cust acct/collect 1,092,096 577,883 514,213 #of cust @ yr end
supervision
902 Meter reading expenses 4,577,785 2,820,602 1,757,183 #of cust @ yr end
903 Cust rec and 14,555,244 7,921,994 6,633,250 #of cust @ yr end
collection expenses
903.90-99A/R misc fees 0 0 0 net direct plant
904 Uncollectible accounts 4,024,467 2,129,547 1,894,920 #of cust @ yr end
905 Misc cust acct expenses 433,612 229,446 204,166 1of cust @ yr end
907 Cust svce & Info exp 0 0 0 #of cust @ yr end
supervision
908 Cust assistance expenses 1,139,474 702,079 437,395 #of cust @ yr end
909 Info & instruct expenses 1,799,793 1,097,730 702,063 #of cust @ yrend
910 Misc cust serv & info 333,026 176,221 156,805 #of cust @ yr end
FERC FORM NO. I (ED. 12-87) Page 356
Name of Respondent I This Report Is: I Date of Report I Year/Period of Report
Avista Corporation (1) An Original (Mo, Da, Yr)
I (2) j A Resubmission 04/12/2013 End of 2012/Q4
COMMON UTILITY PLANT AND EXPENSES
1.Describe the property carried in the utility's accounts as common utility plant and show the book cost of such plant at end of year classified by
accounts as provided by Plant 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.
expenses
911 Sales expense -supervision 0 0 0 #of cust @ yr end
912 Demo & selling expenses 12,899 7,948 4,951 #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 48,284,146 34,866,302 13,417,844 four factor
921 Office supplies expenses 5,575,058 4,025,163 1,549,895 four factor
922 Admin expenses tranf-credit 2,046 1,474 572 four factor
923 Outside services 15,901,289 11,456,226 4,445,063 four factor
employed
924 Property insurance 1,527,074 1,100,165 426,909 four factor
925 Injuries and damages 6,188,683 4,602,591 1,586,092 four factor
926 Employee pensions 65,169,666 47,031,676 18,137,990 four factor
& benefits
927 Franchise requirement 0 0 0 four factor
928 Regulatory commission 2,475,738 1,863,514 612,224 four factor
expenses
929 Duplicate charges-credit 0 0 0 four factor
930.1 General advertising expenses 3,191 2,394 797 four factor
930.2 Misc general expenses 3,615,670 2,629,958 985,712 four factor
931 Rents 1,310,844 955,469 355,375 four factor
935 Maint of general plant 9,235,270 6,776,630 2,458,640 four factor
403 Depreciation 11,694,987 8,489,414 3,205,573 four factor
404 Amort of LTD term plant 7,902,269 5,693753 2,208,516 four factor
Note 1: The four factor allocator is made up of 25 percent each of customer counts, direct labor, direct
O&14 & Net direct plant
4. Letters of approval received from staffs of State Regulatory Commissions in 1993
FERC FORM NO. I (ED. 12-87) Page 356.1
Name of Respondent This Re ort Is: Date of Report Year/Period of Report
Avista Corporation End of 201 2/Q4
(2) AResubmission
PURCHASES AND SALES OF ANCILLARY SERVICES
Report the amounts for each type of ancillary service shown in column (a) for the year as specified in Order No. 888 and defined in the
respondents Open Access Transmission Tariff.
In columns for usage, report usage-related billing determinant and the unit of measure.
(1)On line I 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.
Amount Purchased for the Year Amount Sold for the Year
Usage - Related Billing Determinant Usage - Related Billing Determinant
Unit of Unit of
Line Type of Ancillary Service Number of Units Measure Dollars Number of Units Measure Dollars
F'Jo (a) (b) I (C) (d) (e) (f) (g)
1 Scheduling, System Control and Dispatch 616 MW 125,032
2 Reactive Supply and Voltage
3 Regulation and Frequency Response 66,451 MWh 8,744 69,924 MW 625,117
4 Energy Imbalance 629 MW 1,196,883
5 Operating Reserve - Spinning 835 MWh 17,300 27,475 MWh 251,722
6 Operating Reserve - Supplement 835 MWh 17,300 113,257 MWh 1,141,098
7 Other 1.307,347 MW 11,687,679 1,307,347 MW 11,687,679
8 Total (Lines 1 thru 7) 1,376,084 11,856,055 1,518,632 14,902,499
FERC FORM NO. 1 (New 2-04) Page 398
tSchedule Page: 398 Line No.: 7 Column: b I
Interdepartmental spinning reserve service for Native Load.
ISchedule Page: 398 Line No.: 7 Column: d I
Interdepartmental spinning reserve service for Native Load.
ISchedule Page: 398 Line No.: 7 Column: e I
Interdepartmental spinning reserve service for Native Load.
Schedule Page: 398 Line No.: 7 Column: g I
InterdeDartmental sDinninq reserve service for Native Load.
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Re ort Is:
[:]A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
MONTHLY TRANSMISSION SYSTEM PEAK LOAD
(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.
NAME OF SYSTEM:
Line
No.
-
Month
(a)
Monthly Peak
MW - Total
(b)
Day of
Monthly
Peak
(C)
Hour of
Monthly
Peak
(d)
Firm Network
Service for Self
(e)
Firm Network
Service for
Others
(f)
Long-Term Firm
Point-to-point
Reservations
(g)
Other Long-
Term Firm
Service
(h)
Short-Term Firm
Point-to-point
Reservation
(i)
Other
Service
U)
1 I January 1,98q 1 18001 1,479 307 138 16 55 268
2 February 1,86' 21 800 1,397 306 138 17 20 465
3 March 1,79 A 7001 1,351 289 138 15 20 169
4 Total for Quarter l 5,63 4,227 902 414 48 95 902
5 April 1,70 1900 1,305 228 138 8 34 290
61 May 2,04 31 12001 1,094 205 140 24 609 117
7 June 1,97 2 15001 1,204 222 140 25 408 153
8 Total for Quarter 2 5,721
2,35 1' 16001
3,603 655 418 57 1,051 560
9 July 1,511 269 160 35 419 26
10 August 2,358 A 1600 1,527 270 152 26 409 151
111 September 1,804 2 1700 1,180 208 154 20 262 175
12 Total for Quarter 3 6,521 4,218 747 466 81 1,090 352
13 October 1,95 2 900 1,313 239 146 17 257 168
14 November 1,91 2 2000 1,428 266 139 19 80 422
15 December 1,991 ii 1800 1,432 284 138 17 137 322
161 Total fr. Quarter 4 5,85( 4,173 789 423 53 474 912
17 Total Year to
Date/Year - 23,74E 16,221 3,093 1,721 239 2,710 2,726
FERC FORM NO. 113-Q (NEW. 07-04) Page 400
Name of Respondent
Avista Corporation
This Re ort Is:
AResubrnission
Date of Report Year/Period of Report
End of 2012/04
ELECTRIC ENERGY ACCOUNT
Report below the information called for concerning the disposition of electric energy generated, purchased, exchanged and wheeled during the year.
Line
No.
-
Item
(a)
MegaWatt Hours
(b)
Line
No.
Item
(a)
MegaWatt Hours
(b)
1 SOURCES OF ENERGY 21 DISPOSITION OF ENERGY
2 Generation (Excluding Station Use): 22 Sales to Ultimate Consumers (Including
Interdepartmental Sales)
8,873,005
__________________ 3 Steam 11,708,156
4 Nuclear 23 Requirements Sales for Resale (See
instruction 4, page 311.) 5 Hydro-Conventional 4,088,289
6 Hydro-Pumped Storage 24 Non-Requirements Sales for Resale (See
instruction 4, page 311.)
5,634,398
7 Other 1,155,679
8 Less Energy for Pumping 25 Energy Furnished Without Charge
9 Net Generation (Enter Total of lines 3
through 8)
6,952,124 26
-
Energy Used by the Company (Electric
Dept Only, Excluding Station Use)
10,284
10 Purchases 8,188,382 27 Total Energy Losses 623,656
11 Power Exchanges:
5 )
TAL (Enter Total of Lines 22 Through
(MUST EQUAL LINE 20)
15,141,343
12 Received
13 Delivered 47,8
14
J28
Net Exchanges (Line 12 minus line 13) 8
15 Transmission For Other (Wheeling)
16 Received 3,191,978
17 Delivered 3,191,971
18 Net Transmission for Other (Line 16 minus
line 17)
19 Transmission By Others Losses
20 TOTAL (Enter Total of lines 9, 10, 14, 18
and 19)
15,141,34
FERC FORM NO. 1 (ED. 12-90) Page 401a
Name of Respondent
Avista Corporation
This Re ort Is:
(2) E] A Resubmission
-Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
MONTHLY PEAKS AND OUTPUT
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 systems 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).
NAME OF SYSTEM:
Line
No.
-
Month
(a)
Total Monthly Energy
(b)
Monthly Non-Requirments
Sales for Resale &
Associated Losses
(c)
MONTHLY PEAK
Megawatts (See Instr. 4)
(d)
Day of Month
(e)
Hour
(f)
29 January 1,389,466 465,083 1,554 12 0800
301 February 1,258,480 431,544 1,455 28 0800
31 March 1,133575 317,623 1,377 1 1900
32 April 1,192,231 468,611 1,341 4 1900
33 May 1,287,401 569,913 1,243 15 1700
34 June 1,252,346 562,240 1,242 21 1700
35 July 1,354,143 539,059 1,571 12 1600
36 August 1,235,182 410,700 1,579 7 1600
37 September 1,124,323 418,145 1,222 4 1500
38 October 1,264,983 501,390 1,309 24 0800
39 November 1,310,507 507,159 1,428 12 1800
401 December 1,338,706 442,931 1,499 17 1800
41 TOTAL 15,141,343 5,634,398
FERC FORM NO. I (ED. 12-90) Page 401b
Name of Respondent
Avista Corporation
This Rort Is: ep
(1)An Original
(2)[JA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 20121Q4
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 lithe 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.
Line
No.
-
Item
(a)
Plant
Name: Coyote Springs 2
(b)
Plant
Name: Spokane N.E.
(c)
1 Kind of Plant (Internal Comb, Gas Turb, Nuclear Gas Turbine Gas Turbine
2 IType of Constr (Conventional, Outdoor, Boiler, etc) Not Applicable Not Applicable
3 Year Originally Constructed 2003 1978
4 Year Last Unit was Installed 2003 1978
5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 287.00 61.80
6 Net Peak Demand on Plant - MW (60 minutes) 302 57
7 Plant Hours Connected to Load 4634 34
8 Net Continuous Plant Capability (Megawatts) 284 65
9 When Not Limited by Condenser Water 284 0
10 When Limited by Condenser Water 284 0
ii Average Number of Employees 13 1
12 Net Generation, Exclusive ofPlant Use - KWh 1142118000 181000
13 Cost of Plant: Land and Land Rights 0 157277
14 Structures and Improvements 11373980 744320
15 Equipment Costs 152294712 14071031
16 Asset Retirement Costs 351682 0
17 Total Cost 164020374 14972628
18 Cost per KW of Installed Capacity (line 17/5) Including 571.4996 242.2755
19 Production Expenses: Oper, Supv, & Engr 1169237 22093
20 Fuel 31006780 7488
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 1321189 36789
26 Misc Steam (or Nuclear) Power Expenses 213982 65179
27 Rents 84474 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 1539692 60
30 Maintenance of Structures 0 1591
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 7358436 48314
33 Maintenance of Misc Steam (or Nuclear) Plant 21585 60324
34 Total Production Expenses 42715375 241838
35 Expenses per Net KWh 0.0374 1.3361
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas Gas
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF MCF
38 Quantity (Units) of Fuel Burned 7783936 0 0 2757 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1020000 0 0 1020000 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 1983 0.000 0.000 2.716 0.000 0.000
41 Average Cost of Fuel per Unit Burned 3.983 0.000 0.000 2.716 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 3.905 0.000 0.000 2.663 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.027 0.000 0.000 0.041 0.000 0.000
44 Average BTU per KWh Net Generation 6952.000 0.000 0.000 15537.000 0.000 0.000
FERC FORM NO. I (REV. 12-03) Page 402
Name of Respondent
Avista Corporation
This Report Is:
[:]A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
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.
Plant
Name: Kettle Falls
(d)
Plant
Name: Co/strip
(e)
Plant
Name: Rathdrum
(f)
Line
No.
-
Steam Steam Gas Turbine 1
Conventional Conventional Not Applicable 2
1983 1984 1995 3
1983 1985 1995 4
50.70 233.40 166.50 5
50 232 163 6
5721 8759 121 7
54 222 167 8
54 222 0 9
54 222 0 10
28 200 2 11
209169000 1498987000 6943000 12
2199206 1289095 621682 13
24981463 101239544 3258386 14
682391 27 197540525 58622642 15
450687 134589 0 16
95870483 300203753 62502710 17
1890.9365 1286.2200 375.3917 18
236937 168916 78738 19
8293636 19671443 288574 20
0 0 0
!
647346 3359721 0 22
0 0 0 -
0 0 0 _±
799598 104219 171316 25
381045 1899735 170153 26
0 21917 0 27
0 0
139679 344566 12496 29
118754 488385 9678 30
1678350 3167082 0 31
268369 315845 182279 32
129205 435936 35857 33
12692919 29978065 949091 34
0.0607 0.0200 0.1367 35
Wood Gas Coal Oil Gas 36
TON MCF TON BBL MCF 37
362090 3615 0 949474 1508 0 92542 0 0 38
8600000 1020000 0 16970000 5880000 0 1020000 0 0 39
22.877 2.806 0.000 20.503 135.220 0.000 3.118 0.000 0.000 40
22.877 2.806 0.000 20.503 135.220 0.000 3.118 0.000 0.000 41
2.660 2.751 0.000 1.208 23.000 0.000 3.057 0.000 0.000 42
0.040 0.036 0.000 0.013 0.000 0.000 0.042 0.000 0.000 43
14907.000 0.000 0.000 10755.000 0.000 0.000 13595.000 0.000 0.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403
Name of Respondent
Avista Corporation
This Re ort Is: Date of Report
04n23
Year/Period of Report
End of 2o12/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. 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 lithe 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 Met. 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.
Line
No.
-
Item
(a)
Plant
Name: Boulder Park
(b)
Plant
Name:
(c)
1 Kind of Plant (Internal Comb, Gas Türb, Nuclear Internal Comb
2 IType of Constr (Conventional, Outdoor, Boiler, etc) Conventional
3 Year Originally Constructed 2002
4 Year Last Unit was Installed 2002
5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 24.60 0.00
6 Net Peak Demand on Plant - MW (60 minutes) 25 0
7 Plant Hours Connected to Load 317 0
8 Net Continuous Plant Capability (Megawatts) 24 0
9 When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
ii Average Number of Employees 2 0
12 Net Generation, Exclusive of Plant Use - KWh 5577000 0
13 Cost of Plant: Land and Land Rights 185629 0
14 Structures and Improvements 1204874 0
15 Equipment Costs 31233796 0
16 Asset Retirement Costs 0 0
17 Total Cost 32624299 0
18 JCost per KW of Installed Capacity (line 17/5) Including 1326.1910 0
19 Production Expenses: Oper, Supv, & Engr 10710 0
20 Fuel 154783 0
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 108811 0
26 Misc Steam (or Nuclear) Power Expenses 25587 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering -730 0
30 Maintenance of Structures 504 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 105337 0
33 Maintenance of Misc Steam (or Nuclear) Plant 35699 0
34 Total Production Expenses 440701 0
35 Expenses per Net KWh 0.0790 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear) Gas
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate) MCF
38 Quantity (Units) of Fuel Burned 48878 0 0 0 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 1020000 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 3.167 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 3.167 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 3.105 0.000 0.000 0.000 0.000 0.000
43 Average Cost of Fuel Burned per KWh Net Gen 0.028 0.000 0.000 0.000 0.000 0.000
44 Average BTU per KWh Net Generation 8939.000 0.000 0.000 0.000 10.000 0.000
FERC FORM NO. 1 (REV. 12-03) Page 402.1
Name of Respondent
Avista Corporation
This Re ort Is:
On Original
Date of Report
04/12
Year/Period of Report
End of 201 2/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
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.
Plant
Name:
(d)
Plant
Name:
(e)
Plant
Name:
(f)
Line
No.
-
2
3
4
0.00 0.00 0.00
0 0 0
0 0 0 !
0 0
0 0
0 0 0
0 0 0
0 0 0
0 0 0 i
0 0 0 !
0 0 0 !
0 0 0i!
0 0 0iz
0 0 0 !
0 0 0
0 0 0
0 0 0 21
0 0 0 22
0 0 0__
0 0 0 24
0 0 0__
0 0 0 26
0 0 0
0 0 0 28
0 0 0 29
0 0 0 30
0 0 0 31
0 0 0__
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000
Gas 36
MCF 37
0 0 0 48878 0 0 0 0 0 38
0 0 0 1020000 0 0 0 0 0 39
0.000 0.000 0.000 3.167 0.000 0.000 0.000 0.000 0.000 40
0.000 0.000 0.000 3.167 0.000 0.000 0.000 0.000 0.000 41
0.000 0.000 0.000 3.105 0.000 0.000 0.000 0.000 0.000 42
0.000 0.000 0.000 0.028 0.000 0.000 0.000 0.000 0.000 43
0.000 0.000 0.000 8939.000 0.000 0.000 0.000 0.000 0.000 44
FERC FORM NO. I (REV. 12-03) Page 403.1
Name of Respondent
Avista Corporation
This Re ort Is:
(2) A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
1. Report data for plant in Service only. 2. Large plants are steam plants with installed capacity (name plate rating) of 25,000 Kw or more. Report in
this page gas-turbine and internal combustion plants of 10,000 Kw or more, and nuclear plants. 3. 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 lithe 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.
Line
No.
-
Item
(a)
Plant
Name:
(b)
Plant
Name:
(C)
I Kind of Plant (Internal Comb, Gas Turb, Nuclear
2 IType of Constr (Conventional, Outdoor, Boiler, etc)
3 Year Originally Constructed
4 Year Last Unit was Installed
5 Total Installed Cap (Max Gen Name Plate Ratings-MW) 0.00 0.00
6 Net Peak Demand on Plant - MW (60 minutes) 0 0
7 Plant Hours Connected to Load 0 0
8 Net Continuous Plant Capability (Megawatts) 0 0
9 When Not Limited by Condenser Water 0 0
10 When Limited by Condenser Water 0 0
11 Average Number of Employees 0 0
12 Net Generation, Exclusive of Plant Use - KWh 0 0
13 Cost of Plant: Land and Land Rights 0 0
14 Structures and Improvements 0 0
15 Equipment Costs 0 0
16 Asset Retirement Costs 0 0
17 Total Cost 0 0
18 Cost per KW of Installed Capacity (line 17/5) Including 0 0
19 Production Expenses: Oper, Supv, & Engr 0 0
20 Fuel 0 0
21 Coolants and Water (Nuclear Plants Only) 0 0
22 Steam Expenses 0 0
23 Steam From Other Sources 0 0
24 Steam Transferred (Cr) 0 0
25 Electric Expenses 0 0
26 Misc Steam (or Nuclear) Power Expenses 0 0
27 Rents 0 0
28 Allowances 0 0
29 Maintenance Supervision and Engineering 0 0
30 Maintenance of Structures 0 0
31 Maintenance of Boiler (or reactor) Plant 0 0
32 Maintenance of Electric Plant 0 0
33 Maintenance of Misc Steam (or Nuclear) Plant 0 0
34 Total Production Expenses 0 0
35 Expenses per Net KWh 0.0000 0.0000
36 Fuel: Kind (Coal, Gas, Oil, or Nuclear)
37 Unit (Coal-tons/Oil-barrel/Gas-mcf/Nuclear-indicate)
38 Quantity (Units) of Fuel Burned 0 0 0 0 0 0
39 Avg Heat Cont - Fuel Burned (btu/indicate if nuclear) 0 0 0 0 0 0
40 Avg Cost of Fuel/unit, as Delvd f.o.b. during year 0.000 0.000 0.000 0.000 0.000 0.000
41 Average Cost of Fuel per Unit Burned 0.000 0.000 0.000 0.000 0.000 0.000
42 Average Cost of Fuel Burned per Million BTU 0.000 0.000 0.000 0.000 0.000 0.000
43 1 Average Cost of Fuel Burned per KWh Net Gen 0.000 0.000 0.000 0.000 10.000 0.000
44 Average BTU per KWh Net Generation 0.000 0.000 0.000 0.000 10.000 0.000
FERC FORM NO. 1 (REV. 12-03) Page 402.2
Name of Respondent
Avista Corporation
This Re ort Is:
(2) E] A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
STEAM-ELECTRIC GENERATING PLANT STATISTICS (Large Plants)(Continued)
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.
Plant
Name:
(d)
Plant
Name:
(e)
Plant
Name:
(f)
Line
No.
-
2
3
4
0.00 0.00 0.00
0 0 0
0 0 0 i
0 0 0
0 0 0 !
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0
0 0 0 j
0 0 0 16
0 0 0
0 0 0
0 0 0!!
0 0 0 20
0 0 0
0 0 0 22
0 0 0 23
0 0 0 24
0 0 0 25
0 0 0__
0 0 0 27
0 0 0_._
0 0 0 29
0 0 0__
0 0 0 31
0 0 0__
0 0 0 33
0 0 0 34
0.0000 0.0000 0.0000
36
37
0 0 0 0 0 0 0 0 0
0 0 0 0 0 0 0 0 0
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 10.000 43
0.000 0.000 0.000 0.000 0.000 0.000 0.000 0.000 10.000 44
FERC FORM NO. 1 (REV. 12-03) Page 403.2
Schedule Page: 402 Line No.: -1 Column: b
Operated by Portland General Electric.
ISchedule Page: 402 Line No.: -1 Column: c
designed for peak load service
Schedule Page: 402 Line No.: -1 Column: e
Joint project operated by PPL Montana LLC.
Schedule Page: 402 Line No.: -1 Column: f
designed for peak load service
ISchedule Page: 4021 Line No.: -1 Column: b
designed for peak load service
This Page Intentionally Left Blank
Name of Respondent
Avista Corporation
This Re ort Is:
submission
Date of Report
04/12/2013
Year/Period of Report
End of 201 2/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.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 lithe approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 2545
Plant Name: Monroe Street
(b)
FERC Licensed Project No. 2545
Plant Name: Upper Falls
(C) -
1 Kind of Plant (Run-of-River or Storage) Run-of-River Run-of-River
2 Plant Construction type (Conventional or Outdoor) Conventional Conventional
3 Year Originally Constructed 1890 1922
4 Year Last Unit was Installed 1992 1922
5 lTotal installed cap (Gen name plate Rating in MW) 14.80 10.00
6 Net Peak Demand on Plant-Megawatts (60 minutes) 191 13
7 Plant Hours Connect to Load 8,2981 7,236
8 Net Plant Capability (in megawatts)
(a) Under Most Favorable Oper Conditions 15 10 9
10 (b) Under the Most Adverse Oper Conditions 15 10
11 Average Number of Employees 1 9
12 Net Generation, Exclusive of Plant Use - Kwh 102,158,000 59,630,000
13 Cost of Plant
0 1,081,854 14 Land and Land Rights
15 Structures and Improvements 8,443,779 936,027
16 Reservoirs, Dams, and Waterways 9,977,635 7,676,779
17 Equipment Costs 12,749,437 5,561,235
18 Roads, Railroads, and Bridges 50,448 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 31,221,299 15,255,895
21 Cost per KW of Installed Capacity (line 20 / 5) 2109.5472 1,525.5895
22 Production Expenses
10,049 19,416 23 Operation Supervision and Engineering
24 Water for Power 0 0
25 Hydraulic Expenses 95 474
26 Electric Expenses 555,976 557,976
27 Misc Hydraulic Power Generation Expenses 30,542 55,681
28 Rents 0 0
29 Maintenance Supervision and Engineering 2,492 15,349
30 Maintenance of Structures 1,578 4,579
31 Maintenance of Reservoirs, Dams, and Waterways 141,080 -37,860
32 Maintenance of Electric Plant 79,552 134,141
33 Maintenance of Misc Hydraulic Plant 937 3,239
34 Total Production Expenses (total 23 thru 33) 822,301 752,995
35 Expenses per net KWh 0.0080 0.0126
FERC FORM NO. I (REV. 12-03) Page 406
Name of Respondent
Avista Corporation
This Re ort Is:
AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 201 2/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2545
Plant Name: Nine Mile Falls
(d)
FERC Licensed Project No. 2545
Plant Name: Post Falls
(e)
FERC Licensed Project No. 2058
Plant Name: Cabinet Gorge
(f)
Line
No.
-
Run-of-River Storage Storage 1
Conventional Conventional Outdoor 2
1908 1906 1952 3
1994 1980 1953 4
26.40 14.80 265.00 5
22 261 2646
8,715 8,186 8,740 7
8
18 18 2959
18 18 25510
1 1 1211
106,194,000 82,967,000 1,198,885,000 12
13
33,429 3,570,115 11,550,027 14
3,950,732 1,466,897 10,942,975 15
13,619,813 6,344,384 31,786,471 16
12,560,784 3,171,979 46,900,620 17
625,181 0 1,098,564 18
0 0 0
30,789,939 14,553,375 102,278,657 20
1,166.2856 983.3361 385.9572 21
22
524 106,918 94,164 23
0 0 0 24
1,741 11 0 25
631,502 646,740 1,204,847 26
32,320 31,988 115,131 27
0 0 0 28
41,452 25,353 27,414 29
31,842 18,615 227,613 30
49,218 262,530 92,203 31
271,387 .193,659 460,001 32
588 14,161 50,175 33
1,060,574 1,299,975 2,271,548 34
0.0100 0.0157 0.0019 35
FERC FORM NO. I (REV. 12-03) Page 407
Name of Respondent
Avista Corporation
This Re ort Is:
(2) E] A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants)
1.Large plants are hydro plants of 10,000 Kw or more of installed capacity (name plate ratings)
2.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 lithe approximate average number of employees assignable to each
plant.
Line
No.
Item
(a)
FERC Licensed Project No. 2058
Plant Name: Noxon Rapids
(b)
FERC Licensed Project No. 2545
Plant Name: Long Lake
(C)
1 1 Kind of Plant (Run-of-River or Storage) Storage Storage
2 Plant Construction type (Conventional or Outdoor) Outdoor Conventional
3 Year Originally Constructed 1959 1915
4 Year Last Unit was Installed 1977 1924
5 Total installed cap (Gen name plate Rating in MW) 480.601 70.00
6 INet Peak Demand on Plant-Megawatts (60 minutes) 5371 89
7 Plant Hours Connect to Load 8,748 7,684
8 Net Plant Capability (in megawatts)
622 90 9 (a) Under Most Favorable Oper Conditions
10 (b) Under the Most Adverse Oper Conditions 580 90
11 Average Number of Employees 13 5
12 Net Generation, Exclusive of Plant Use - Kwh 1,822,999,0001 513,474,000
13 Cost of Plant
35,624,343 1,765,942 14 Land and Land Rights
15 Structures and Improvements 14,911,402 2,428,620
16 Reservoirs, Dams, and Waterways 32,991,048 16,672,732
17 Equipment Costs 105,923,602 12,176,179
18 Roads, Railroads, and Bridges 246,561 0
19 Asset Retirement Costs 0 0
20 TOTAL cost (Total of 14 thru 19) 189,696,956 33,043,473
21 Cost per KW of Installed Capacity (line 20/ 5) 394.7086 472.0496
22 Production Expenses
97,245 117,198 23 Operation Supervision and Engineering
24 Water for Power 0 0
25 Hydraulic Expenses 108,221 9,952
26 Electric Expenses 1,246,803 750,618
27 Misc Hydraulic Power Generation Expenses 131,698 59,370
28 Rents 0 0
29 Maintenance Supervision and Engineering 24,264 6,450
30 Maintenance of Structures 120,543 116,267
31 Maintenance of Reservoirs, Dams, and Waterways 92,448 596,307
32 Maintenance of Electric Plant 883,402 324,905
33 Maintenance of Misc Hydraulic Plant 73,594 33,895
34 Total Production Expenses (total 23 thru 33) 2,778,218 2,014,962
35 Expenses per net KWh 0.0015 0.0039
FERC FORM NO. I (REV. 12-03) Page 406.1
Name of Respondent
Avista Corporation
This Re ort Is:
(2) F]A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
HYDROELECTRIC GENERATING PLANT STATISTICS (Large Plants) (Continued)
5.The items under Cost of Plant represent accounts or combinations of accounts prescribed by the Uniform System of Accounts. Production Expenses
do not include Purchased Power, System control and Load Dispatching, and Other Expenses classified as "Other Power Supply Expenses."
6.Report as a separate plant any plant equipped with combinations of steam, hydro, internal combustion engine, or gas turbine equipment.
FERC Licensed Project No. 2545
Plant Name: Little Falls
(d)
FERC Licensed Project No. 0
Plant Name:
(e)
FERC Licensed Project No. 0
Plant Name:
(f)
Line
No. -
Run-of-River
Conventional 2
1910 3
1911
32.00 0.001 0.00 5
381 01 01 6
7,633 0 01 7
8
36 0 09
36 0 010
5 0 011
201 ,982,000 0 0 12
4,325,371 0 0
13
14
1,188,042 0 0 15
5,065,501 0 0 16
6,140,499 0 0 17
0 0 0
0 0 0
16,719,413 0 0 20
522.4817 0.0000 0.0000 = 21
22
0 0 o
0 0 0 24
9,945 0 025
654,236 0 0 26
19,125 0 0 27
812,382 0 0 28
5,047 0 Q 29
50,418 0 0 30
112,862 0 0 31
154,090 0 0 32
973 0 033
1,819,078 0 0 34
0.0090 0.0000 0.0000 35
FERC FORM NO. 1 (REV. 12-03) Page 407.1
Name of Respondent
Avista Corporation
This Re ort Is:
(1)X An Original
(2)JA Resubmission.
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
GENERATING PLANT STATISTICS (Small Plants)
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.
Line
No.
Name of Plant
(a)
Year
Orig. Const.
(b)
Installed Capacity
Name Plate Ratin
(In MW)
(c)
Net Peak Demand
(6'n
' (3 '
Net Generation Excluding Plant Use
(e)
Cost of Plant
(f)
I Kettle Falls CT 2002 7.20 8.0 860,000 9,178,263
2
3
4
5
6
7
a
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
Avista Corporation
This Re ort Is:
[]A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
GENERATING PLANT STATISTICS (Small Plants) (Continued)
3. List plants appropriately under subheadings for steam, hydro, nuclear, internal combustion and gas turbine plants. For nuclear, see instruction 11,
Page 403. 4. If net peak demand for 60 minutes is not available, give the which is available, specifying period. 5. If any plant is equipped with
combinations of steam, hydro internal combustion or gas turbine equipment, report each as a separate plant. However, if the exhaust heat from the gas
turbine is utilized in a steam turbine regenerative feed water cycle, or for preheated combustion air in a boiler, report as one plant.
Plant Cost (Incl Asset
Retire. Costs) Per MW
(g)
Operation
Exc'l. Fuel
(h)
Production Expenses
Kind of Fuel
(k)
Fuel Costs (in cents
(per Million Btu)
(I)
L me
Fuel
(i)
Maintenance
(j)
1,274,759 75,672 33,050 29,273 Nat Gas 327 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 411
Name of Respondent
Avista Corporation
This Report Is:
(1)LJAn Original
(2)UA Resubmission
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINE STATISTICS
1.Report information concerning transmission lines, cost of lines, and expenses for year. List each transmission line having nominal voltage of 132
kilovolts or greater. Report transmission lines below these voltages in group totals only for each voltage.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by a State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.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 (9) 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.
Line
No.
-
DESIGNATION VOLTAGE (KV) (Indicate where other than
60 cycle, 3 phase)
Type o
Supporting
Structure
(e)
LENGTH (Pole miles) (In tfle case of undergrouna lines report circuit miles)
Number
Of
Circuits
(h)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
On Structure ofDesi
on Struçures of Line
(g)
1 Group Sum 60.0c 60.00 1.00
2
3 Group Sum • 115.0c 115.00 1,535.00
4
5 Beacon Sub #4 BPA Bell Sub 230.0 230.00 Steel Tower 1.00 1
6 Beacon Sub BPA Bell Sub 230.0 230.00 H Type 5.00 1
7 Beacon Sub #5 BPA Bell Sub 230.0 230.00 Steel Pole 4.00 1
8 Beacon Sub #5 BPA Bell Sub 230.0 230.00 H Type 2.00 1
9 Beacon Cabinet Gorge Plant 230.0 230.00 Steel Tower 1.00
10 Beacon Cabinet Gorge Plant 230.0 230.00 Steel Pole 28.00 2
11 Beacon Cabinet Gorge Plant 230.0(. 230.00 H Type 53.00 1
12 Beacon Sub Lolo Sub 230.0 230.00 Steel Tower 1.00 1
13 Beacon Sub Lolo Sub 230.0 230.00 H Type 102.00 1
14 Benewah Shawnee 230.0 230.00 Steel Pole 60.00 1
15 Noxon Plant Pine Creek Sub 230.0 230.00 Steel Pole 29.00 1
16 Noxon Plant Pine Creek Sub 230.01 230.00 H Type 14.00 1
17 Cabinet Gorge Plant Noxon 230.01 230.00 H Type 19.00 1
18 Benewah Sw. Station Pine Creek Sub 230.01 230.00 Steel Tower
19 Benewah Sw. Station Pine Creek Sub 230.01 230.00 H Type 43.00 1
20 Divide Creek Lolo Sub 230.01 230.00 Steel Tower 1
21 Divide Creek Lolo Sub 230.01 230.00 H Type 43.00 1
22 N. Lewiston Walla Walla 230.01 230.00 H Type 43.00 1
23 N. Lewiston Walla Walla 230.01 230.00 Steel Pole 4.00 1
24 N. Lewiston Shawnee 230.01 230.00 Steel Pole 7.00 1
25 N. Lewiston Shawnee 230.Oq 230.00 H Type 27.00 1
26 Walla Walla Wanapum 230.01 230.00 Alum 1
27 Walla Walla Wanapum 230.01 230.00 H Type 78.00 1
28 BPA (Libby) Noxon Plant 230.0' 230.00 Steel Tower 1.00 1
29 BPNHot Springs #1 Noxon Plant 230.0' 230.00 Steel Tower 1.00 1
301 BPNH0t Springs #2 Noxon Plant (dead) 230.0 230.00 Steel Tower 2.00 1
31 BPAIH0t Springs #2. Noxon Plant 230.01 230.00 H Type 68.00 1
32 BPA Line West Side Sub 230.0 230.00 Steel Pole 2.00 2
33 Hatwai N. Lewiston Sub 230.0i 230.00 H Type 7.00 1
34 Divide Creek lmnaha 230.01 230.00 H Type 20.00 1
35 Cobstrip Plant Broadview 500.00 500.00
TOTAL 2,198.00 3.00 32
FERC FORM NO. I (ED. 12-87) Page 422
Name of Respondent
Avista Corporation
This Re ort Is:
An Original
(2) E] A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINE STATISTICS (Continued)
7.Do not report the same transmission line structure twice. Report Lower voltage Lines and higher voltage lines as one line. Designate in a footnote if
you do not include Lower voltage lines with higher voltage lines. 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 (I) on the book cost at end of year.
Size of
COST OF LINE (Include in Column (j) Land,
Land rights, and clearing right-of-way)
EXPENSES, EXCEPT DEPRECIATION AND TAXES
Conductor
and Material
(i)
Land
(j)
Construction and
Other Costs (k)
Total Cost
(I)
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(°)
Total
Expenses
(P)
Line
136,03E 498,412 634,450
2
9,921,384 119,820,203 129,741,587 287,452 1,009,993 1,297,44a 3
4
1272 ACSS 5
1272 ACSS 17,91 1,316,679 1,334,591 6
1272 ACSS 7
1272 ACSS 30,32: 3,275,357 3,305,680 8
1272 ACSS 9
1590 ACSS 10
1590 ACSR 1,118,77 36,035,588 37,154,362 225 87,185 87,41' 11
1272 ACSS 12
1272 McMAL 456,162 8,425,652 8,881,814 19,983 19,981 13
1590ACSS 570,207 48,024,931 48,595,138 1,807 5,039 6,84E 14
1272 ACSR 15
54McMAL 1,052,73" 17,987,859 19,040,592 2,617 541,564 544,181 16
54 McMAL 177,73 1,306,125 1,483,858 7,521 7,521 17
54McMAL 18
54McMAL 285,24 2,605,672 2,890,912 23,018 38,394 61,412 19
1272 McMAL 20
1272McMAL 86,22E 3,698,864 3,785,092 15,592 1,164 16,75e 21
1272 McMAL 22
1272 McMAL 623,98 6,978,675 7,602,659 3,383 1,251 4,634 23
1272 ACSR 24
1272 ACSR 872,150 10,042,777 10,914;927 1,900 1 90C 25
1272 McMAL 26
1272 MGMAL 70,781 2,709,710 2,780,491 7,396 16,158 23,554 27
1272 ACSR 28
272ACSR 19,521 19,521 1,856 4,888 6,744 29
1272 McMAL 30
1272 McMAL 293,365 4,039,470 4,332,835 7,214 34,451 41,66E 31
1272 ACSR 36,461 594,543 631,004 32
1590ACSR 106,581 2,722,818 2,829,399 997 202 1,19 33
1272McMAL 201,35S 1,312,849 1,514,208 178 1,710 1,88E 34
595,789 30,117,774 30,713,563 62,425 205,692 91,626 359,74 35
16,653,204 301,533,479 318,186,683 414,160 1,977,095 91,626 2,482,881 36
FERC FORM NO. 1 (ED. 12-87) Page 423
Name of Respondent
Avista Corporation
This Report Is:

(1) An Original
I (2) flA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
tRANSMISSION LINES ADDED DURING YEAR
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 (I) to (o), it is permissible to report in these columns the
Line
No.
-
LINE DESIGNATION Line Length
Miles
(C)
SUPPORTING STRUCTURE CIRCUITS PER STRUCTUR
From
(a)
To
(b)
Type
(d)
Avere
NumbJ per
Miles
(e)
Present
(f)
Ultimate
(g)
1 No additions during 2012
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 TOTAL
FERC FORM NO. 1 (REV. 12-03) Page 424
Name of Respondent
Avista Corporation
This Report Is:
(1)An Original
(2)flA Resubmission
Date of Report (Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
TRANSMISSION LINES ADDED DURING YEAR (Continued)
costs. Designate, however, if estimated amounts are reported. Include costs of Clearing Land and Rights-of-Way, and Roads and
Trails, in column (I) 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.
CONDUCTORS Voltage
KV
(Operating) (k)
LINE COST ___________ Line
No.
-
Size
(h)
Specification
(i)
Conficiuration
and spacing
(j)
__________
Land and
Land Rights
(I)
_________
Poles, Towers
and Fixtures
(m)
Conductors
and Devices (n)
Asset
Retire. Costs
(0)
Total
(p)
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
43
44
FERC FORM NO. I (REV. 12-03) Page 426
Name of Respondent
Avista Corporation
This Re ort Is:
(2)
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.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).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(C)
Secondary
(d)
Tertiary
(e)
1 STATE OF WASHINGTON
2
3 Airway Heights Distr. Unattended 115.00 13.80
4 Barker Road Distr. Unattended 115.00 13.80
5 Beacon Trnsm. & Distr Unatt 230.00 115.00 13.80
6 Boulder Trnsm. Unattended 230.00 115.00 13.80
7 Chester Distr. Unattended 115.00 13.80
8 Chewelah 115Kv Distr. Unattended 115.00 13.80
9 Colbert Distr. Unattended 115.00 13.80
10 College & Walnut Distr. Unattended 115.00 13.80
11 Colville 11 5K Distr. Unattended 115.00 13.80
12 Critchfield Distr. Unattended 115.00 13.80
13 Deer Park Dist. Unattended 115.00 13.80
14 Dry Creek Transm. Unattended 230.00 115.00 13.80
15 Dry Gulch Distr. Unattended 115.00 13.80
16 East Colfax Distr. Unattended 115.00 13.80
17 1 East Farms Distr. Unattended 115.00 13.80
18 Fort Wright Distr. Unattended 115.00 13.80
19 Francis and Cedar Distr. Unattended 115.00 13.80
20 Gifford Distr. Unattended 115.00 34.00
21 Glenrose Distr. Unattended 115.00 13.80
22 Greenwood Distr. Unattended 115.00 13.80
23 Hallett & White Distr. Unattended 115.00 13.80
24 Indian Trail Dist. Unattended 115.00 13.80
25 Industrial Park Dist. Unattended - 115.00 13.80
26 Kettle Falls Distr. Unattended 115.00 13.80
27 Lee & Reynolds Distr. Unattended 115.00 13.80
28 Liberty Lake Distr. Unattended 115.00 13.80
29 Little Falls 115/34Kv Distr. Unattended 115.00 34.00
30 Lyons & Standard Distr. Unattended 115.00 13.80
31 Mead Distr. Unattended 115.00 13.80
32 Metro Distr. Unattended 115.00 13.80
33 Milan Distr. Unattended 115.00 13.80
34 Millwood Dist. Unattended 115.00 13.80
35 Ninth & Central Distr. Unattended 115.00 13.80
36 Northeast Distr. Unattended 115.00 13.80
37 1 Northwest Distr. Unattended 115.00 13.80
38 Opportunity Dist. Unattended 115.00 13.80
39 Othello Distr. Unattended 115.00 13.80
40 Post Street Distr. Unattended 115.00 13.80
FERC FORM NO. I (ED. 12-96) Page 426
Name of Respondent
Avista Corporation
This Re ort Is:
(1)X An Original
(2)JA Resubmission
Date of Report (Mo, Da, Yr)
04112/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS (Continued)
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.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
U)
Total Capacity
(k)
2
24 2 Frcd Oil&Air Fan&Cap 39 40 3
12 1 Two Stage Fan 1 20 4
536 4 Two Stage Fan 2 560 5
300 2 Two Stage Fan 2 500 6
24 2 Frcd Oil & Air Fan 2 40 7
12 1 Two Stage Fan 1 20 8
12 1 Fred OiI& Air Fan 16 20 9
36 2 Two Stage Fan 2 60 10
31 3 Frcd Oil & Air Fan 3 45 11
12 1 Two Stage Fan 1 20 12
12 1 Two Stage Fan 1 20 13
150 1 Two Stage Fan &Caps 223 250 14
24 2 Fred Oil & Air Fan 2 40 15
12 1 FrOiI/Air Fan 1 20 16
12 1 Two Stage Fan 1 20 17
24 2 1 Fr OiI/Air/2Stg Fan 2 40 18
36 2 Two Stage Fan 2 60 19
12 1
12 1 Fred Oil & Air Fan 1 20 21
12 1 Two Stage Fan 1 20 22
12 1 Two Stg Fan 1 20 23
12 1 Two Stage Fan 1 20 24
24 2 Two Stg/Pt/Frcd Oil 14 45 25
12 1 Fred Oil & Air Fan 1 20 26
12 1 Two Stage Fan 1 20 27
24 2 Two Stage Fan 2 40 28
12 1
36 2 Two Stage Fan 2 60 30
18 1 Two Stage Fan 1 30 31
24 2 Two Stage Fan 2 40 32
24 2 Fred Oil & Air Fan 2 40 33
24 2 2 FrcAir/FrcOil/AirFan 2 40 34
24 2 1 Fred & Two Stage Fan 2 40 35
24 2 Two Stage Fan 2 40 36
24 2 Two Stage Fan 2 40 37
12 1 Two Stage Fan 1 20 38
24 2 FrOil/AirFan 40 39
36 2 Fred Oil & Wt Fan 2 60 40
FERC FORM NO. 1 (ED. 12-96) Page 427
Name of Respondent
Avista Corporation
This Re ort Is:
(2) []A Resubmi sion
Date of Report
(Mo, Da, Yr)
04/12/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.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 (t).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Pound Lane Distr. Unattended 115.00 13.80
2 1 Ross Park Distr. Unattended 115.00 13.80
3 Roxboro Distr. Unattended 115.00 24.00
4 Shawnee Trans. Unattended 230.00 115.00 13.80
5 Silver Lake Distr. Unattended 115.00 13.80
6 Southeast Distr. Unattended 115.00 13.80
7 South Othello Distr. Unattended 115.00 13.80
8 South Pullman Distr. Unattended 115.00 13.80
9 Sunset Distr. Unattended 115.00 13.80
10 Terre View Dist. Unattended 115.00 13.80
11 Third & Hatch Distr. Unattended 115.00 13.80
12 ITurner Dist. Unattended 115.00 13.80
13 Waikiki Distr. Unattended 115.00 13.80
14 West Side Trans. Unattended 230.00 115.00 13.80
15 Other: 28substa less than 1 OMVA Distr. Unattended
16
17 STATE OF IDAHO
18 Appleway Dist. Unattended 115.00 13.80
19 Avondale Dist. Unattended 115.00 13.80
20 Benewah Trans. Unattended 230.00 115.00 13.80
21 Big Creek Distr. Unattended 115.00 13.80
22 Blue Creek Distr. Unattended 115.00 13.80
23 Bunker Hill Limited Distr. Unattended 115.00 13.80
24 Cabinet Gorge (Switchyard) Trans. Unattended 230.00 115.00 13.80
25 Clark Fork Distr. Unattended 115.00 21.80
26 Coeur d'Alene 15th Ave Distr. Unattended 115.00 13.80
27 Cottonwood Distr. Unattended 115.00 24.90
28 Dalton Distr. Unattended 115.00 13.80
29 Grangeville Distr. Unattended 115.00 13.80
30 Holbrook Distr. Unattended 115.00 13.80
31 Huetter Distr. Unattended 115.00 13.80
32 Idaho Road Distr Unattended 115.00 13.80
33 Juliaetta Distr. Unattended 115.00 13.80
34 Kamiah Dist. Unattended 115.00 13.80
35 Kooskia Distr. Unattended 115.00 13.80
36 Lolo Tran & Dist Unattnd 230.00 115.00 13.80
37 1 Moscow Distr. Unattended 115.00 13.80
38 Moscow 230Kv Tran & Dist Unattnd 230.00 115.00 13.80
39 North Moscow Distr. Unattended 115.00 13.80
40 North Lewiston 230kV Trans Unattended 230.00 115.00 13.80
FERC FORM NO. 1 (ED. I296) Page 426.1
Name of Respondent
Avista Corporation
This Re ort Is: Date of Report
04/1212013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS (Continued)
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.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(i)
Number of Units
(j)
Total Capacity
(k)
24 2 Two Stage Fan 2 40 1
30 2 Two Stage Fan 2 54 2
24 2 Two Stage Fan 2 40 3
150 1 Two Stage Fan 1 250 4
12 1 Frcd Oil &Air Fan 1 20 5
30 2 Two Stage Fan 2 50 6
12 1 Two Stage Fan 1 20 7
30 2 Two Stage Fan 2 50 8
33 2 Two Stage Fan & Caps 50 55 9
12 1 Two Stage Fan 1 20 10
54 3• Two Stg Fan & Cap 103 90 11
36 2 Two StgFan 2 60 12
24 2 Two Stage Fan 2 40 13
250 2
166 34 3 1 15
16
17
36 2 Two Stage Fan 2 60 18
12 1 Two Stage Fan 1 20 19
75 1 Two Stage Fan & Caps 223 125 20
18 2 Portable Fan . 2 22 21
20 3 1
12 1 Frcd Air Fan 1 16 23
75 1 Two Stage Fan 1 125 24
10 1 Frcd Air Fan 1 13 25
36 2 . Two Stage Fan 2 60 26
12 1 Two Stage Fan 1 20 27
24 2 FrcOil/Air2StgFan 2 40 28
25 4 FrcdOillAir/Pt Fan&C 17 34
12 1 Two Stage Fan 1 20 30
12 1 Two Stage Fan 1 20 31
12 1 Two Stage Fan 1 20 32
12 1 Frcd Oil & Air Fan 1 20 33
12 i Two Stage Fan 1 20 34
15 3 Frcd Air Fan 3 20 35
262 3 Frcd Oil/Air/Two Stg 1 270 36
24 2 FrOiI/Air/2Stg Fan 2 40 37
137 . 2 2 Capacitors 48 38
12 1 Two Stage Fan 1 20 39
250 1 1 Capacitors 48 . 40
FERC FORM NO. I (ED. 12-96) Page 427.1
Name of Respondent
Avista Corporation
This Re ort Is:
EArriri
(2) []A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.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 (t).
Line
No
-
Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 North Lewiston Distr. Unattended 115.00 13.80
2 Oden Distr. Unattended 115.00 21.80
3 Oldtown Distr. Unattended 115.00 21.80
4 Orofino Distr. Unattended 115.00 13.80
5 Osburn Distr. Unattended 115.00 13.80
6 Pine Creek Tran & Dist Unattnd 230.00 115.00 13.80
7 Pleasant View Distr. Unattended 115.00 13.80
8 Plummer Dist Unattended 115.00 13.80
9 Post Falls Distr. Unattended 115.00 13.80
10 Potlatch Distr. Unattended 115.00 13.80
11 Prarie Distr. Unattended 115.00 13.80
12 1 Priest River Distr. Unattended 115.00 20.80
13 Rathdrum Trans & Distr Unattd 230.00 115.00 13.80
14 Sagle Dist. Unattended 115.00 20.80
15 Sandpoint Distr. Unattended 115.00 20.80
16 South Lewiston Distr. Unattended 115.00 13.80
17 Sweetwater Distr. Unattended 115.00 24.90
18 St. Manes Distr. Unattended 115.00 23.90
19 Tenth & Stewart Distr. Unattended 115.00 13.80
20 Wallace Distr. Unattended 115.00 13.80
21 Other: 13 substa less than 10 MVA Distr. Unattended
22
23 STATE OF MONTANA
24 1 substation less than 10 MVA Distr. Unattended
25
26 SUBSTA. © GENERATING PLANTS
27 STATE OF WASHINGTON
28 Boulder Park Trans. Attended 115.00 13.80
29 Kettle Falls Trans. Attended 115.00 13.80
30 Long Lake Trans. Attended 115.00 4.00
31 Nine Mile Trans. Attended 115.00 13.80 2.30
32 Little Falls Trans. Attended 115.00 4.00
33 Northeast Trans. Attended 115.00 13.80
34 Post Street Trans. Attended 13.80 4.00
35
36 STATE OF IDAHO
37 1 Cabinet Gorge (HED) Trans. Attended 230.00 13.80
38 Post Falls Trans. Attended 115.00 2.30
39 Rathdrum Trans. Attended 115.00 13.80
40 STATE OF MONTANA
FERC FORM NO. I (ED. 12-96) Page 426.2
Name of Respondent
Avista Corporation
This Re ort Is:
2l1::ssion
Date of Report
04/12/2013
Year/Period of Report
End of 2012/Q4
SUBSTATIONS (Continued)
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.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
In Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Lane
No.
-
Type of Equipment
(I)
Number of Units
- (j)
Total Capacity
(k)
10 3 1
10 1 Frcd Air Fan 1 13 2
18 2 Frcd Air Fan 2 22 3
20 2 Fred Oil & Air Fan 1 28 4
12 1 Portable Fan 1 15 5
262 3 Two Stg Fan/Capacito 45 270 6
12 1 Two Stage Fan 1 20 7
12 1 Two Stage Fan 1 20 8
18 1 Two Stage Fan 1 30 9
15 2 Portable Fan 2 19 10
12 1 Frcd Oil & Air Fan 1 20 11
10 1 Frcd Air Fan 1 13 12
474 4 Frcd Oil & Air Fan 50 490 13
12 1 Two Stage Fan 1 20 14
30 3 Frcd Air Fan 3 38 15
27 4 Port Fan/FrcdOiI/Air 4 39 16
12 1 Frcd Oil &Air Fan 1 20 17
24 2 Two Stage Fan. 2 40 18
30 2 Frcd Oil/Air/Two Stg 2 50 19
10 3 . 20
70 13
22
23
5 1
25
26
27
36 1 Two StageFan 1 60 28
34 1 1 Two StageFan 1 62 . 29
80 4 1 30
24 2 . Frcd Oil & Air Fan 1 40 31
24 2 Fred Oil & Air Fan 2 40 32
-36 1 TwoStageFan 1 60 33
35 2 .
35
36
300 6 1 Fred Oil and Air Fan 37
16 . 2 Frcd Air/Oil/Air Fan 2 21 38
114 2 1 Two StageFan 2 190 39
40
FERC FORM NO. I (ED. 12-96) Page 427.2
Name of Respondent
Avista Corporation
This Re ort Is:
(2) []A Resubmission
Date of Report
04/12/2013
Year/Period of Report
End of 2012/04
SUBSTATIONS
1.Report below the information called for concerning substations of the respondent as of the end of the year.
2.Substations which serve only one industrial or street railway customer should not be listed below.
3.Substations with capacities of Less than 10 MVa except those serving customers with energy for resale, may be grouped according
to functional character, but the number of such substations must be shown.
4.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 (1).
Line
No.'o Name and Location of Substation
(a)
Character of Substation
(b)
VOLTAGE (In MVa)
Primary
(c)
Secondary
(d)
Tertiary
(e)
1 Noxon Trans. Attended 230.00 13.80
2
3 STATE OF OREGON
4 Coyote Springs Il Trans. Attended 500.00 13.80 18.00
5
6 SUMMARY:
7 Washington:
8 4 subs Trans. Unattended
9 75 subs Distr. Unattended
10 1 subs Tran & Dist Unattnd
11 7 subs Trans. Attended
12 1 Idaho:
13 3subs Trans. Unattended
14 48 subs Distr. Unattended
15 4 subs Tran & Dist Unattnd
16 3 subs Trans. Attended
17 1 Montana: 1 sub Trans. Attended
18 1 sub Distr. Unattended
19 Oregon: 1 sub Trans. Unattended
20 System: 148 subs
21
22
23
24
25
26
27
28
29
30
31
32
34
35
36
37
38
39
40
FERC FORM NO. I (ED. 12-96) Page 426.3
Name of Respondent
Avista Corporation
This Re ort Is:
AResubmission
Date of Report
04/12/2013
Year/Period of Report
End of 201 2/Q4
SUBSTATIONS (Continued)
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.
Capacity of Substation
(In Service) (In MVa)
(f)
Number of
Transformers
n Service
(g)
Number of
Spare
Transformers
(h)
CONVERSION APPARATUS AND SPECIAL EQUIPMENT Line
No.
-
Type of Equipment
(I)
Number of Units
(i)
Total Capacity
(k)
435 9 1 Two Stage Fan 2 635 1
2
3
213 1 1 Two Stage fan 1 355 4
6
7
850 8
1200 9
536 10
269 11
12
400
668
1135
430
435 17
5 -
213 19
6141
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
Avista Corporation
This Re ort Is:
AResubmission
Date of Report
04/12/203
Year/Period of Report
End of 2012/04
TRANSACTIONS WITH ASSOCIATED (AFFILIATED) COMPANIES
1.Report below the information called for concerning all non-power goods or services received from or provided to associated (affiliated) companies.
2.The reporting threshold for reporting purposes is $250,000. The threshold applies to the annual amount billed to the respondent or billed to
an associated/affiliated company for non-power goods and services. The good or service must be specific in nature. Respondents should not
attempt to include or aggregate amounts in a nonspecific category such as "general".
3.Where amounts billed to or received from the associated(affiliated) company are based on an allocation process, explain in a footnote.
Line
No. Description of the Non-Power Good or Service
(a)
Name of
Associated/Affiliated
Company
(b)
Account
Charged or
Credited
(C)
Amount Charged or
Credited
(d)
1 Non-power Goods or Services Provided by Affiliated
2
3
4
5
6
7
8
9
10
11
12
13
14
15
16
17
18
19
20 Non-power Goods or Services Provided for Affiliate
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
37
38
39
40
41
42
FERC FORM NO. I (New) Page 429
FERC FORM NO. I-F (New)
VU 10
E
2OU•PR3O PM 2:35
Avista Corp.
2012
IDAHO
State Electric Annual Report
C 61-405)
This Page Iitentiona11y Left Blank
Name of Respondent
Avista Corporation
This Report is:
An Original
EJ A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012 / Q4
STATEMENT OF UTILITY OPERATING INCOME - IDAHO
Instructions
1.For each account below, report the amount attributable to the state of Idaho based on Idaho jurisdictional Results of Operations.
2.Provide any necessary important notes regarding this statement of utility operating income in a footnote in the available space at the bottom of this page
Line
No.
-
Account
(a)
Refer to
Form I
Page
(b)
TOTAL SYSTEM - IDAHO
Current Year
(c)
Prior Year
(d)
1 UTILITY OPERATING INCOME
450.171.070 I 490.828.505 Operating Revenues (400) 300-301
3 Operating Expenses
4 Operation Expenses (401) 320-323 313,684,985 I 372,734,080
5 P 7
2
Maintenance Expenses (402) 320-323 20,099,052 1,449,373
6 Depreciation Expense (403) 336-337 33,505,585 32,159,853
Depreciation Expense for Asset Retirement Costs (403.1) 336-337 - -
8_ - Amortization & Depletion of Utility Plant (404-405) 336-337 3,047,756 2,650,538
9_ - Amortization of Utility Plant Acquisition Adjustment (406) 336-337 67,304 67,304
10 Amort. of Property Losses, Unrecov Plant and Regulatory Study Costs (407) - -
11 Amortization of Conversion Expenses (407)
12 Regulatory Debits (407.3) (1,870,742) (9,642,712)
13 (Less) Regulatory Credits (407.4) (5,824,027') (2,460,999)
14 Taxes Other Than Income Taxes (408.1) 262-263 14,639,363 14,029,701
15 Income Taxes - Federal (409.1) 262-263 6,730,137 11,858,943
16 - Other (409.1) 262-263 - -
17 Provision for Deferred Income Taxes (410.1) 234 272-277 10,655,054 8,946,025
18 Less) Provision for Deferred Income Taxes-Cr. (411.1) 234, 272-277 - -
19 Investment Tax Credit Adjustment - Net (411.4) 266 (85,353) (69,896)
20 (Less) Gains from Disposition of Utility Plant (411.6)
21 Losses from Disposition Of Utility Plant (411.7)
22 Less) Gains from Disposition of Allowances (411.8)
23 Losses from Disposition of Allowances (411.9)
24 Accretion Expense (411.10) - -
25 TOTAL Utility Operating Expenses (Total of line 4 through 24) 394,649,114 431,722,210
26 Net Utility Operating Income (Total line 2 less 25) 55,521,956 59,104,295
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.114-115
Name of Respondent
Avista Corporation
This Report i
An Original
A Resubmission
Date of Report
mmldd/yyyy
4/12/2013
Year / Period of Report
End of 2012 / Q4
STATEMENT OF UTILITY OPERATING INCOME - IDAHO
Instructions
or in a separate schedule.
3. Explain in a footnote if the previous years figures are differei it from those reported in prior reports.
ELECTRIC UTILITY GAS UTILITY OTHER UTILITY Line
Current Year Prior Year
(e) (f)
• 354.298.765 I 374.727.202

237,642,238 276,342,925
I
urrent Year
I () I
I 95.872.305 I
76,042,747
Prior Year
(h)
116.099.303
96,391,155
Current Year
(I)
I
Prior Year
Ii)
I I
I
No.
I 2
3
I
17,657900 2,441,152 1,449,373 -
28,775,543 27,602,346 4,730,042 4,557,507 -
7
2,502,863 2,133,508 544,893 517,030
67,304 67,304
10
11
(1,870,742) (9,332,082' (310,630) .12
(5,824,027) (2,460,999) 13
12,291,725 11,783,114 2,347,638 2,246,587 .ii.
6,585,305 11,102,578 144,832 756,365 1 5
16
8,217,502 6,419,332 2,437,552 2,526,693 IL.
18
(68,625) (52,928) (16,728) (16,968) IL
20
21
22
23
______ ___ ______________________ 24
305,976,986 323,605,098 88,672,128 108,117,112 - -
48,321,779 1 51,122,104 1 7,200,177 1 7,982,191 - - 26
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) 1 E.ID.1 14-DIe
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012 / Q4
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION - IDAHO
Instructions
1.Report below the original cost of utility plant in service necessary to furnish utility service to customers in the state of Idaho, and the
accumulated provisions for depreciation, amortization, and depletion attributable to that plant in service.
2.Report in column (c) the amount for electric function, in column (d) the amount for gas function, in columns (e), (U and (g) report other (specify),
Line
No.
-
1
Account
(a)
Total Company
I End of Current Year
(b)
Electric
(C)
1 Utility Plant
2 InService
3 1PIant in Service (Classified) 1327,736,695 1,079,511442
4 Property Under Capital Leases 334,898
5 Plant Purchased or Sold -
6 Completed Construction not Classified -
7 Experimental Plant Unclassified -
8 Total (Total lines 3 through 7) 1,328,071593 1,079,511,442
9 Leased to Others -
10 Held for Future Use 414,587 199,007
11 Construction Work in Progress 42,866,262 28,686,005
12 Acquisition Adjustments
13 Total Utility Plant (Total lines 8 through 12) 1,371,352,441 1 1108,396,454
14 Accumulated Provision for Depreciation, Amortization, and Depletion 470,102,780 389,935,675
15 Net Utility Plant (Line 13 less line 14) 901,249.661 718,460.779
16 Detail of Accumulated Provision for Depreciation, Amortization, and Depletion
17 InService
18 Depreciation 461,324,559 • 387,309,090
19 Amortization and Depletion of Producing Natural Gas Lands I Land Rights -
20 Amortization of Underground Storage Lands I Land Rights -
21 Amortization of Other Utility Plant 8,778,221 2,626,585
22 Total (Total lines 18 through 21) 470,102,780 389,935,675
23 Leased to Others
24 Depreciation -
25 Amortization and Depletion -
26 Total Leased to Others -
27 Held for Future Use
28 Depreciation -
29 Amortization -
30 Total Held for Future Use - -
31 Abandonment of Leases (Natural Gas) -
32 Amortization of Plant Acquisition Adjustment -
33 Total Accumulated Provision (Total lines 22, 26, 30, 31, 32) 470,102,780 389,935,675
(1) A small portion of the Company's electric distribution plant is located in Montana. For jurisdictional reporting purposes, those amounts are
included as Idaho plant.
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.200-201
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
nim/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012/04
SUMMARY OF UTILITY PLANT AND ACCUMULATED PROVISIONS FOR DEPRECIATION, AMORTIZATION AND DEPLETION IDAHO
Instructions
and in column (h) common function.
3. In order to accurately reflect utility plant in service necessary to furnish utility service to customers in the state of Idaho, electric and gas
plant not directly assigned is allocated to the state of Idaho as appropriate and included in column (c) and (d).
Gas
(d)
176,602,456
Other (Specify)
(e)
I
Other (Specify)
(f)
I
Other (Specify)
(g)
Common
(h)
I 71,622,797
Line
No.
2
' 3
274,405 60,493 _j
5
6
7
176,876,861 - - - 71,683,290 - -
215,580 10
1,950,046 12,230,211 11
12
179,042,487 - - - 83,913,501 13
59,175,488 - - - 20,991,617 14
119,866,998
588938491
- I - I - 62.921.884
15,121,620
15
16
17
'18
19
20
281,639 5,869,997 21
59,175
L
488 - - - 20,991,617 22
24
25
26
27
28
29
- - - - - 30
31
32
59,175,488 - - - 20,991,617 33
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.200-201
Name of Respondent
Avista Corporation
This Report is:
[] An Original
AResubrnon
Date of Report
mm/ddfyyyy
4112/2013
Year! Period of Report
End of 2012 I Q4
ELECTRIC PLANT IN SERVICE - IDAHO (Account 101,102,103 and 106)
Instructions
1.Report below the original cost of electric plant in service necessary to furnish electric utility service to customers in the state of Idaho.
Include electric plant not directly assigned as allocated to the state of Idaho.
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, include by primary plant account increases in column (C), additions, and
reductions in column (e), adjustments.
5.Enclose in parentheses credit adjustments of plant accounts to indicate the negative effect of such amounts.
6.Classify Account 106 according to prescribed accounts, on an estimated basis if necessary, and include the entries in column (c). Also to be included
in column (C) are entries for reversals of tentative distributions of prior year in column (b). Likewise, if the respondent has a significant amount of plant
retirements which have not been classified to primary accounts at the end of the year, include in column (d) a tentative distribution of such retirements,
on an estimated basis, with appropriate contra entry to the account for accumulated depreciation provision. Include also in column (d) distributions of
Line
No. Account
Balance
Beginning of Year Additions
1 1. INTANGIBLE PLANT
2 301 Organization - -
3 302 Franchises and Consents 15,311,508 1 -
4 303 Miscellaneous Intangible Plant 985,166 181,767
5 TOTAL Intangible Plant (Total of lines 2, 3, and 4) 16,296,674 181,767
6 2. PRODUCTION PLANT
7 A. Steam Production Plant
8 310 Land and Land Rights 775,285 1 9 311 Structures and Improvements 43,686,521 186,820
10 312. Boiler Plant Equipment 59,029,184 327,183
11 313 Engines and Engine-Driven Generators 2,353 -
12 314 Turbogenerator Units 17,816,722 382,552
13 315 Accessory Electric Equipment 9,417,810 96
14 316 Miscellaneous Power Plant Equipment 5,527,543 10,820
15 317 Asset Retirement Costs for Steam Production - -
16 TOTAL Steam Production Plant (Total of lines 8 through 15) 136,255,418 907,471
17 B. Nuclear Production Plant
18 320 Land and Land Rights - -
19 321 Structures and Improvements - -
20 322 Reactor Plant Equipment - -
21 323 Turbogenerator Units - -
22 324 Accessory Electric Equipment - -
23 325 Miscellaneous Power Plant Equipment - -
24 326 Asset Retirement Costs for Nuclear Production - -
25 TOTAL Nuclear Production Plant (Total of lines 18 through 24) - -
26 C. Hydraulic Production Plant
27 330 Land and Land Rights 19,928,684 810,533
28 1 331 Structures and Improvements 15,041,907 227,706
29 332 Reservoirs, Dams, and Waterways 42,655,726 669,387
30 333 Water Wheels, Turbines, and Generators 54,061,315 2,736,195
31 334 Accessory Electric Equipment 11,805,280 18,036
32 335 Miscellaneous Power Plant Equipment 2,793,427 85,307
33 336 Roads, Railroads, and Bridges 695,048 7,415
34 337 Asset Retirement Costs for Hydraulic Production - -
35 TOTAL Hydraulic Production Plant (Total of lines 27 through 34) 146,981,387 4,554,579
36 D. Other Production Plant
37 340 Land and Land Rights 14,636 -
38 341 Structures and Improvements 5,731,202 (10,616)
39 342 Fuel Holders, Products, and Accessories 7,356,445 1,904
40 343 Prime Movers 7,604,369 1,843,247
41 344 Generators 69,319,124 1,556,881
42 345 Accessory Electric Equipment 5,884,333 34,129
43 346 Miscellaneous Power Plant Equipment 565,100 (3,697)
44 347 Asset Retirement Costs for Other Production - -
45 TOTAL Other Production Plant (Total of lines 37 through 44) 96,775,209 3,421,848
46 TOTAL Production Plant (Total of lines 16, 25, 35, and 45) 380,012,014 8,883,898
(1) A small portion of the Company's electric distribution plant is located in Montana. For jurisdictional reporting purposes, those amounts are
included as Idaho plant.
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.10.204-205
Name of Respondent
Avista Corporation
This Report is:
FTJ An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year / Period of Report
End of 2012/04
ELECTRIC PLANT IN SERVICE - IDAHO (Account 101, 102,103 and 106)
Instructions
these tentative classifications in columns (C) and (d), including the reversals of the prior year's tentative account distributions of these amounts. Careful
observance of these instructions and the texts of Accounts 101 and 106 will avoid serious omissions of the reported amount of respondent's plant
actually in service at end of year.
7.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 (t) to primary
account classifications.
8.For account 399, state the nature and use of plant included in this account, and, if substantial in amount, submit a supplementary statement showing
subaccount classification of such plant conforming to the requirement of these pages.
9.For each account comprising the reported balance and changes in Account 102, state the property purchased or sold, name of vendor or purchase, and
date of transaction. If proposed journal entries have been filed as required by the Uniform System of Accounts, give also the date of such filing.
Retirements Adjustments
(d)
Transfers
Balance
End of Year
Line
No.
2
- 101,313 - 15,412,821 3
181,814 (16,939)1 968,180 _____ 4
181,814
-
84,374
445,271
-
-'
16,381,001
1,220,556
9,154,177t
,
'
5
6
7
8
888 292,278 - 44,164,731 9
112,030 710,220 - 59,954557 10_
- 16 - 2,369 11
7,738 117,890 - 18,309,426 12
2,457 (261,272) - 13
- 39,519 - 5,577,882 14
- - * - 15
123,113 1,343,922 - 138.383.698 16 .
17
- - - - 18
- - - - 19
- - - - 20
- - - - 21
- - - - 22
- - - - 23
- - - 24
- - - - 25
26
- (240,689) (221,444) 20,277,084 27
2,447 222,374 - 15,489,540 28
- (111,944) 221,444 43,434,613 29
85,063 336,817 - 57,049,264 30
6,242 83,904 - 11,900,978 31
- (34,978) - 2,843,756 32
- 4,600 - 707,063 33
- - - - 34
93,752 260,084 - 151,702,298 35
36
- 2,082 - 316,718 37
- 81,302 - 5,801,888 38
- 48,676 - 7,407,025 39
- (1,158,989) - 8,288,627 40
786,769 402,540 - 70,491,776 41
- 69,026 - 5,987,488 42
- 40,259 - 601,662 43
- - - - 44
786,769 (515,104)1 98,895,184 45
1,003,634 1 1,088,902 - 388,981,180 46
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61.405) E.ID.204-205
Name of Respondent
Avista Corporation
This Report is:
[] An Original
LI A Resubmission
Date of Report
mm/dd/yyyy
4/1212013
Year/ Period of Report
End of 2012/ Q4
ELECTRIC PLANT IN SERVICE - IDAHO (Account 101, 102,103 and 106) (Continued)
Line
No.
-
Account
(a)
Balance
Beginning of Year
(b)
Additions
(C)
47 3. TRANSMISSION PLANT
48 350 Land and Land Rights 6,691,874 111,243
49 352 Structures and Improvements 5,831,863 19,366
50 353 Station Equipment 70,660,373 4,620,853
51 354 Towers and Fixtures 5,951,197 739
52 355 Poles and Fixtures 50,614,833 6,675,835
53 356 Overhead Conductors and Devices 39,145,124 3,274,963
54 357 Underground Conduit 905,668 -
55 358 Underground Conductors and Devices 809,933 -
56 359 Roads and Trails 650,793 -
57 359.1 Asset Retirement Costs for Transmission Plant
58 TOTAL Transmission Plant (Total of lines 48 through 57) 181,261,658 14,702,999
59 4. DISTRIBUTION PLANT
60 360 Land and Land Rights 2,943,488 19,879
61 361 Structures and Improvements 5,228,068 3,805
62 362 Station Equipment 36,802,755 1,529,299
63 363 Storage Battery Equipment - -
64 364 Poles, Towers, and Fixtures 94,768,240 4,989,182
65 365 Overhead Conductors and Devices 62,578,020 3,402,347
66 366 Underground Conduit 31,009,659 802,448
67 367 Underground Conductors and Devices 48,590,338 2,447,566
68 368 Line Transformers 63,870263 2,314,736
69 369 Services 46,273,660 1,232,992
70 370 Meters 20,626,945 (8,134,590)
71 371 Installations on Customer Premises -
72 372 Leased Property on Customer Premises - -
73 373 Street Lighting and Signal Systems 13,826,257 613,544
74 374 Asset Retirement Costs for Distribution Plant - -
75 TOTAL Distribution Plant (Total of lines 60 through 74) 426,517,693 9,221,208
76 5. REGIONAL TRANSMISSION AND MARKET OPERATION PLANT
77 380 Land and Land Rights - -
78 381 Structures and Improvements - -
79 382 Computer Hardware - -
80 383 Computer Software - -
81 384 Communication Equipment - -
82 385 Miscellaneous Regional Transmission and Market Operation Plant - -
83 386 Asset Retirement Costs for Regional Transmission and Operation Plant - -
84 TOTAL Transmission and Market Operation Plant (Total lines 77 through 83) -
85 6. GENERAL PLANT
86 389 Land and Land Rights 369,788 -
87 390 Structures and Improvements 3,047,640 249,750
88 391 Office Furniture and Equipment 745,321 1,235,452
89 392 Transportation Equipment 4,937,621 635,061
90 393 Stores Equipment 136,686 -
91 394 Tools, Shop and Garage Equipment 923,350 34,557
92 395 Laboratory Equipment 351,289 -
93 396 Power Operated Equipment 11,576,127 3,025,489
94 397 Communication Equipment 14,189,489 592,605
95 398 Miscellaneous Equipment 5,878 5,727
96 SUBTOTAL (Total of lines 86 through 95) 36,283,189 5,778,641
97 399 Other Tangible Property - -
98 399.1 Asset Retirement Costs for General Plant - -
99 TOTAL General Plant (Total of lines 96, 97 and 98) 36,283,189 5,778,641
100 TOTAL (Accounts 101 and 106) 1,040,371,228 38,768,513
101 102 Electric Plant Purchased - -
102 102 (Less) Electric Plant Sold -
103 103 Experimental Plant Unclassified - -
1.2 TOTAL Electric Plant in Service (Total of lines 100 through 103) 1,040,371,228 38,768,513
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.206-207
Name. of Respondent
Avlsta Corporation .
This Report is:
An Original
LIII A Resubmission
Date of Report
mm/dd/yyyy
411 2/2013
Year / Period of Report
End of 2012 / 04
ELECTRIC PLANT IN SERVICE - IDAHO (Account 101, 102,103 and 106) (Continued)
Retirements
(d)
-
Adjustments
(e)
(25,398)
Transfers
(f)
-
Balance
End of Year
(9)
6,777,719
Line
No.
47
48
26,553 160,144 - 5,984,820 49
110,486 (564,302) - 74,606,438 50
- 39,377 - 5,991,313 51
110,569 (3,016,322) - 54,163,777
27,195 (1,535,903) - 40,856,989 53
- 5,992 - 911,660 54
- 5,359 - 815,292 55
- 4,306 - 655,099
- - - - 57
274 803
-
(4,926,747)
(17,863)
-
-
190.763.107
2,945,504
58
59
60
22,237 - - 5,209,636 61
346,669 1 - 37,985,386 62
- - - - 63
222,396 - - 99,535,026 64
181,742 - - 65,798,625 65
97,072 (160) 31,714,875 66
175,387 1 - 50,862,518 67
78,398 - - 66,108,601 68
55,458 - - 47,451,194 69
146 8,529,784 152,725 21,174,718 70
- - - - 71
- - - - 72
45,835 2 - 14,393,968 73
- - - - 74
1,225,340 8,511,765 152,725 443.178.051 75
76
77
78
79
80
81
82
83
-
-
-
8
-
-
-
369,796
84
85
86
387 950 - . 3,297,953 87
120,963 3,713 - 1,863,523 88
375,449 19,117 - 5,216,350 89
- 107 - 136,793 90
32,735 404 (2,707) 922,869 91
47,632 226 - 303,883 92
1,268,573 15,162 - 13,348,205 93
25,064 (19,907) 14,737,123 94
- 3 - 11,608 95
1,870,803 19,783 (2,707) 40,208,103 96
- - - 97
- - - 98
1,870,803 19,783 (2,707) 40,208,103 99
4,556,394 4,778,077 150,018 1,079,511,442 100
- - - 101
102
- - - 103
4,556,394 4,778,077 150,018 1,079,511,442 104
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.206-207
Name of Respondent
Avista Corporation
This Report is:
[J An Original
A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year I Period of Report
End of 2012 / Q4
ELECTRIC OPERATING REVENUES - IDAHO
Instructions
1.Report below operating revenues attributable to the state of Idaho for each prescribed account in accordance with jurisdictional Results of
Operations. Report the portion of total operating revenue and megawatt hours which pertains to unbilled revenue and MWH pertaining unbilled
revenue in the lines provided.
2.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.
3.If increases or decreases from previous period (columns (c), (e), and (g)) are not derived from previously reported figures, explain any inconsistencies
in a footnote in the available space at the bottom of the page, or in a separate schedule. -
Line
No.
- -
Account
(a)
ELECTRIC OPERATING REVENUE
Current Year
(b)
Prior Year
(c)
_1 Sales of Electricity
_2 440 Residential Sales 102.933,167 107.877.413
_3 442 Commercial and Industrial Sales (3)
4 Small (or Commercial) 84,744,247 86,211 ,236
5 Large (or Industrial) 63,150,341 67,439,293
6 - 444 Public Street and Highway Lighting 2,440,129 2,376,108
7 - - 445 Other Sales to Public Authorities -
- - 446 Sales to Railroads and Railways -
448 Interdepartmental Sales 209,881 217,766
10 TOTAL Sales to Ultimate Customers (1) 253,477,765 264,121,816
11 447 Sales for Resale 51,786,744 41,020,894
12 TOTAL Sales of Electricity 305,264,509 305,142,710
13 449.1 (Less) Provision for Rate Refunds
14 TOTAL Revenues Net of Provision for Refunds 305,264,509 305,142,710
15 Other Operating Revenues
16 450 Forfeited Discounts
17 451 Miscellaneous Service Revenues 201,468 215,731
18 453 Sales of Water and Water Power 164,033 176,088
19 454 Rent from Electric Property 989,469 946,506
20 455 Interdepartmental Rents -
21 456 Other Electric Revenues 43,608,408 63,813,040
22 456.1 Revenues from Transmission of Electricity for Others 4,070,878 4,433,127
23 457.1 Regional Control Service Revenues -
24 4572 Miscellaneous Revenues -
25
26 TOTAL Other Operating Revenues 49,034,256 69,584,492
27 TOTAL Electric Operating Revenues 354,298,765 374,727,202
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.lD.300-301
Name of Respondent This Report is: Date of Report Year! Period of Report
Avista Corporation FTJ An Original mm/dd/yyyy End of 2012/ Q4
LII A Resubmission 4/12/2013
ELECTRIC OPERATING REVENUES - IDAHO
Instructions
4.Disclose amounts of $250,000 or greater in a footnote at the bottom of the page or in a separate schedule for accounts 451, 456, and 457.2.
5.Commercial and 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.)
6.See pages 108-109 in the FERC Form 1, Important Changes During Period, for important new territory added and important rate increases or
decreases.
7.Include unmetered sales. Provide details of such Sales in a footnote in the available space at the bottom of this page or in a separate schedule.
MEGAWATT HOURS SOLD AVG. NO. OF CUSTOMERS PER MONTH Line
Current Year Previous Year Current Year Previous Year No.
(d) (e) (f) (9)
1.165.138 1,198.793 106,528 105.840 _2_...
996,974 996,844 16,727 16,633 4
1,185,320 1,225,366 468 476
9,061 8,971 143 125 6
7
8
2,396 2,557 44 38
(2) 3,358,889 3,432,531 123,910 123,112 10
1,971 ,476 1,419,675 - J.L.
5,330,365 4,852,206 123,910 123,112 12
- - 13
5,330,365T 4,852,2061 123,910 123,112 14
(1)Includes $ (683,704) of unbilled revenues.
(2)Includes (6,475) MWH relating to unbilled revenues.
(3)Segregation of Commercial and Industrial made on basis of utilization of energy and not on size of account.
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61.405) E.ID.300-301
Name of Respondent
Avista Corporation
This Report is:
An Original
EJ A Resubmission
Date of Report
mm/dd/yyyy
4/12/2013
Year! Period of Report
End of 2012/ Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1.For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2.If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
1. POWER PRODUCTION EXPENSES
2 A. Steam Power Generation
3 lOperation
4 500 Operation Supervision and Engineering I 142,008 174,731
5 501 Fuel 9,784,981 10,863,947
6 502 Steam Expenses 1,402,073 1,495,883
7 503 Steam from Other Sources - -
8 504 (Less) Steam Transferred-Cr. - -
9 505 Electric Expenses 316,246 316,390
10 506 Miscellaneous Steam Power Expenses 828,089 833,611
11 507 Rents 7,669 11,262
12 509 Allowances - -
13 TOTAL Operation (Total of lines 4 through 12) 12,481,066 13,695,824
14 Maintenance
15 510 Maintenance Supervision and Engineering 173,851 204,091
16 511 Maintenance of Structures 212,438 251,492
17 512 Maintenance of Boiler Plant 1,695,417 2,116,527
18 513 Maintenance of Electric Plant 204,416 487,186
19 514 Maintenance of Miscellaneous Steam Plant 197,743 296,276
20 TOTAL Maintenance (Total of Lines 15 through 19) 2,483,865 3,355,572
21 TOTAL Steam Power Generation Expenses (Total lines 13 & 20) 14,964.931 17.051,396
22 B. Nuclear Power Generation I
23 Operation
24 517 Operation Supervision and Engineering I - I -
25 518 Fuel - -
26 519 Coolants and Water - -
27 520 Steam Expenses - -
28 521 Steam from Other Sources - -
29 522 (Less) Steam Transferred-Cr. -
30 523 Electric Expenses - -
31 524 Miscellaneous Nuclear Power Expenses - -
32 525 Rents - -
33 TOTAL Operation (Total of lines 24 through 32) - -
34 Maintenance
35 528 Maintenance Supervision and Engineering - - -
36 529 Maintenance of Structures - -
37 530 Maintenance of Reactor Plant Equipment - -
38 531 Maintenance of Electric Plant * -
39 532 Maintenance of Miscellaneous Nuclear Plant - -
40 TOTAL Maintenance (Total of lines 35 through 39) - -
41 TOTAL Nuclear Power Generation Expenses (Total lines 33 & 40)
42 1C. Hydraulic Power Generation
43 Operation
44 535 Operation Supervision and Engineering 840,868 895,522
45 536 Water for Power 411,845 388,681
46 537 Hydraulic Expenses 2,767,437 2,731,943
47 538 Electric Expenses 2,204,138 2,009,278
48 539 Miscellaneous Hydraulic Power Generation Expenses 217,048 244,582
49 540 Rents 2370,453 2,299,679
50 TOTAL Operation (Total of lines 44 through 49) 8,811,789 8,56685
51 Maintenance F- 52 541 Maintenance Supervision and Engineering 204,061 ' 193,655
53 542 Maintenance of Structures 212,090 146,256
54 543 Maintenance of Reservoirs, Dams, and Waterways 474,378 1,026,725
55 44 Maintenance of Electric Plant 981,380 814,630
56 545 Maintenance of Miscellaneous Hydraulic Plant 169,793 175,165
57 TOTAL Maintenance (Total of lines 53 through 57) 2,041,702 2,356,431
58 TOTAL Hydraulic Power Generation Expenses (Total of lines 50 & 58) 10853,491 10,926,116
59
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.320
Name of Respondent
Avista Corporation
This Report is:
An Original
A Resubmission
Date of Report
mm/cid/yyyy
4/12/2013
Year / Period of Report
End of 2012 I Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions
1.For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2.If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
60 D. Other Power Generation L
61 Operation
62 1 546 Operation Supervision and Engineering 451,338 499,959
63 547 Fuel 22,412,775 19,111,767
64 548 Generation Expenses 592,556 374,463
65 549 Miscellaneous Other Power Generation Expenses 216,690 198,473
66 550 Rents 17,723 (11,067)
67 TOTAL Operation (Total of lines 62 through 66) 23.691,082 20.173,595
68 Maintenance
69 551 Maintenance Supervision and Engineering 653,278 236,589
70 552 Maintenance of Structures 4,343 4,257
71 553 Maintenance of Generating and Electric Plant 2,696,525 514,713
72 554 Maintenance of Miscellaneous Other Power Generation Plant 56,407 53,795
73 TOTAL Maintenance (Total of lines 69 through 72) 3,410,553 809,354
74 TOTAL Other Power Generation Expenses i 27,101,635 20.982.949.
75 E. Other Power Supply Expenses
76 555 Purchased Power 95,516,653 85,280,960
77 556 System Control and Load Dispatching 302,502 248,402
78 ... 557 Other Expenses 1 50,030,662 86,945,012
79 TOTAL Other Power Supply Expenses (Total of lines 76 through 78) 145,849,817 172,474,374
80 TOTAL Power Production Expenses (Total of lines 21, 41, 59, 74, & 79) 198.769,874 221,434,835
81 12. TRANSMISSION EXPENSES
82 Operation
83 560 Operation Supervision and Engineering 757,626 745,700 I
84 561 Load Dispatching 753,317 775,159
85 561.1 Load Dispatch-Reliability - -
86 561.2 Load Dispatch-Monitor and Operation Transmission System - -
87 561.3 Load Dispatch-Transmission Service and Scheduling - -
88 1561.4 Scheduling, System Control and Dispatch Services - -
89 561.5 Reliability, Planning and Standards Development - -
90 561.6 Transmission Service Studies - -
91 561.7 Generation Interconnection Studies - -
92 561.8 Reliability, Planning and Standards Development Services - -
93 562 Station Expenses 146,840 110,714
94 563 Overhead Lines Expenses 164,079 180,118
95 564 Underground Lines Expenses - -
96 565 Transmission of Electricity by Others 6,141,310 6,079,392
97 566 Miscellaneous Transmission Expenses 625,372 583,739
98 567 Rents 40,562 44,337
99 TOTAL Operation (Total of lines 83 through 98) 8.629,106 8.519.159
100 Maintenance
101 568 Maintenance Supervision and Engineering 743,120 456,642
1021 569 Maintenance of Structures 156,654 148,318
103 569.1 Maintenance of Computer Hardware - -
104 569.2 Maintenance of Computer Software - -
105 569.3 Maintenance of Communication Equipment - -
106 569.4 Maintenance of Miscellaneous Regional Transmission Plant - -
107 570 Maintenance of Station Equipment 393,877 398,533
108 571 Maintenance of Overhead Lines 626,044 837,647
109 572 Maintenance of Underground Lines 2,931 774
110 573 Maintenance of Miscellaneous Transmission Plant 32,843 10,131
111 TOTAL Maintenance (Total of lines 101 through 110) 1,955,469 1,852,045
112 TOTAL Transmission Expenses (Total of lines 99 and 111) 10,584,575 1 10,371,204
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.321
Name of Respondent
Avista Corporation
This Report is:
[] An Original
E1 A Resubmission
Date of Report
mm/dd/yyyy
4112/2013
Year / Period of Report
End of 2012 / Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES -IDAHO
Instructions -
1. For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2. If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
113 3. REGIONAL MARKET EXPENSES
114 Operation I 115 575.1 Operation Supervision -
116 575.2 Day-Ahead and Real-Time Market Facilitation - -
117 575.3 Transmission Rights Market Facilitation - -
118 575.4 Capacity Market Facilitation - -
119 575.5 Ancillary Services Market Facilitation - -
120 575.6 Market Monitoring and Compliance - -
121 575.7 Market Facilitation, Monitoring, and Compliance Services - -
122 575.8 Rents - -
123 Total Operation (Total lines 115 through 122) - -
124 Maintenance
125 576.1 Maintenance of Structures and Improvements - -
126 576.2 Maintenance of Computer hardware - -
127 576.3 Maintenance of Computer Software - -
128 576.4 Maintenance of Communication Equipment - -
129 576.5 Maintenance of Miscellaneous Market Operation Plant - -
130 Total Maintenance (Total lines 125 through 129) - -
131 TOTAL Regional Market Expenses (Total lines 123 & 130)
132 4. DISTRIBUTION EXPENSES
133 Operation
134 580 Operation Supervision and Engineering 754,053 604,475
1351 581 Load Dispatching - -
136 582 Station Expenses 254,492 243,446
137 583 Overhead Line Expenses 894,238 424,700
138 584 Underground Line Expenses 447,249 100,057
139 585 Street Lighting and Signal System Expenses 138,544 195,612
140 586 Meter Expenses 511,301 305,766
141 587 Customer Installations Expenses 302,094 299,434
142 588 Miscellaneous Expenses 2,625,200 2,265,407
143 589 Rents 120,791 81,698
144 TOTAL Operation (Total of lines 134 through 143) I 6,047,962 4,520,595
145 Maintenance
146 590 Maintenance Supervision and Engineering I 597,528 400,047
147 591 Maintenance of Structures 203,685 93,155
148 592 Maintenance of Station Equipment 250,486 195,592
149 593 Maintenance of Overhead Lines 2,974,733 2,930,014
150 594 Maintenance of Underground Lines 368,272 336,670
151 595 Maintenance of Line Transformers 247,084 647,883
152 596 Maintenance of Street Lighting and Signal Systems 218,118 176,599
153 597 Maintenance of Meters 24,769 20,783
1541 598 Maintenance of Miscellaneous Distribution Plant 120,960 82,942
155 TOTAL Maintenance (Total lines 146 through 154) 5,005,6351 4,883 1685
156 TOTAL Distribution Expenses (Total of lines 144 and 155) I 11,053,597 9,404,280
157 5. CUSTOMER ACCOUNTS EXPENSES
158 - Operation
901 Supervision 198,872 217,546 I
902 Meter Reading Expenses 402,147 427,146
903 Customer Records and Collection Expenses 2,801,378 2,729,877
904 Uncollectable Accounts 732,862 904,089
905 Miscellaneous Customer Accounts Expenses 78,962 47,599
TOTAL Customer Accounts Expenses (Total of line 159 through 163) 4,214,221 4,326,257
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.322
Name of Respondent
Avista Corporation
This Report is:
{j] An Original
AResubmission
Date of Report
mm/dd/yyyy
4/1212013
Year / Period of Report
End of 2012 / Q4
ELECTRIC OPERATION AND MAINTENANCE EXPENSES - IDAHO
Instructions -
1.For each prescribed account below, report operation and maintenance expenses as allocated by the Results of Operations model to the state of
Idaho.
2.If the amount for previous year is not derived from previously reported figures, explain in a footnote.
Line
No.
-
Account
(a)
Amount for
Current Year
(b)
Amount for
Previous Year
(c)
165 6. CUSTOMER SERVICE AND INFORMATIONAL EXPENSES
166 Operation
1671 907 Supervision -
168 908 Customer Assistance Expenses 6,830,136 7,878,529
169 909 Informational and Instructional Expenses 390,120 308,833
170 910 Miscellaneous Customer Service and Informational Expenses 60,645 45,958
171 TOTAL Customer Service and Informational Expenses (Total lines 167 through 170) 7,280,901 8.233.320
172 7. SALES EXPENSES
173 Operation
1741 911 Supervision - -
175 912 Demonstrating and Selling Expenses 2,735 4,152
176 913 Advertising Expenses - -
177 916 Miscellaneous Sales Expenses - (22)
178 TOTAL Sales Expenses (Total of lines 174 through 177) 2,735 4,130
179 8. ADMINISTRATIVE AND GENERAL EXPENSES
180 Operation I. 181 920 Administrative and General Salaries 10,290,220 8,150,383
182 921 Office Supplies and Expenses 1,342,667 1,315,513
183 922 (Less) Administrative Expenses Transferred-Credit (21,716) (20,259)
184 923 Outside Services Employed 3,835,186 4,750,405
185 924 Property Insurance 437,430 403,349
186 925 Injuries and Damages 795,256 1,450,711
187 926 Employee Pensions and Benefits 426,919 391,971
188 927 Franchise Requirements 5,747 5,738
189 928 Regulatory Commission Expenses 2,101,988 2,058,197
190 929 (Less) Duplicate Charges-Cr. - -
191 930.1 General Advertising Expenses - -
192 930.2 Miscellaneous General Expenses 1,080,251 920,702
1931 931 Rents 339,611 287,291
194 TOTAL Operation (Total of lines 181 through 193) 20,633.559 19,714,001
_195 Maintenance
196 935 Maintenance of General Plant 2,760,676 2,854,898
197 TOTAL Administrative and General Expenses (Total of lines 194 and 196) 23,394,235 22,568,899
198 TOTAL Elec Op and Maint Expns (Total lines 80, 112, 131, 156, 164, 171, 178, 197) 255,300,138 276,342,925
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.323
Name of Respondent
Avista Corporation
This Report is:
[] An Original
A Resubmission
Date of Report
mm/ddlyyyy
4112/2013
Year / Period of Report
End of 2012 / Q4
TRANSMISSION LINE STATISTICS - IDAHO
Instructions
1.Report information concerning transmission lines physically located in the state of Idaho, including the cost of lines, and expenses for the
year. List each transmission line having nominal voltage of 132 kilovolts or greater.
Transmission lines below this voltage should be grouped and totals reported for each group.
2.Transmission lines include all lines covered by the definition of transmission system plant as given in the Uniform System of Accounts. Do not report
substation costs and expenses on this page.
3.Report data by individual lines for all voltages if so required by the State commission.
4.Exclude from this page any transmission lines for which plant costs are included in Account 121, Nonutility Property.
5.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 in the available space at the bottom of this page or in a separate
-
Line
No.
-
DESIGNATION
VOLTAGE (1(V)
Indicate where other than
60 cycle. 3 phase
Type of
Supporting
Structure
(e)
LENGTH (Pole Miles)
For underground lines, report circuit miles Number
of
Circuits
(h)
On Structure
of Line Designated
(1
On Structures
of Another Line
(g)
From
(a)
To
(b)
Operating
(c)
Designed
(d)
1 Group Sum -ll5kV 115.00 115.00 609.00
2
3 Beacon Cabinet Gorge Plant 230.00 230.00 Steel Pole 9.00
4 Beacon Cabinet Gorge Plant 230.00 230.00 Steel Pole 5.00 _2_
5 Beacon Cabinet Gorge Plant 230.00 230.00 H Type 53.00
6 Divide Creek Lolo Sub 230.00 230.00 Steel Tower
- Divide Creek Lolo Sub 230.00 230.00 H Type 43.00
oxon Plant Pine Creek Sub 230.00 230.00 H Type 15.00 - - oxon Plant Pine Creek Sub 230.00 230.00 Steel Pole 15.00 1 -
lu Cabinet Gorge Plant Noxon 230.00 230.00 H Type 2.00 -
11 Benewah Sw. Station Pine Creek Sub 230.00 230.00 Steel Tower 1 -
12 Benewah Sw. Station Pine Creek Sub 230.00 230.00 H Type 43.00
13 Beacon Sub Lolo Sub 230.00 230.00 H Type 81.00
14 North Lewiston Walla Walla 230.00 230.00 H Type 8.00
15 North Lewiston Shawnee 230.00 230.00 H Type 1.00
16 Hatwai N. Lewiston Sub 230.00 230.00 H Type 7.00
17
18
19
20
21
22
23
24
25
26
27
28
29
30
31
32
33
34
35
36
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.ID.422-423
Name of Respondent
Avlsta Corporation
This Report is:
FTJ An Original
A Resubmission
Date of Report
rnm/dd/yyyy
4/12/2013
Year I Period of Report
End of 2012/ Q4
TRANSMISSION LINE STATISTICS - IDAHO
Instructions
schedule, explain the basis of such occupancy and state whether these expenses with respect to such structures are included in the expenses reported
for the line designated.
7.Do not report the same transmission line structure twice. Report lower-voltage lines and higher-voltage lines as one line. Designate in a footnote if you
do not have include lower-voltage lines with higher-voltage lines. 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 (9).
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 details of such matters as percent ownership by respondent in the line, name of c-owner, basis of sharing expenses of the line, and and how
expenses borne by the respondent are accounts for, and accounts affected. Specify whether lessor, co-owner, or other party is an associated company.
9.Designate any transmission line leased to another company and give name of lessee, date and terms of lease, annual rent for year, and how determined.
Specify whether lessee is an associated company.
10.Base the plant cost figures called for in columns 0) through (I) on the book cost at end of year associated with the physical lines reported.
Size of
COST OF LINE
Include incolumn (I) land, land tights, and clearing right-of-way
EXPENSES, EXCEPT DEPRECIATION AND TAXES -
Line
Conductor
and Material
(I)
Land
U)
Construction
and Other Costs
(k)
Total Cost
Operation
Expenses
(m)
Maintenance
Expenses
(n)
Rents
(0)
Total
Expenses
(p)
No.
-
4,057,033 49,004,722 53,061,756 166,623 611,589 - 778,211 1
-2
1590ACSS - - - - - - - 3
1590AC55 - - - - - - - 4
1590 ACSR 1,005,364 20,272,624 21,277,987 225 63,790 - 64,015 5
1272McMAL - - - - - - -
1272McMAL 86.228 3,698,864 3,785,092 15,592 1,164 - 16,756 7
954 McMAL - - - - - - -
1272 ACSR 663,750 10,914,879 11,578,629 2,617 477,461 480,078 9
954McMAL 131,532 128,808 260,340 - 7,021 - 7,021 10
954 McMAL - - - - - - - IL
954McMAL 285,240 2,605,672 2,890,912 23,018 38,394 - 61,412 12
1272McMAL 363,604 6,989,980 7,353,584 - 4,277 - 4,277 13
1272McMAL 25,818 1,321,341 1,347,159 3,383 - - 3,383 14
1272ACSR 10,015 319,300 329,315 - - - - IL
1590 ACSR 106,581 2,722,818 2,829,399 997 202 - 1,199 16
- - 17
- 18
19
20
21
- - 22
23
24
25
26
27
28
- - 29
30
31
32
33
34
35
36
IDAHO STATE ELECTRIC ANNUAL REPORT (IC 61-405) E.lD.422-423
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